Accessories for HV and EHV Extruded Cables: Volume 2: Land and Submarine AC/DC Applications 3030804054, 9783030804053

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CIGRE Green Books

CIGRE Study Committee B1: Insulated Cables

Accessories for HV and EHV Extruded Cables Volume 2: Land and Submarine AC/DC Applications

CIGRE Green Books Series Editor CIGRE, International Council on Large Electric Systems (CIGRE), Paris, France

CIGRE presents their expertise in unique reference books on electrical power networks. These books are of a self-contained handbook character covering the entire knowledge of the subject within power engineering. The books are created by CIGRE experts within their study committees and are recognized by the engineering community as the top reference books in their fields.

Pierre Argaut Editor

Accessories for HV and EHV Extruded Cables Volume 2: Land and Submarine AC/DC Applications

With 305 Figures and 44 Tables

Editor Pierre Argaut Study Committee B1 CIGRE Unverre, France

ISSN 2367-2625 ISSN 2367-2633 (electronic) ISBN 978-3-030-80405-3 ISBN 978-3-030-80406-0 (eBook) ISBN 978-3-030-80407-7 (print and electronic bundle) https://doi.org/10.1007/978-3-030-80406-0 © Springer Nature Switzerland AG 2023 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG. The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

The editors are pleased to dedicate this Green Book to the memory of their friend Pierre Argaut, who was the father of this subject at CIGRE Insulated Cables Committee

Message from the President

CIGRE is the global expert community for electric power systems. It is a nonprofit organization based in Paris. It consists of members from over 100 countries representing 61 national committees. It functions as a virtual organization with members who are experts in their technical field, forming working groups dealing with issues facing the power-delivery industry. In 2019, 230 working groups including more than 3000 experts were working together to resolve the identified issues. The output of the working groups is technical brochures. There are over 700 technical brochures, which contain the combined knowledge and practice of engineering experts from all over the world. The brochures are practical in nature, enabling the engineer to plan, design, construct, operate, and maintain the power-delivery systems as required. CIGRE has over 10,000 reference papers and other documents supporting the brochures and dealing with other relevant technical matters. This Green Book on accessories for HV and EHV cable systems, compiled by Study Committee (SC) B1, “Insulated Cables,” provides the state of the art in the design and application of accessories in HV and EHV cable systems. The book comprises material from published technical peer-reviewed publications and technical experts in the field. CIGRE is a source of unbiased technical information. Engineers can refer this book without fear of favoring one supplier or country. It is a compilation of the combined expertise of many international experts. Like other CIGRE Green Books, this book contains input from several tens of experts, not just one or two. These international experts have provided technical information relevant to readers irrespective of where the readers reside. The views expressed and suggestions made are unbiased objective statements. These can be used as references for engineers to develop standards such as IEC Standards and guidelines within their organizations. This book is a reference book for academia, power transmission engineers, consultants, and users. For each of the chapters of this book, a tutorial has been prepared by the members of the working group who published the content of the chapter as a technical brochure or a report in Electra to disseminate this unbiased information. By collecting the knowledge and experience gained over time in the field of cable accessories and systems, this book not only explains the know-how but also the know-why.

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Message from the President

I would like to congratulate those involved from SC B1 who have compiled this book. Many of them have had to work in their spare time for hours to complete this task, for which they worked as volunteers. I specifically want to address on behalf of CIGRE all my thanks and gratitude to Pierre Argaut, past chair of Study Committee B1, for leading this formidable task. I would recommend this book in forming the basis for underground transmission system design activities now and in the future. December 2020

Michel Augonnet Michel Augonnet is a graduate electrical engineer from Centrale Supelec (1973). Forty-two years of his career were spent with Alstom Group in the field of power generation, transmission, and distribution, with a focus on electrical systems, control and instrumentation, project management, and sales. Michel is currently the president of SuperGrid Institute (an electrical research and testing laboratory in Lyon, France); a board member of AEG Power Systems, Mastergrid SA; and an alternate board director for ACTOM (PTY) South Africa. Michel is president of CIGRE, and outgoing treasurer and former president of the French NC.

Message from the Chairman of the Technical Council of CIGRE

This Green Book on accessories for HV and EHV cable systems aims at describing the cumulated experience gained by CIGRE experts in the domain of accessories for transmission underground systems. It is well known that the reliability and performance of a cable circuit is dependent in equal measures on the design of the cable and accessories and on the skill and experience of the person who is assembling the accessory. The cable insulation is manufactured in the factory under controlled process conditions using selected materials of high quality. It is equally important that the same quality measures are employed for the manufacture of the accessories in the factory and for their assembly on site onto the specially prepared cable. It is essential to select the design of accessory to be exactly compatible with the particular cable type and the particular service application. Compatibility should be validated by electrical type approval tests and be supported by prequalification tests and satisfactory service experience. In particular, the performance of the accessory is dependent on the quality, skill, and training of the jointing personnel and on the use of the specialized tools required for a particular accessory. The chapters of this book form the basis of the information that is needed by the manufacturer and installer of the cable and accessories. For many applications, the cable manufacturer also manufactures, supplies, and installs the accessories as part of the complete cable circuit. In the event that the user purchases the accessories separately from the cable, the Green Book will also provide the basis of the information (including tests reports) that should be required to obtain the appropriate performance of the system, both in the case of a new underground line of “the Power System of the Future” or in the upgrading process of an existing line “to make the best use of the existing power system.” This Green Book has been authored by leading industry, research, and academic professionals, acting as members of working groups within Study Committee B1, who published technical brochures and prepared tutorials, providing all stakeholders with high quality and unbiased information.

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Message from the Chairman of the Technical Council of CIGRE

I take the opportunity to acknowledge the editor, the chapters’ authors, and all the numerous contributors in working bodies for this contribution from which the entire global power systems will benefit. Also, I especially acknowledge the leading role of Study Committee B1 – Marco Marelli – on the realization of this Green Book. Marcio Szechtman CIGRE Technical Council Chair Marcio Szechtman graduated and received his MSc degree in electrical engineering from the University of Sao Paulo, Brazil, in 1971 and 1976, respectively. He joined CIGRE in 1981 and became the Study Committee Chair of B4 (DC Systems and Power Electronics) between 2002 and 2008. He received the CIGRE Medal in 2014 and was elected as Technical Council Chair in 2018. Marcio has a long career in R&D Power Systems Centers, and since April 2019, he was appointed as Eletrobras Chief Transmission Officer.

Message from the Secretary General

In 2014, I had the pleasure to comment on the launching of a new CIGRE publication collection in an introductory message about the first CIGRE Green Book, the one on overhead lines, the second one being on accessories for HV extruded cables. The idea to valorize the collective work of the study committees accumulated over many decades, by putting together all the technical brochures of a given field in a single book, was first proposed by Dr. Konstantin Papailiou to the Technical Committee (now Council) in 2011. In 2015, cooperation with Springer allowed CIGRE to publish the Green Book on overhead lines again as a “Major Reference Work” distributed through the vast network of this well-known international publisher. In 2016, the collection was enriched with a new category of Green Books, the CIGRE “Compact Series,” to satisfy the needs of the study committees when they want to publish shorter, concise volumes. The first CIGRE compact book was prepared by Study Committee D2, under the title Utility Communication Networks and Services. The concept of the CIGRE Green Books series has continued to evolve, with the introduction of a third subcategory to the series, the “CIGRE Green Book Technical Brochures” (GBTB). CIGRE has published more than 720 technical brochures since 1969, and it is interesting to note that in the first one, on tele-protection, the first reference was a Springer publication of 1963. A CIGRE Technical Brochure produced by a CIGRE working group, following specific Terms of Reference, is published by the CIGRE Central Office and is available from the CIGRE online library, e-cigre, one of the most comprehensive, accessible databases of relevant technical literature on power engineering. Between 40 and 50 new technical brochures are published yearly, and these brochures are announced in Electra, CIGRE’s bimonthly journal, and are available for downloading from e-cigre. In the future, the Technical Council of CIGRE may decide to publish a technical brochure as a Green Book in addition to the traditional CIGRE Technical Brochure. The motivation of the Technical Council to make such a decision is to disseminate the related information beyond the CIGRE community, through the Springer network. All CIGRE Green Books are available from e-cigre in electronic format free of charge for the co-authors of the book. CIGRE plans to co-publish new Green Books xi

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Message from the Secretary General

edited by the different study committees, and the series will grow progressively at a pace of about one or two volumes per year. This new Green Book, a Major Reference Work prepared by Study Committee B1 on Insulated Cables, is an updated version of the Green Book published in 2014, and is the seventh of this subcategory. This new edition comprises two additional chapters related to the most recent work of SC B1. A second volume of the book will address accessories in submarine and DC applications. Some chapters will also cover distribution cable systems. It is important to know that each of the chapters of this book is the topic of a dedicated tutorial prepared by the members of the WG who published the content of the chapter as a Technical Brochure or an Electra Report. I want to congratulate all the authors, contributors, and reviewers of this book, which gives the reader a clear, comprehensive, and unbiased vision of the past, recent, and future developments of accessories for HV and EHV cable systems. Secretary General

Philippe Adam Philippe Adam was appointed secretary general of CIGRE in March 2014. Graduate of the École Centrale de Paris, he began his career in EDF in 1980 as a research engineer in the field of HVDC and was involved in the studies and tests of outstanding projects like the Cross Channel 2000 MW link and the first multiterminal DC link between Sardinia, Corsica, and Italy. After this pioneering period, he managed the team of engineers in charge of HVDC and FACTS studies of the R&D division of EDF. In this period, his CIGRE membership as a working group expert and then as a working group convener in Study Committee 14 was a genuine support to his professional activities. Then, Philippe held several management positions in the EDF Generation and Transmission division in the fields of substation engineering, network planning, transmission asset management, and international consulting until 2000. When RTE, the French TSO, was created in 2000, he was appointed manager of the Financial and Management Control Department, in order to install this corporate function and the necessary tools. In 2004, Philippe contributed to the creation of RTE international activities, first as project director and then deputy head of the International Relations Department. From 2011 to

Message from the Secretary General

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2014, he was the strategy director of infrastructures and technologies of the Medgrid industrial initiative. In the meantime, between 2002 and 2012, he served CIGRE as the technical committee secretary and as the secretary and treasurer of the French National Committee from 2009 to 2014. Philippe was appointed secretary general of CIGRE in March 2014.

Preface

Dear Reader, This CIGRE Reference Book on Accessories for HV and EHV Extruded Cables is the first in a series of Reference Books regarding High and Extra High Voltages Cable Systems. The book compiles the results of the work achieved by several Working Groups and Task Forces of CIGRE Study Committee 21/B1, and Joint Working Groups and Joint Task Forces with other Study Committees. Many experts from Study Committees 21/B1 (Insulated Cables), 15/D1 (Materials and Emerging Test Techniques), 33/ B3 (Substations), C3 (System Environmental Performance), and C4 (System Technical Performance) have participated in this work in the last 30 years in order to offer comprehensive, continuous, and consistent outputs. I would like to express my deepest thanks to these WG members who made all this possible. This publication is divided into two Volumes covering land and submarine applications, HVAC and HVDC systems, transitions from lapped cable systems to extruded cable systems, from OHL to UG cables, and from cables to substations. It provides the reader with recommendations for testing, installation, maintenance, remaining life management. This first Volume of the Book, dedicated to components, provides information regarding Recommendations and Guidelines from CIGRE for Design, Workmanship and Testing of Accessories for AC extruded cables. This second Volume is dedicated to Land and Submarine AC/DC Applications. Chapter 1 provides the basics for the various topics to be addressed in the process of selection of the accessories. The content of Chap. 1 is mainly coming from TB 250, published in 2004 by CIGRE WG B1.19 convened by Pierre Argaut (France). When necessary, reference is made to other publications of CIGRE. Chapter 2 is part of the Output of TB 801 published in 2020 by CIGRE WG B1.44 convened by Unnur Stella Gudmundsdottir from Denmark “Guidelines for Safe Work on Cable Systems Under Induced Voltages or Currents.” Some appendices of TB 801 have not been reproduced in the chapter for lack of space. Chapter 3 reproduces the Technical Brochure 490 “Recommendations for Testing of Long AC Submarine Cables with Extruded Insulation for System Voltage

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Preface

Above 30 (36) to 500 (550) kV” Published in 2012 by CIGRE WG B1.27 convened by Anders Gustafsson from Sweden. Chapter 4 provides basics on Installation of land extruded cable systems. The content of the chapter is mainly coming from TB 194 “Construction, Laying and Installation Techniques for Extruded and Self Contained Fluid Filles Cable Systems” published in 2001 by CIGRE WG 21.17 convened by Yves Maugain from France. Chapter 5 reproduces TB 623 published in 2015 by CIGRE WG B1.43, convened by Marc Jeroense from Sweden “Recommendations for Mechanical Testing of Submarine Cables.” It is divided into two principal parts: one part describes the general background of mechanical handling of cables throughout the life cycle and the general aspects of testing in relation to handling; the other part describes the tests that are recommended or may be performed. Chapter 6 reproduces TB 496 “Recommendations for Testing DC Extruded Cable Systems for Power Transmission at a Rated Voltage up to 500 kV” published in 2012 by CIGRE WG B1.32 convened by Bjørn Sanden from Norway. Chapter 7 reproduces TB 622 “Recommendations for Testing DC Transition Joints for Power Transmission at a Rated Voltage up to 500 kV” published in 2015 by CIGRE WG B1.42 convened by Gunnar Evenset from Norway. Chapter 8 reproduces TB 797 “Sheath Bonding Systems of AC Transmission Cables: Design, Testing, and Maintenance” published in 2020 by CIGRE WG B1.50 convened by Tiebin Zhao from the USA. Chapter 9 reproduces the part dedicated to extruded cables of the TB 825 “Maintenance of HV Cable Systems” published in 2021 by CIGRE WG B1.60 convened by Bart Mampaey from Belgium. As past chairman of SCB1, as well as being member of some of these Working Groups, I have reviewed these chapters and can confirm that all of them give unbiased information, which will be useful for those involved in new cable systems projects. This volume is the output of the work of numerous Working Groups of worldwide experts. Once again, I would like to express my deepest thanks to all of them and my sincere congratulations to the Conveners of these Working Groups and to the Management of SC B1. After Pierre Argaut passed away, Yves Maugain kindly accepted to finish the edition of this book.

Contents

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Accessories in Underground Cable Systems and in Transitions from Overhead to Underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pierre Argaut

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Safe Work Under Induced Voltages or Currents . . . . . . . . . . . . . . . Unnur Stella Gudmundsdottir

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Long AC Extruded Submarine Cables: Recommendations for Testing Cables and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Anders Gustafsson

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Basics on Construction and Installation Methods Yves Maugain

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Recommendations for Mechanical Testing of Submarine Cables (and Their Accessories) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Marc Jeroense

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Recommendations for Testing DC Extruded Cable Systems for Power Transmission at a Rated Voltage up to 500 kV . . . . . . . . . . . Bjørn Sanden

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Recommendations for Testing DC Transition Joints for Power Transmission at a Rated Voltage up to 500 kV . . . . . . . . . . . . . . . . Gunnar Evenset

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Sheath Bonding Equipment for AC Transmission Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tiebin Zhao

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Maintenance and Remaining Life . . . . . . . . . . . . . . . . . . . . . . . . . . . Bart Mampaey

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About the Editor

Pierre Argaut graduated as an electrical engineer from Institut d’Electrotechnique de Grenoble in 1971. He joined Delle-Alsthom (HV Switchgear Manufacturer) in November 1971 and took several positions before heading the R&D Department on GIS. After being operations manager of the South European Pipeline, he joined SILEC in 1988 and retired at the end of 2010. His last position with SILEC was senior vice president. In Study Committee B1 (Insulated Cables), Pierre has held position of working group member (21.09;21.06;21.07;21.17), French SC member, working group convener (B1.19), special reporter (2010), advisory group convener (Tutorial Advisory Group till 2010), and chairman of SC B1 from August 2010 to August 2016. He received the Technical Committee Award in 2000, the Distinguished Member Award in 2002, and the title of Honorary Member of CIGRE in 2016. Pierre was in the final stage of publication of this volume when he passed away peacefully in May 2022. He is missed by all his colleagues. Pierre will be remembered for his contributions, but mostly for his brilliant intelligence, his natural gift of teacher to colleagues and friends, his vitality, his permanent attentive ear for everybody, his desire to be always inclusive.

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Contributors

Pierre Argaut Study Committee B1, CIGRE, Unverre, France Gunnar Evenset Power Cable Consulting AS, Halden, Norway Unnur Stella Gudmundsdottir Orsted, Fredericia, Denmark Anders Gustafsson Borealis, Energy, Stenungsund, Sweden Marc Jeroense Marcable Consulting, Karlskrona, Sweden Bart Mampaey ELIA, Brussels, Belgium Yves Maugain CIGRE, Paris, France Bjørn Sanden Nexans, Oslo, Norway Tiebin Zhao EPRI, Charlotte, NC, USA

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Accessories in Underground Cable Systems and in Transitions from Overhead to Underground Pierre Argaut

Contents 1.1 Introduction to the Chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.2 Content of the Chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.3 General Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 System Requirements and Basic Concepts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1 Basics on Transmission Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1.1 Functions of the Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1.2 Types of Substations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1.3 Main Cable Circuit Configurations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1.4 The Overhead to Underground Transition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1.5 System Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.2 Parameters Determined by the Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.2.1 Main Equipment Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.2.2 Fault Clearance Times . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Design and Construction Issues Relating to Underground Section . . . . . . . . . . . . . . . . . . . . . . . 1.3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.1 Electrical Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.2 Thermal Dimensioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.3 Economical Optimization of Conductor Area . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.4 Main Insulation Coordination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.5 Choice of Grounding Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.6 Protection and Reclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1.7 Magnetic Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.2 Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 Laying Techniques and Installation Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1 Laying Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.1 Trenches (Direct Burial) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.2 Ducts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Pierre Argaut: deceased. P. Argaut (*) Study Committee B1, CIGRE, Unverre, France © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_1

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P. Argaut

1.4.1.3 Troughs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.4 Tunnels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.5 Microtunnels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.6 Shafts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.7 Bridges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.8 Mechanical Laying . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.9 Horizontal Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.10 Pipe Jacking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.11 Embedding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.1.12 Use of Existing Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4.2 Installation Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5 Accessories Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.1 Quality Assurance Approval for Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.2 Quality Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.3 Training of Personnel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.4 Assembly Instructions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.5 Special Assembly Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.6 Preparation of the Assembly Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.6.1 Joint Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.6.2 Termination Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6 Design and Construction Issues Relating to Overhead to Underground Transition . . . . . . 1.6.1 Options for Transition Overhead/Underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6.2 Transition on Towers/Poles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6.3 Transition Compounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7 Transition Compound . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1 Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1.1 Extent of the Transition Compound . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1.2 Connection Scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1.3 Fault Current Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1.4 Neutral Point Earthing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.1.5 Protection in General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.2 Site Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.2.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.2.2 Environmental Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.2.3 Technical Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.3 Overvoltage and Insulation Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.4 Current Rating and Overcurrents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.5 Electrical Clearances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.6 Direct Lightning Stroke Shielding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.7 Earthing for Personnel Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.8 Corona and Radio Interference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.9 Acoustic Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.10 Water Contamination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11 Mechanical Forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11.1 Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11.2 Wind Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11.3 Earthquake . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11.4 Short-Circuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.11.5 Combinations of Forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.12 Civil Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.12.1 Supporting Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.12.2 Foundations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

23 23 24 24 24 25 25 25 26 26 26 26 27 27 27 28 28 28 29 29 31 31 34 38 38 39 39 40 43 43 43 43 43 44 48 50 50 51 51 52 54 54 54 55 55 55 55 56 56 56 56 57

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Accessories in Underground Cable Systems and in Transitions from Overhead. . .

1.7.12.3 Site Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.12.4 Fencing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.12.5 Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.13 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.14 Transition Compound Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7.15 Energy Efficiency in Transition Compounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.8 Commissioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.9 Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1.1

Introduction to the Chapter

1.1.1

Background

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57 57 57 58 58 59 59 61 62

In many occasions in the previous chapters and especially of Volume 1 ▶ Chap. 2 “Guide to the Selection of Accessories,” the reader has been advised to consider the compatibility of the Accessory with the Cable (Sect. 2.2), and the compatibility of the Accessory Performance with that of the Cable System (Sect. 2.3). The goal of this chapter is to provide basics for the various topics to be addressed in the process of selection of the accessories. The Content of this chapter is mainly coming from TB 250 (CIGRE WG B1.19 2004), published in 2004 by WG B1.19 convened by Pierre Argaut (France). When necessary, reference is made to other publications of CIGRE. ▶ Chapter 4 will cover with more details the various installation techniques and provide information regarding the way to handle thermomechanical forces in the case of large cross-section cable systems.

1.1.2

Content of the Chapter

The chapter is divided into 10 sections: After a short introduction in section one, the second section covers system requirements and basic concepts, including network considerations and the particular needs of transition equipment. Section 1.3 considers the design and construction issues relating to the undergrounding of a line and describes the methodology that will lead to the final selection of components and techniques. Section 1.4 briefly introduces laying techniques and cable installation methods. These items will be covered in more details in ▶ Chap. 4. Section 1.5 reminds the basics of accessory installation to be considered in the selection of the accessories in an undergrounding project. Section 1.6 is dedicated to the design of the aboveground equipment relating to the overhead to underground transition in some circuit configurations. Two options are proposed and one is the use of a Transition Compound.

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Section 1.7 focuses on Transition Compounds. This includes discussion of the technical and environmental factors that must be considered when selecting the most suitable site for locating transition equipment. This section also details the criteria that are applied to select layout and to determine the primary and secondary equipment required. Section 1.8 provides guidance on commissioning. Section 1.9 deals with operation. References are listed at the end of this chapter.

1.1.3

General Process

The design of an underground cable circuit depends on many factors including: – Route availability: it must be possible to route the underground circuit. – The impact of other services which may conflict with the cable route either now or in the future must be considered. – Route topography: if the terrain is very uneven or has lots of hills it may be difficult to route the circuit. – Urbanization: if the line is to be routed through an urban area future building or road developments may impact on the circuit. – Flooding: this may undermine the installed cable circuit. – Conductor size: the size of the conductor is dependent on the current to be carried and on the increase of temperature of the surroundings allowed by regulations. Of course, the size of the conductor also has an impact on the weight and size of the cable drum being delivered – currently the maximum conductor size used is 2500 sq. mm and drum lengths are typically 600–1000 m long: jointing of cable lengths is then required every 600–1000 m. Provision for jointing bays (civil works as an example) must be done. Everyone can understand the interest to have longer cable lengths, to reduce the cost of civil works and jointing. The sizing of the conductor and the overall design of the cable are therefore very important. – Soil thermal conductivity: the conductor size has an impact on the losses or heat, which is created by the current flowing through the cable when it is delivering power. In the case of a cable installed in the ground this heat must travel through the ground to be liberated into the air. So, the ground thermal conductivity and temperature also have an impact on the cable sizing. CIGRE WG B1.41 has published Technical Brochure 714 on this topic (CIGRE WG B1.41 2017). – Cable pulling: the route and drum lengths and route topography must be such that the cables can be pulled into the selected installation arrangement: trench, duct, tunnel, etc. – Electrostatic effects: underground cables have no electrostatic effects initiated by the cable as the electric field is contained inside the cable. – Electromagnetic field: in this case the current sets up a magnetic field which must be considered during the design of the underground circuit. In some countries there are specific limits – for example, set by the International Committee for Non-Ionising Radiation Protection (ICNIRP). It should be noted that underground

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cables have higher electromagnetic fields than overhead lines at close separations, but the fields fall off more rapidly with distance. This topic is addressed in TB 373 published by CIGRE WG 204 (CIGRE WG C4.204 2009) and TB 559 published by CIGRE WG B1.23 (CIGRE WG B1.23 2013). The electromagnetic field is often higher at joint bays or manholes since the distance between phases is higher (for thermal reasons and to ease the work on joints). ▶ Chapter 4 of this book, which partly covers EMF, will be completed by some relevant information from TB 373 and 559 on mitigation measures at joint bays. – Since all these factors can vary along the route of a projected cable link, the Study Area will have to be divided in several sections as detailed hereafter (Fig. 1.12 and ▶ Chap. 4). The Study Area is the area where the impacts are assessed. It includes the location of the two ends of the projected underground cable system, and the likely extent of the physical and visual influence of the potential underground cable route corridors between these two points. The criteria to define this area are: • • • • • •

Physical Natural (flora, fauna. . .) Land use: agricultural, urban or peri-urban Technical Cultural heritage Administrative boundaries

Then the area is delimited by administrative boundaries where the local authorities are identified.

1.2

System Requirements and Basic Concepts

1.2.1

Basics on Transmission Network

The transmission network has two main constituent elements: (a) Circuits (lines, cables, etc.) that enable power transmission. (b) Substations that enable the interconnection of these circuits and the transformation between networks of different voltages.

1.2.1.1 Functions of the Network The transmission network performs three different functions: (a) The transmission of electric power from generating stations (or other networks) to load centres. (b) The interconnection function, which improves security of supply and allows a reduction in generation costs.

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(c) The supply function which consists of supplying the electric power to sub-transmission or distribution transformers and in some cases to customers directly connected to the transmission network.

1.2.1.2 Types of Substations These three functions of the transmission network are fulfilled through different types of substations listed below: (a) Substations attached to Power Stations (b) Interconnection substations (c) Step-down (EHV/HV, EHV/MV, HV/MV) substations A single substation may perform more than one of these functions.

1.2.1.3 Main Cable Circuit Configurations Various configurations such as single circuit, double circuit, and triple circuit lines with different arrangements of transformer and generator connections are in use. Many types of connections comprising overhead lines, underground cables, or both are in use today. The length of such transmission lines and cables can vary significantly. In order to provide for high transmission loads, some circuits can consist of more than one cable per phase. Previous work (CIGRE JWG 21/33 2001) has identified a number of commonly used cable configurations. These are given below and are representative of the most common practical situations. Note that in the subsequent figures each cable can consist of several cable systems. 1.2.1.3.1 Meshed Underground Network Some parts of a HV network may be entirely underground as is often found in large towns where urbanization limits the construction of overhead lines. Cables connect the busbars in the system, as indicated in Fig. 1.1, by means of outdoor terminations (Fig. 1.2), indoor terminations, or GIS terminations (Fig. 1.3). Fig. 1.1 Underground cable system in a meshed network

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7

Fig. 1.2 Outdoor termination connected to busbar

Fig. 1.3 GIS termination connected to a GIS busbar

1.2.1.3.2 Siphon A siphon (Fig. 1.4) is an underground cable connected between two overhead lines. It is assumed that no switching device is located between line and cable. This configuration allows a HV link to pass through areas too wide for an overhead line span such as rivers or small lakes. The configuration may also permit the transmission line to pass through or near a protected site or an urbanized area. Transition between overhead and underground sections is made either by means of simple

Fig. 1.4 Siphon, an underground cable between two overhead lines

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Fig. 1.5 Transition OHL to UGC on a Lattice Tower

terminations installed on poles or towers (Fig. 1.5) or in a special fenced area called a “Transition Compound” (Fig. 1.10) and Chapter 1.7.

1.2.1.3.3 Substation Entrance An underground cable is often used as the interface between an overhead line and a substation (Fig. 1.6), especially when it is a gas-insulated substation. This

Fig. 1.6 Underground entry to a substation

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9

configuration allows the design of more compact stations, particularly when there are a large number of incoming overhead lines. Transition from OHL to UGC is made with outdoor terminations (on a pole, tower, or in a transition compound) and transition from UGC to Substation is made by outdoor termination, indoor termination, or GIS termination.

1.2.1.3.4 Power Generator Output An underground cable may be used to carry power from an inaccessible generator to a busbar, as shown in Fig. 1.4. In many hydro power stations the generator is located inside a mountain. In order to save space the generator is connected directly to the step-up transformer, without use of a circuit breaker. The secondary side of the transformer is connected to an outdoor substation via cable, which may have a length up to several kilometers. The substation (air insulated or gas insulated) is connected to one or more overhead lines (Fig. 1.7).

1.2.1.3.5 Power or Auxiliary Transformer Supply In this configuration, a cable is connected between a high power busbar and the power transformer or the auxiliary transformer of a power unit (see Figs. 1.8 and 1.9). The cable is usually short.

Fig. 1.7 Power generator output

Fig. 1.8 Power or auxiliary transformer supply

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Fig. 1.9 Connection of a cable to a transformer

1.2.1.4 The Overhead to Underground Transition In at least two of the above configurations in transmission systems and in many other configurations in distribution systems, there is need for a transition between overhead and underground sections. For lower voltages, generally up to 145 kV, this is achieved by means of terminations installed on poles or towers. Many examples can be found at 170 kV and 245 kV levels with the use of light composite insulators (Fig. 1.5). In other cases, and especially for very high voltages, the weight of the equipment, and the electrical clearances required may be such that the equipment cannot easily be located on towers. In these circumstances, the transition is made in special fenced area called a transition compound. This is normally located close to a tower or includes a tower. The transition compound often resembles a small substation, but without switchgear and transformers. Example of transition compound is shown in Fig. 1.10. The technical and environmental issues relating to transition compounds are considered in Sect. 1.7 of this chapter.

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Fig. 1.10 Example of a transition compound (United Kingdom)

1.2.1.5 System Requirements The design of a circuit depends on the functions it has to fulfill. The system planning requirements define these functions and enable the parameters that have to be complied with, to be determined. Some of these parameters are common for all the circuits that perform similar functions whereas others are completely specific to each circuit. Standardised parameters are established jointly by system planners and transmission departments by means of system studies, and economic considerations. Particular economic benefits are derived from specifying the technical requirements to allow the use of standardised HV equipment with identical characteristics (such as short circuit rating, maximum current carrying capacity, insulation level). Cables are generally dimensioned for the expected transmission capacity.

1.2.2

Parameters Determined by the Network

System planners seek to optimize the parameters that apply to the complete transmission system. They proceed to network studies that involve mainly insulation co-ordination, transient stability, short-circuit level, and load flow.

1.2.2.1 Main Equipment Parameters When a utility determines a standardisation policy and the development of technical requirements, the main characteristics of the primary equipment have to be specified by the asset managers in close consultation with designers.

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The following parameters may be defined: (a) The short circuit current ratings of the equipment, including the supporting structures. (b) The maximum load current passing through the components (which is related to the maximum current carrying capacity of the lines and underground cables) in normal operation and in overload conditions.

1.2.2.2 Fault Clearance Times In order to comply with the requirements of the network (system stability), or the specifications of particular utilities, specified fault clearance times must not be exceeded. Fault clearance times and the policy on reclosing may influence the choice of components, the size of the metallic screen of cables and installation design (depth of burial), and also the dimensioning of the earthing grid and the mechanical strength of the equipment.

1.3

Design and Construction Issues Relating to Underground Section

1.3.1

Introduction

Taking into account the data from both operating and environmental sides, a preliminary route and cable design are selected. Then, in the progress of the study, several technical issues will be faced before reaching the final selection of cable and accessories design and laying technique(s). Main technical aspects which will be examined in this process are as follows.

1.3.1.1 Electrical Characteristics This very important question has been studied in detail in Report 21-13 prepared for CIGRE Session 1986 by CIGRE WG 21-13 (CIGRE WG 21.13 1986). The following lines will just remind main issues. A transmission line may be modeled with discrete line elements in a π-link, or by using the exact solutions from the wave equations. In Fig. 1.11, an equivalent diagram of a line element is shown. The series impedance consists of the series resistance and inductive reactance (X ¼ ωL for pure sine waves), while the shunt admittance consists of capacitive susceptance (B ¼ ωC for pure sine waves) and the shunt conductance, which for cables is represented by the dielectric losses (Pdiel ¼ U2  G ¼ U2  ωC  tan δ). The dielectric loss factor, tan δ, is normally about 0.0002 for XLPE cables.

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Accessories in Underground Cable Systems and in Transitions from Overhead. . .

I1

13

I2 L

V1

R

G

C

V2

Fig. 1.11 Equivalent diagram of a line element

The line elements are: • Series resistance R. The resistance may consist of conductor resistance or in case of underground cables the conductor resistance corrected to take into account the screen/sheath ohmic losses, depending upon screen bonding technique. • Series inductance L. An element that stores and releases magnetic energy with changing current. • Shunt conductance G. Represents the heating effect from induced polarization of the insulation material in case of cables and stray currents in case of Over Head Lines (OHL). • Shunt capacitance C. An element that stores and releases electrical energy with changing voltage. Different transmission systems have different magnitudes of the line elements. There are, for example, large differences between cables and OHL. The series inductance is about 2–3 times larger for OHL compared to cables (depending on the geometrical configuration) but the shunt capacitance is 10–20 times less (depending on material properties and geometrical configuration). Each of these impedances must be taken into account when performing detailed cable system design. This topic is fully covered in TB 531 (CIGRE WG B1.30 2013).

1.3.1.2 Thermal Dimensioning Cables are classified by their type of insulation system. The thermal capability of the material defines the maximum allowed conductor temperature in steady-state operation and short circuit condition (about 1 second duration). These temperatures are normally used as basis for thermal dimensioning of the cables for a given application.

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In operation, there are thermal losses in the various cable layers/components. Each one of these heat sources contribute to rise the temperature of layer in the cable relative the surrounding. At steady-state conditions the heat losses equal the heat transfer to the surrounding. The current that gives a temperature rise of the conductor to its maximum allowed steady state is called the nominal current. A cable system, especially with buried cables, is a slow thermal system that from a stable low load condition may carry a load during a limited period with a current higher than the nominal current without exceeding the thermal design criteria/maximum conductor temperature. Except for the dielectric losses in the insulation, which are voltage dependent, the losses are current dependent heat losses in the conductor and all metallic layers as metallic sheath, reinforcement tapes, and armour on submarine cables. The AC-resistance of the conductor is higher than the DC-resistance due to effects that cause uneven current distribution over the conductor cross section. For large conductors (usually larger than 800 to 1200 mm2) segmented conductors might be cost efficient. Induced currents in metallic sheaths, reinforcement tapes, and armor cause losses that may be reduced by various means as: • Laying configuration as trefoil configuration which in turn gives higher residual thermal influence • Choice of metallic sheaths technology • Transposition of the cores along the circuit length • Bonding techniques as single point bonding, mid-point bonding, or cross bonding of metallic sheaths. Maximum allowed sheath voltages limit the length of the cable sections between bonding points. This topic is fully covered in TB 640 issued by WG B1.35 (CIGRE WG B1.35 2015) and in TB 880 issued by WG B1.56 (CIGRE WG B1.56 2022). WG B1.72 will soon publish reports covering practical examples in complex configurations.

1.3.1.3 Economical Optimization of Conductor Area 1.3.1.3.1 Short Circuit Characteristics The cross-sectional area of the cable conductor and shield/sheath must be selected to carry fault current until the fault is cleared by a circuit breaker, without exceeding the short-circuit temperature rating of the insulation and/or outer serving. The maximum temperature for XLPE insulation is normally 250  C. A commonly used formula to calculate the adiabatic temperature, that is, no heat is dissipated during the fault, is: I sh A

2

t ¼ k  ln

θ2 þ θ θ1 þ θ

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Accessories in Underground Cable Systems and in Transitions from Overhead. . .

15

Ish ¼ maximum short circuit current [A]. k ¼ constant for conductor or shield/sheath material, dimensionless. A ¼ conductor or shield/sheath cross-sectional area. θ ¼ temperature of inferred zero resistance. θ1 ¼ temperature of conductor or shield/sheath before short-circuit. θ2 ¼ temperature of conductor or shield/sheath after short-circuit. For transmission cables, the time t, is normally assumed to be the backup breaker fault clearing time, which should be less than 1 s. If other clearing times are present the following formula can be used: I I t ¼ p1 t t ¼ short circuit duration [s]. I1 ¼ short circuit current during 1 s It ¼ short circuit current during t seconds. Auto re-closing of OHL in meshed networks is common. Auto re-closing is performed by the primary protection, which means that tripping time of the fault is short. Short time over-current design of OHL and cables are done for the backup protection. Total short time over-current at auto re-closing of the OHL against a persisting failure is normally lower than the short time over-current when backup protection clears the fault. If a cable constitutes a section in an OHL, for example a siphon, the cable must be designed for faults in the OHL and in the cable. Power Frequency Faults in the OHL The cable section in the OHL transmits fault current to the fault in the OHL. Conductor and screen of the cable must be designed for the largest fault currents that may appear or the established fault currents specified for the network. The design of the cable does not differ from design of cables in pure cable networks. Power Frequency Faults in the Cable For single point bonding technique earth fault in the cable means that the fault current in the screen is in the same order as the fault current in the conductor. The cable is at least grounded at one end. If the resistance of the grounding is high, the voltage of the local earth grid is high. If the cable is long, the voltage between the screen and the ambient may be high far from the earth grid. This voltage may be too high for the oversheath of the cable. To limit the voltage over the oversheath a bare groundwire must be installed in parallel with the cable. The groundwire is an extension of the earth grid to which cable screens are connected. In other words, as a conclusion, there is no thermal overheating of the conductor and/or screen if the duration for the backup protection is the base for the short time

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current design. The total fault clearing time, including auto-reclosing, of the main protection is lower than the total fault clearing time for the backup protection. Re-closing of OHL including cable sections is therefore possible from a technical point of view if the described protection philosophy is used. Other considerations, such as personal safety (for example tunnels) and an immediate signal for the location of the fault, may in some cases imply a separate protection of the cable, however. In CIGRE technical brochure 194 “Construction, laying and installation techniques for extruded and self contained fluid filled cable systems,” other issues are also discussed (CIGRE WG 21.17 2001). The standard reference for calculating allowable short circuit currents in cable networks is IEC 60949 [10].

1.3.1.4 Main Insulation Coordination This topic is addressed in TB 189 for AC Cable Systems. Further work is in progress for DC Cable systems (CIGRE JWG 21/33 2001). 1.3.1.5 Choice of Grounding Technique In order to achieve in an economic way the current rating of the cable system, it is current practice to use special bonding techniques for the cable system. If this results in a better transmission capacity for the underground cable, or in a much cheaper design for a cable assigned to a given transmission capacity, permanent and transient voltages can appear in the sheath and at the metallic (or conducting) parts at the ends of the cable sections. The grounding technique has to be designed taking into account the voltage withstand level of cables and accessories, and voltage stresses during normal operation and during a failure on the overhead part or on the underground part of the line. This design is subdued to: • Electric induction on the sheath, during normal operation and even in case of a fault. • Specific rules depending on each country, relative to the maximum induced voltage allowed on the sheath, next to any point where someone can touch (wiping bell near transition compounds towers for example); the voltage allowed varies between 35 to 400 Volt. (See ▶ Chap. 2 of this book which deals with safe work under induced voltages and currents.) • The resistivity of the ground to eliminate the voltage in the sheath. • The resistivity of the towers next to both ends of the underground line. • If it exists groundwires on the overhead line. • The value of the asymmetric factor taken into account during a fault at power frequency. • Surge arrestors specifications. This topic is covered in TB 283 [10] and in TB 797 (CIGRE WG B1.50 2020) reproduced in ▶ Chap. 2 of this book.

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1.3.1.6 Protection and Reclosure Short-circuit characteristics have been mentioned in 1.3.1.3.1. The topic of protection and reclosure is partly covered in TB 680 published by WG B1.47 (CIGRE WG B1.47 2017) in the following terms: Protection systems of HV and EHV grids are often based on the application of overhead lines. The introduction of cable connections or hybrid connections can be a reason for an adapted protection philosophy. Most matters caused by cables can be solved by modern protection devices and these digital or numeric protections devices can deal with different types of connections. Additional high voltage equipment related to cables, like series and shunt reactors must also be protected. This can be done within the protection zone of the connection or by a separate differential protection system. Auto re-closure is typically designed for overhead lines, where many faults have a temporary character. This is not the case with underground cables where a fault in the insulation cannot heal itself. For full cable connections, auto re-closure is not applicable, but for hybrid connections a consideration must be made. There are different possible policies which each have their own advantages and disadvantages. From an insulation coordination point, surge arresters to protect the cable insulation are not always necessary, although they can still be a worthwhile complement in hybrid lines, where reflections and earth potential rise (EPR) can occur at transition points. (See TB 347 from TF B1.26)(CIGRE TF B1.26 2008). a) Power Cable Protection and protection of Hybrid links Line distance protection is widely used in High Voltage transmission grids, because it can operate without telecommunication channels between both ends of the line. Distance protection relays are based on a linear increase of the impedance over the line length. If the impedance declines below an adjusted minimum, then the fault is within the protect zone and the line will be switched off. Distance protection can be used for cables too, but underground cables have different electrical properties. Cables can have different return paths, depending on the type of fault (core – sheath or core – sheath – earth), place of the fault (distance to the cross-bonding or grounding point) and the way the metal sheath is earthed (single point, solid bonded, cross bonded or other). Due to this a deviation of the linear impedance curve can occur, which can cause inaccuracies in determining the limit of the protected zone. This is especially so if there is insufficient distinction in the last 20 percent of the impedance curve, because in this range it is important to determine the set-point for the first protection zone. On long lengths of cross-bonded cable systems the deviation of the linear curve is less, due to the decrease of the relative impedance of each section. Detailed studies are necessary to find out the right setting for the distance relays. Capacitive currents are sometimes neglected in case of overhead lines, but they must be considered for long length cable systems.

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Differential protection is normally the first choice for a reliability protection system with cable connections and a line distance protection can function as a backup system. In the case of hybrid links (partial undergrounding) different impedances are connected in series. On one hand this makes it harder to determine the minimum impedance setting for the distance protection, but on the other hand the longer the total connection the less the influence of the cable section on the total impedance. Modern digital distance relays are a big step forward; they can also deal with multiple cable sections in a hybrid line. If protection by line distance relays only is uncertain, differential protection can always be applied. For full cable connections, this is the normal choice, but in case of partial undergrounding of existing lines telecommunication channels are not always available. To summarise, cable systems can be protected by distance protection. For longer cable lengths, it is easier to reach an acceptable level of accuracy than for (very) short lengths. The application of differential protection over full cable connection is preferable, but dependency on telecommunications must be managed. b) Auto re-closure and lock-out system On overhead lines, auto re-closure after a line fault is widely used. The aim of this system is to optimize the availability of circuits and by doing so increasing the security of supply. In case of a hybrid connection there are a few strategies for the use of auto-reclose. They are: • A lock-out system for faults in the cable section, • unchanged auto re-closure system, • no auto re-close. Each of these strategies has it owns advantages and disadvantages and all are applied worldwide. A lock-out system has the best performance as the auto re-closure is still intact but will not operate when there is a cable failure. With a fault in the cable there is no additional damage and no further voltage dips. However, to detect this fault, measurement and telecommunication channels to the substations are necessary. A lock-out system consists of differential protection over the cable section and therefore current transformers are needed. A Lock-out system becomes more difficult in case of numerous cable sections in the overhead line. The installation of a lock-out system can be a considerable disadvantage for cost and space reasons. If slip-on current transformers are used at the ends of the cable system a failure of the cable sealing ends will still operate the auto re-closure. In some circumstances, auto re-close on hybrid connections is acceptable. This will be a part of a risk evaluation. The benefit is that it keeps the system simple.

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Issues that need to be considered in this case are the expected number of faults in the cable section (which are far lower than in the overhead line section), the additional cable damage, the risk of fire or other injuries and additional voltage dips. For hybrid lines with relatively short overhead line sections the removal of the auto re-closure could also be considered. To get a decision many factors play a role, like the failure rate (protection level against lightning strikes), the amount of redundancy in the meshed grid and safety aspects (especially in highly urbanised areas). Although removing of auto re-close is not very advisable, in the Netherlands this is partial done by 150 kV hybrid lines in a highly-meshed grid, with no significant decline of security of supply, observed over a period of more than 15 years. New technical developments in protection equipment can improve the ability to distinguish between the overhead line section and the cable section. Then auto re-closure only takes place when the fault is in the overhead line section. Auto re-closure can cause overvoltage’s, especially at the transitions points where overhead lines are connected to underground cable. Careful examination of this phenomenon is necessary to determine the cable design, including any surge arresters at the transition compounds.

1.3.1.7 Magnetic Fields This topic is introduced in ▶ Chap. 4 of this book and fully covered in TB 373 (CIGRE WG C4.204 2009) and 559 (CIGRE WG B1.23 2013). As said before, induced voltages are generated by these magnetic fields. Safe work under induced voltages and currents is the topic of ▶ Chap. 2 of this book.

1.3.2

Methodology

When an engineer is at the beginning of a new project, the problem is always: how could it be managed in order to be the most effective on the technical, economic, and environmental points of view? The following chart (Fig. 1.12) proposed in Technical Brochure 250 prepared by WG B1.19 (CIGRE WG B1.19 2004) will help the engineer in the management of his project. In an organization accustomed with the underground cable system project management, it is clear that some stages may be jumped over. It can be seen that the exercise is very much an integrated process with the impact of the various stages being considered and steps taken to modify previous and subsequent stages of the process to achieve an optimized end result. The reader will find more details in ▶ Chap. 4 and a case study prepared by WG 21.17 (CIGRE WG 21.17 2001) will be proposed.

20 Fig. 1.12 Methodology in project management

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1.4

21

Laying Techniques and Installation Methods

Laying and installation techniques have been reviewed in detail by CIGRE WG 21-17 and are described in Technical Brochure 194 (CIGRE WG 21.17 2001) partly reproduced in ▶ Chap. 4 of this book. This Technical Brochure describes a comprehensive state of art shared by the technical cable systems community, established starting from two questionnaires sent to Utilities and Manufacturers. Two papers propose a summary of the main results obtained from the completed questionnaires at the time of the survey. Twelve existing construction techniques are reported and explained in Technical Brochure 194 (CIGRE WG 21.17 2001). They are shortly recalled hereunder. When appropriate, some information will be given regarding jointing issues.

1.4.1

Laying Techniques

The following 12 techniques are now used: trenches, ducts, troughs, tunnels, microtunnels, shafts, bridges, mechanical laying, horizontal drilling, pipe jacking, embedding, and use of existing structures. Backfill For the first three methods, the cables, ducts, and troughs are usually placed on a bed of materials suitable for protecting them against sharp rocks that can often be found at the bottom of the trench. The material is mainly sand. The trench within which cables, ducts, and troughs are installed, is backfilled with materials which may be the original excavated soil, concrete, sand, or any other suitable materials. In certain countries, special backfill is used in order to improve the thermal environment assisting the removal of the heat released by the power cables (hence increasing their transmission capacity). The material is mainly sand or special backfill. The reader is invited to consult TB 714 for more information (CIGRE WG B1.41 2017).

1.4.1.1 Trenches (Direct Burial) This method consists of digging a trench and directly placing the cables in the trench. The cables can be placed in trefoil configuration or in flat configuration. The joints will be directly buried with or without fixing equipment. In Fig. 1.13, 400 kV joints are fixed on a concrete basement. The cover over the cables is generally 1 m or more. The most common installation techniques used are the trefoil formation up to 170 kV and flat formation above 170 kV (Fig. 1.14).

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Fig. 1.13 400 kV Joints ready for direct burial in a rural area

Fig. 1.14 Joint Bay in a directly buried cable system

1.4.1.2 Ducts This laying method consists of placing ducts or pipes in trenches (by horizontal drilling or other methods) and then pulling the cables into them. These ducts or pipes can be of PVC, concrete, polyethylene (PE), steel, or fiberreinforced epoxy (FRE), but according to the replies mainly PVC or PE ducts are used. The ducts or pipes can be filled with air, bentonite, mortar, sand, or water. Usually only one cable is placed in each duct and the ducts are air filled or filled with bentonite or other material (Fig. 1.15).

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Fig. 1.15 Examples of manhole in a duct and manhole installation

1.4.1.3 Troughs The troughs usually consist of prefabricated concrete segments, usually placed in a trench, after which the cables are laid in the trough. The troughs are generally filled with sand and usually three cables are laid in each trough. Excavated soil is usually used as backfill around the troughs. In this installation design, joints are generally placed in a joint chamber filled with sand. 1.4.1.4 Tunnels Tunnel boring machines can bore large diameter tunnels (in excess of 2 m). Tunnels, which can be built for a variety of purposes other than cable laying, have practically no technical limit regarding tunnel length. The positioning of the cables in the tunnel (on steel trays, in the concrete, . . .) will depend on what the tunnel was built for (metro, etc.). It is common for tunnels to share with other utilities such as gas or water (see TB 403 published by WG B1.08 (CIGRE WG B1.08 2010)). Generally, joints in tunnel are staggered along the cable route (Fig. 1.16). One tunnel out of four is equipped with a cooling system. Fig. 1.16 Example of laying in tunnel with joints

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1.4.1.5 Microtunnels This technique presented in TB 770 issued by WG B1.48 (CIGRE WG B1.48 2019) consists of thrust-jacking through the soil prefabricated pipe sections having the exact diameter of the final pipe, from a pit equipped with a thrust-jacking station. Tunnel boring is always mechanical: a remote-controlled microtunnel boring machine is placed at the head of the pipes, and makes it possible to build smalldiameter horizontal tunnels (diameters 0.3 m to 1.2 m). The section lengths do not generally exceed 150 m. If the drilling length is too long, it can be divided into two with a central work shaft and two lateral exit shafts. Microtunnels are generally dedicated to only one user. The cables are generally pulled in ducts that are installed in the microtunnel when it is finished. If required, the ducts and the space between ducts and microtunnel can then be filled. 1.4.1.6 Shafts These are circular or rectangular excavations that are made vertically or at an angle less than 30 to vertical. Such shafts are dug, for example when constructing a microtunnel, for the start and end stations of the microtunnel. The cables in these shafts are usually placed on a steel structure, the length of the shaft defining the type of system (rigid or flexible systems – See Sect. 1.4.2 of this book). The most common installation techniques used are a flexible design with cables installed in trefoil formation. Generally, there is no joint in the shaft. 1.4.1.7 Bridges At special or delicate crossings, this method makes it possible to avoid having to use costly and sometimes technically difficult methods. The cables are placed either inside the bridge or on the outside of it, mainly depending on the type of structure of the bridge. See TB 403 (CIGRE WG B1.08 2010). The most common installation techniques used are a flexible design with cables installed in trefoil formation. Generally, there is no joint in a bridge. For long bridges, special space is often allocated for joints installation (Fig. 1.17). Fig. 1.17 Example of installation of joints in a (long) bridge

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1.4.1.8 Mechanical Laying There are three ways of organizing the mechanical laying site: – Mechanically excavated narrow trench, and separate laying of the cables: laying and backfilling is done by traditional methods after the trench has been mechanically excavated. – Trench excavation and cable laying both mechanical: trench excavation, cable laying, and sometimes the backfilling are performed by a machine. – Trench excavation, cable laying, backfilling all continuous and mechanized: with this method, trench excavation, cable laying, and sometimes trench backfilling can all be done simultaneously in a continuous process over the full length of a homogeneous portion of the link (the joints have to be prepared beforehand). This technique is only used for voltages under 170 kV. The cables are usually buried directly in trefoil formation with a minimum cover of 1 meter. Joints are most of the time directly buried.

1.4.1.9 Horizontal Drilling This technique is directly derived from the directional drilling techniques used in the oil industry (CIGRE WG B1.48 2019). It is used for crossing of major obstacles (e.g., rivers, railway tracks, motorways, . . .) or longitudinal drilling. The method involves three phases: – Drilling of the pilot hole – Back reaming – Placing of the final pipe(s) The drilling mud (generally bentonite) washes cuttings to the surface, reduces friction, stabilizes the bore hole, and cools the drill head. Generally, the mud is screened and recycled for re-use in a closed circuit. The nature of the soil is essential when considering using this technique. After the pipes are installed, the cables are pulled into them. Three PE ducts are usually pulled in one drill with one cable per duct. These are air filled or filled with bentonite.

1.4.1.10Pipe Jacking This technique consists of thrusting through the soil portions of prefabricated pipes that have the required final cross section (CIGRE WG B1.48 2019). A work pit or shaft is excavated to install the jacking equipment and the pipe portion to be jacked. As the pipe jacking progresses the earth works are done, either manually or mechanically, according to the requested diameter. The first portion of pipe may be provided with a cutting curb made of steel which attacks the soil in place and protects the personnel who excavate the soil.

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Pipe jacking can be done for pipe diameters comprised between 0.4 m and 3.2 m. This technique is advantageous for lengths exceeding 100 m and it is possible to do pipe jacking work over great lengths of 500 or 600 m. Pipes are usually of concrete or steel type. The cables are placed as in tunnels or microtunnels, depending on the diameter. If required, the ducts and the space between ducts and pipe can be filled.

1.4.1.11Embedding This technique consists of excavating the river bed from a barge or an amphibious vehicle, and embedding the pipes or cables themselves in the river bed. When crossing navigable waterways, this method implies that river traffic be stopped or deviated during the excavation and laying operations. 1.4.1.12Use of Existing Structures It may sometimes be decided to use existing (or ancient disused) structures (racks, trays, . . .) or disused utility ducts (water, gas, pipeline, . . .) to place the cables in them. In that case it is essential to thoroughly inspect these structures and completely clean them, especially in the case of ducts. This technique was studied in depth by CIGRE WG B1.08 that published TB 403 in 2010.

1.4.2

Installation Techniques

Rigid or Flexible Systems When certain methods are used (tunnels, microtunnels, bridges, pipe jacking), the question may arise whether to install the cables in rigid or flexible systems. In a rigid system the cable is held in such a manner that virtually no lateral movement occurs and the cable absorbs the thermal expansion by developing a high internal compressive force. In a flexible system the cable is held in such a manner that the expansion movement is accommodated by lateral deflection of the cable. The design of the cable system ensures that the movement does not cause excessive strain in any of the cable components which could result in a short fatigue life. These options will be presented in detail in ▶ Chap. 4 of the book.

1.5

Accessories Installation

Assembly of the accessories onto cable with extruded insulation is the most vulnerable part of a project involving the manufacture and installation of a new cable circuit. Accessories and cables are manufactured and tested under controlled factory

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conditions, whereas the in-service performance of the accessory is dependent upon the training, skill, and reliability of the personnel, who are often required to work under adverse site conditions. (See Chapters 2, 5, and 6 of Volume 1 and ▶ Chap. 2 of this volume.) For many project applications one company will manufacture the cable and accessories and undertake to complete the installation of the circuit. In other applications the installer may complete the circuit using cable and accessories supplied by different manufacturers. In some applications the installer may only assemble the accessories. For each application the requirements of the quality assurance (QA) system are equally rigorous.

1.5.1

Quality Assurance Approval for Installation

The user should ensure that the installer provides evidence of an approved quality assurance system for installation to an internationally recognized standard.

1.5.2

Quality Plan

The installer is required to produce a Quality Plan for each project, which includes the project time schedule together with the requirements for suitably qualified personnel, training, on-site storage of components and accessories, tools, testing equipment, constructing materials, assembly instructions, preparation of the jointing environment, and records of the assembly work. It is important that the records of assembly are traceable to the location of each accessory in the cable circuit. If purchasing separately, the user is advised to ensure that, for the purposes of traceability, the quality systems of the cable manufacturer, accessory manufacturer, and installer are compatible.

1.5.3

Training of Personnel

When selecting the designs of accessories, the user should ensure that training courses are available for the jointing and supervisory personnel. It is strongly advised that personnel receive training on the particular designs of accessories and cable. Examples of the elements of a training course for assembly personnel are: • General training at specific system voltages with the standard range of accessories required by the user • Repeat training after a defined period for those personnel who have completed general training • Specified training on a new accessory or cable design for those personnel who have completed general training.

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At the end of the training course the proficiency of the assembly personnel is normally assessed, for example, by a verbal or written examination, by a practical test, and preferably by performing on the assembled accessories an electrical partial discharge test and voltage withstand test. Proficiency is recognized at the completion of training by the issue of a certificate, which should be checked by the user as part of the quality plan for a specific project. In many instances a kit of general jointing tools and a set of general assembly instructions are also issued to the personnel following satisfactory completion of training.

1.5.4

Assembly Instructions

The accessory manufacturer is required to supply a complete set of assembly instructions together with drawings of the particular accessory. The instructions should also include lists of the specified assembly tools, the specified consumable materials, and the health and safety precautions. Recommendations for the preparation of the assembly environment should also be given. It is important that the user studies the instructions before work begins to ensure that the workplace is correctly prepared and that all the tools and consumable materials are available.

1.5.5

Special Assembly Tools

Most designs of accessories, particularly those operating at higher system voltages, require special tools which are purchased or hired from the accessory manufacturer. The user should ensure that full instructions are provided and that the personnel are trained in their use. These tools may take the form, for example, of (a) hydraulic compression presses or welding equipment for connecting the conductors, (b) cutting equipment to remove the insulation screen and to shape the cable insulation (c) assembly machines which stretch and position pre-molded elastomeric components, (d) taping machines that apply tape, and (e) heated mold tools and mobile extruders for field molded joints.

1.5.6

Preparation of the Assembly Environment

It is strongly recommended that the assembly area for both joints and terminations to be enclosed within a tent or temporary building, with the objective of providing a clean and dry environment (Figs. 1.17 and 1.18). The enclosure should be (a) well lit to facilitate accurate preparation of the cable insulation, (b) provided with a sound floor, and (c) lined with sealed materials to facilitate cleanliness. In extremes of

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Fig. 1.18 Temporary enclosure for jointing

climate it is good practice to provide control of temperature and humidity to ensure (a) consistent performance of the personnel and (b) consistent properties of the polymeric materials.

1.5.6.1 Joint Assembly • An appropriately sized joint bay or chamber. • The provision of a temporary and/or permanent support for the completed joint. • Heating and/or air cooling system. • Power supply for straightening cable ends. 1.5.6.2 Termination Assembly • A temporary weatherproof structure during assembly (Fig. 1.19). • A permanent support structure (Figs. 1.20 and 1.21). • Means of lifting the cable and insulator into position (Figs. 1.21 and 1.22).

30 Fig. 1.19 Temporary enclosure for terminating

Fig. 1.20 Terminations under installation

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Fig. 1.21 Lifting of a 400 kV termination prepared at ground level with a crane

Fig. 1.22 Installation in a 400 kV transition compound

1.6

Design and Construction Issues Relating to Overhead to Underground Transition

1.6.1

Options for Transition Overhead/Underground

Any underground line is connected to the network by means of terminations. In general cases, the terminations are located within substations. In the case of siphon (Fig. 1.2) or underground entrance to a substation (Fig. 1.3), transition equipment is needed, in accordance with all technical issues listed in previous sections. For example, they must allow:

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• Easy access to connections of the main circuit for operational changes in circuit configuration. • Easy access to phase protecting devices: surge arresters, etc. • Easy access to shield protective devices and bonding connections (SVL). • Easy access to diagnostics sensors or pressure and level monitoring devices. • Easy access to optical fibers for thermal monitoring. Power supply may also be needed. In addition, protection of people, protection from vandalism, visual impact may dictate or influence the choice of the transition solution between: • Transition towers or poles where all the equipment is located on platforms installed on the lattice tower (Fig. 1.23) or pole (Fig. 1.24) or beside them. • Transition compound, which is a fenced area, similar to a small substation which could eventually be remote operated (Figs. 1.25, 1.26 and 1.27). In some countries, regulations require to prevent access to cable terminations from shooting and the only acceptable solution would be transition compounds protected by concrete walls.

Fig. 1.23 Transition tower

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Fig. 1.24 Transition pole

Fig. 1.25 400 kV transition compound

33

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Fig. 1.26 120 kV transition compound

Fig. 1.27 400 kV transition compound surrounded by concrete walls

In other cases, polymeric or composite terminations may offer better safety and environmental performances and make transition towers and poles acceptable (Fig. 1.28). When choosing a solution, due to the permanent presence of tension, special care must be given to the authorization of people in charge of maintenance of the various equipment involved.

1.6.2

Transition on Towers/Poles

The design of transition towers or poles has to take into consideration the method of installation of the cable on the structure (Figs. 1.29 and 1.30).

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Accessories in Underground Cable Systems and in Transitions from Overhead. . .

Fig. 1.28 100 kV transition structure with synthetic terminations Fig. 1.29 Transition on a platform installed on a lattice tower (without fence)

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Fig. 1.30 Transition on a pole

Some of the available options are: • Cable installed inside the structure. This method gives a better mechanical protection for the cables from external aggression, but it requires special considerations for the installation of cables. A special foundation design is required for the pole. Good coordination between the cable installation and the tower installation is also very important in that case (Fig. 1.31). • Cables installed outside the tower in conduits: The conduits give a suitable mechanical protection and facilitate the cable installation. Cable clamping at the top end of the conduit must be designed carefully and may limit the height of the termination in the tower. • Cables clamped on the outside of the pole: in this option, the cables are clamped on the outside of the pole. For mechanical protection of the cables, cover plates are usually installed, especially in the lower part of the structure that can be accessible to public (Fig. 1.32). • Cables installed on a platform next to the foot of the tower: the platform may be integrated to the tower design (Fig. 1.29) or may have independent foundations. Of course, this is also possible in a transition compound (Fig. 1.33).

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Fig. 1.31 Transition on a pole: cables are installed inside the pole

Fig. 1.32 Cables installed outside the pole and protected at the lower part of the structure

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Fig. 1.33 Transition tower with equipment on a platform in a transition compound

1.6.3

Transition Compounds

Following Sect. 1.7 covers the selection of transition compound type and the detailed design of an insulated transition compound. The three component parts of the transition compound are defined as follows: (a) Primary System The primary system comprises all equipment which, in whole or in part, is in service at the highest operating voltage of the system. (b) Secondary System The secondary system comprises all equipment which is used for the control (local and remote), protection, monitoring automation, and measurement of the primary system. (c) Auxiliary System Auxiliary systems are those which are required to enable the primary and secondary equipment to operate. Details are provided in CIGRE Technical Brochure 197 Design guidelines for power station auxiliaries and distribution systems issued by WG 23.04 in 2002.

1.7

Transition Compound

As said before, a transition compound is similar to a small substation with a limited number of equipment, mainly terminations, surge arresters, and occasionally disconnectors, depending on the connection scheme (see Fig. 1.34). The following sections highlight the most important considerations for a transition compound but do not go into details about the specifications of each type of equipment. More considerations about

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Fig. 1.34 EHV transition compound

the design of substations can be found in CIGRE Technical Brochure 161 “General Guidelines for the Design of Outdoor Substations” (CIGRE WG 23.03 2000). Due to the many points Substations and Transition Compounds have in common, this paragraph refers to and summarize the main aspects highlighted by the Technical Brochure 161.

1.7.1

Planning

This section will give information helpful for planning the transition compound and for defining the general scope equipment, depending on the system requirements. The options of extending or uprating the existing equipment and/or lines should have already been evaluated. The starting point for a transition compound design procedure is as follows: (a) The need for the new equipment has been approved. (b) The range of its duties, loading, and general location has been determined.

1.7.1.1 Extent of the Transition Compound The area available for the compound, the connection schemes and the possibility of extension as well as compensating equipment options should be selected for the needs of the future. It should be noted that the lifetime of the compound may be between 30 and 50 years. It is very important to allow sufficient space for extension. Sophisticated network planning is needed to estimate the necessary reserve space. The space required depends essentially on the function of the compound. Extension work such as building, reconstruction, or extension may be rather difficult and expensive if there has been no previous planning for them.

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It is important to define the size of the compound at the final stage of development. The initial peak load of a cable system is dependent upon a number of factors such as the network configuration, standby philosophy, and rate of load growth. The outgoing line corridors should be planned so that there are a minimum number of crossings between different circuits.

1.7.1.2 Connection Scheme The selection of a connection scheme and its possible extensions for a particular arrangement is an important initial step of the design. Among the matters that affect this decision are operational flexibility, reliability and availability, and costs. 1.7.1.2.1 Operational Flexibility In order to reduce the risk of disconnection of generators or consumers, due to faults in system components, circuits between two substations are often doubled so that power transfer is shared, for instance between two separate overhead/underground line circuits. Consequently, in the transition compounds, one can find doubled transition equipment. 1.7.1.2.2 Reliability and Availability The failure rates of the equipment and the choice of the transition compound scheme have a considerable effect on reliability and availability, that is, forced outages and planned shutdowns. Calculations can give only approximate results. This is because the available failure statistics is always based on an older generation of apparatus and the occurrence of a severe outage during the lifetime of the transition compound is likely to be quite small. However, for a comparison of different schemes, reliability calculation is a valuable instrument for the transition compound engineer, which can assist in the choice of scheme and layout. Recent publications have indicated that not only the primary equipment but also the secondary equipment, for example, the location and number of instrument transformers and the arrangement of the secondary circuits can have a great influence on the overall reliability. Special attention has to be paid to the secondary wiring and cabling. The proposed scheme and layout must allow simple and efficient performance of normal operational life, changes of connections, and planned outage for maintenance or extension. 1.7.1.2.3 Service Continuity When choosing a specific arrangement one of the prime considerations should be the effect of a loss due to fault conditions or for maintenance. Such effects may include loss of generating plant, loss of transmission, and loss of supply to customers. In all the examples given, if line or transformer faults or maintenance (of, e.g., line disconnector, instrument transformers, or line traps) are considered, continuity cannot be maintained on the affected circuits. Apart from these limitations, a measure of service continuity can be maintained.

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An assessment of the continuity that can be obtained has been categorized as follows: Categories Definitions and Examples The transition compound may be classified in three categories, according to availability in default conditions (Tables 1.2 and 1.3): • Category I: the circuit is fully redundant (in N-1, no overload is produced) • Category II: the circuit is not fully redundant (in N-1, one overload is acceptable, at least temporarily, or the circuit is derated). Accessories must accept the overload. • Category III: the circuit is not redundant (in N-1, the connection is lost) The following table shows the analysis of reliability for typical configurations for a single circuit transition compound. It should be noted that the duration of service interruption will depend upon the time required to transfer the load to the spare cables (Table 1.1). The two first categories may be further analyzed in sub-categories (Tables 1.2 and 1.3) to observe the conditions of the exploitation in N-2 configuration: – Category I: a second fault • induce no overload (Ia) or • induce an acceptable overload (Ib) or • induce the loss (Ic) Table 1.1 Categories for single circuit configurations (availability of link in “N-1” configuration) Configuration (1 circuit) 1 cable per phase

2 cables per phase

0 spare 1 spare 2 spares 0 spare 1 spare 2 spares

State in N-1 Loss No overload No overload Overload or derated No overload No overload

Categories III I I II I I

Table 1.2 Sub-categories for single circuit configurations (availability of link in “N-2” configuration) Configuration (1 circuit) 1 cable per 0 spare phase 1 spare 2 spares 2 cables per 0 spare phase 1 spare 2 spares

State in N-1 Loss

State in N-2 Loss

Sub-categories III

No overload No overload Overload or derated No overload No overload

Loss No overload Overload or derated or loss Overload or derated No overload

Ic Ia IIa or IIb Ib Ia

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Table 1.3 Summary regarding service continuity

N-1configuration

Healthy state

Categories I

Description No overload

II

Overload or derated

III

Loss

N-2 configuration Sub categories a b c a

b

Description No overload Acceptable overload or derating Loss Acceptable overload or derating but no loss Loss

– Category II: a second fault • induce an acceptable overload (IIa) or • induce the loss (IIb) As seen in the examples for single circuit transition compounds, determination of the reliability to achieve can assist significantly in the choice of layout for the transition compound. Similar analysis can be done for double circuit layouts, or any other conditions, for example, when the spare cables are of different size (ampacity) than the cable from the links. 1.7.1.2.4 Choice of Connection Arrangements In addition to the functions of a transition compound, choice of switching arrangements may be influenced by: (a) The level of skill and experience of operating staff (b) The future growth and development of the supply system (c) Economy in the early stages of development (d) The ease of facilitating future extensions (e) Duplication of circuits to give alternative supply routes (f) Amount of power to be transmitted (g) Strategic importance of the circuits (h) The service continuity of other significant parts of the network (i) The reliability, both of the transition compound as a whole and the individual components within the transition compound (including accessories) (j) The standardization policy of the organization (k) Maintenance requirements and techniques (l) National regulations (e.g., whether or not it is permissible to operate a disconnector remotely to change a particular switching arrangement without visual confirmation)

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1.7.1.3 Fault Current Levels Fault current dimensioning depends on the neighboring network. System planning usually defines the following fault current ratings for a new equipment: (a) Maximum three-phase effective short-circuit current for the lines and the transition compound for the foreseeable future (b) Duration of the effective short-circuit current (c) Peak short-circuit current (d) Maximum earth fault current and corresponding time (e) Maximum current through the neutral point of transformers (f) Minimum short-circuit current (for protection) (g) Minimum earth fault current (for protection)

1.7.1.4 Neutral Point Earthing The electrical networks may be: (a) Effectively earthed (earth fault factor up to 1.4) (b) Non-effectively earthed (earth fault factor, e.g., 1.7). For example, resistance earthed or resonant earthed (c) Isolated In the first case earth current may be 60. . .120% of the short-circuit current. If the conductivity of the soil is poor (resistivity of 2000 Ohm*m or greater), special attention has to be paid to the magnitude of station potential during an earth-fault. In this case it is possible to limit the earth-fault current and dimension the insulation level correspondingly. Alternatively the potential rise of the earthing grid may be limited by ensuring that the earth wires of outgoing overhead lines are of good conductivity and, in extreme cases, have cross-sectional areas equivalent to those of the phase cables.

1.7.1.5 Protection in General The transition compound has to be designed and constructed so that all possible faults can be eliminated: The need for telecontrol and telecommunication links depends on the needs of the automation, remote control, data transmission, and operation of the network.

1.7.2

Site Selection

1.7.2.1 General The choice of a site for a transition compound is a compromise between technical, economic, environmental, and political factors. In simple terms the problem is to find the most suitable place within a fairly large geographic region, where the compound can be built, given the total number of circuits and the destination of the lines. Typically, in the whole region, climate and altitude are almost the same, but technical and environmental factors vary.

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The first step is to locate possible sites, which are as level as possible, with enough available area, at reasonable costs, with easy access, within the general location, and without important restrictions on line corridors, where the transition compound can be erected with minimum environmental impacts. It is advantageous to locate sites near to existing line corridors or even at crossing points. Sometimes, such places simply do not exist and the choice will be confined to places that have only some of the above characteristics. Once the possible sites have been located, an analysis is then made for all the technical and environmental aspects of each one, including costs, potential environmental impacts, and the preventive or corrective measures that can be taken to avoid or reduce them. It is also worthwhile to assess the social acceptance of project. This analysis then furnishes the criteria for deciding on the most suitable transition compound site, bearing in mind the degree of feasibility and the project cost of each alternative. If no suitable site is found, the process may be reinitiated with another general area.

1.7.2.2 Environmental Aspects This aspect has the greatest effect in terms of reducing the possible impacts on the natural or social environment; since many of the potential effects of a transition compound, and especially the magnitude of such effects, depend largely on whether its siting avoids the more sensitive areas. Some of the aspects given below are the limitations including technical point of view. Negligence in taking account of these aspects could have an indirect effect on environmental protection. 1.7.2.2.1 Land The site should preferably be on fairly flat land. This would significantly cut down the possible effects on the substratum by reducing the need for earth movements. The area of the transition compound site must not be flood-prone/water stagnation. The transition compound site should not come within areas or spots listed in the inventories of sites of geological interest. The terrain should be big enough and have a suitable layout for housing all transition compound equipment and services, including any future extensions thereof, and for the development of a landscaping project. 1.7.2.2.2 Water The site should be chosen so as to avoid any damage to the natural drainage network, especially to permanent surface watercourses, avoiding their interruption, and to ground-water recharge areas, to avoid any damage to the underground network. 1.7.2.2.3 Vegetation Where possible the transition compound should be sited in low-productivity farming areas or uncultivated land, avoiding areas in which the existing plant formations have a high ecological or economic value.

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All wooded areas should in general be avoided, especially woodland formed by protected species, singular groups, or riverside copses. The impact on vegetation of the future line corridors should be considered. 1.7.2.2.4 Fauna The site should be chosen so as to avoid any areas or spots listed as protected areas due to the importance of their animal communities, especially those protected because of birds. Attempts will also be made to site the transition compound as far from such areas as possible to preempt future problems in the incoming and outgoing lines. 1.7.2.2.5 Population and Economy As far as possible the transition compound will be sited away from population centers, isolated dwellings, and areas of potential urban development. This obviously does not hold for distribution transition compounds that have to be close to the consumers they serve. Proximity to all mines and mining concessions in general will be avoided, as these impose limitations on the transition compound’s incoming and outgoing lines, Any zones with a tourist and/or recreational potential will be avoided. 1.7.2.2.6 Town Planning The local town planning policy needs to be taken into account when siting the transition compound to avoid urban areas, development land, or land held in reserve for possible future development. Transition compound landscaping may be covered by local regulations and should be considered in detail when siting the transition compound. 1.7.2.2.7 Cultural Heritage All areas should be avoided that contain items belonging to the cultural heritage, to prevent either direct damage, such as the deterioration or destruction of archaeological remains, or indirect, resulting from placing the transition compound in the vicinity of a monument and affecting its visual setting (Fig. 1.35). Fig. 1.35 Identification of cultural heritage

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1.7.2.2.8 Infrastructures Consideration should be given to the presence of any infrastructure such as radio and television antennae and/or relays, airports and aerodromes, other projects, generating plant or infrastructures belonging to other electricity companies, deposits of fuel or flammable material, dumps, military sites, or any other infrastructure that might impose limitations on the siting of the transition compound and the incoming lines. The proximity of other infrastructures has to be considered: train stations and main roads (equipment transfers), water supply, medium voltage electricity network, and telephone service network. Existing devices for the treatment and evacuation of rainwater and sewage water should also be considered. 1.7.2.2.9 Protected Natural Sites Enlarging on the points already made under the heading of fauna, the transition compound should be sited outside and as far as possible from any areas listed as protected natural sites, especially national and natural parks, or other listings of similar standing. 1.7.2.2.10 Landscape Wherever possible, the transition compound will be sited in areas of little scenic value, avoiding any areas or spots listed in the natural inventory of outstanding landscapes. Sites in woodland should also be avoided, given the tree-felling that would be necessary and the visual impacts that would ensue. The nearby presence of woods, however, would cut down the visibility of the transition compound, thereby reducing its landscape impact. The best site, as far as landscaping is concerned, is such that the transition compound is not visible from the most common views points. (Fig. 1.36).

Fig. 1.36 Example of integration of a transition compound in the landscape

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An analysis will be made of the nearby presence of roads and railways, as these would greatly boost the number of potential observers and the consequent visual impact of the compound. The choice of the site should take into account the size and shape of the visual field affected. With the aim of minimizing the scenic impact of the transition compound and helping it to blend in with the background, a landscaping project should be drawn up in the interests of definitive landscape restoration. Landscape restoration should achieve the best possible harmonization of the transition compound with the shapes, textures, and color of the surroundings. The project thus has to deal with such matters as earth movements, the definition of surface coverings and the use of plantations of trees and bushes, as these are basic means to that end. 1.7.2.2.11 Access Route When designing the access route, consideration will be given to the same factors as in the choice of site, preventing the access route from producing undesirable impacts that the siting of the transition compound had managed to avoid. The definitive transition compound access route will be designed to reduce the visual impact as far as possible. A study should therefore be made for the possibility of making an independent access route for the work, especially for bringing the equipment for the transition compound. Other considerations to take into account are: the possibility of setting up the access route by purchase of the land or by establishing the corresponding rights of way, determination of the access with the minimum length, and negotiability of the route for the special vehicles needed for bringing in the heaviest and biggest items of the electric equipment. Once a decision has been taken on the area that meets the characteristics for setting up the route, attention will then be paid to the following aspects when laying down the definitive access route: effecting the definitive access route from secondary roads of the public road network to cut down the number of potential observers; avoiding straight-line junctions with the road network, using curves and exploiting the natural relief; minimizing earth movements and the creation of unnatural shapes, thus avoiding the creation of banks difficult to plant up afterwards, avoiding tree cutting and felling and/or damage to other important elements of the environment such as nests, underground lairs, and cultural monuments. 1.7.2.2.12 Site Preparation Special care will be taken with all watercourses, whether permanent or temporary, ensuring their continuity by means of any necessary channels or under-apron tubes, according to the solution decided upon. The site should be made so that the banking around the station has a gentle slope, less than 30% if possible, to ward off any significant erosion. This measure should be taken into account in the banking of both embankments and cuttings, in the first case due to their greater proneness to erosion, and in the second, due to the greater

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difficulty of carrying out corrective measures as the substratum here is much poorer and it is therefore more difficult for plants to take root. Banking work will also be finished off so as to present a homogeneous surface, with a certain roughness to facilitate seeding. As far as possible they should be made to chime in with the natural forms of the land, avoiding the creation of abrupt changes of gradient, sharp edges or unnatural shapes at the top of the banking. Where the plot lies close to a road, a study should be made of the feasibility of distancing the apron from it as far as possible to cut down the scenic impact. Care should be taken when creating the outdoor yard not to interrupt any existing paths on the plot, to avoid balking the free movement of the owners of other property. Where necessary an alternative route will be set up. The ideal solution would be an internal ring road round the edge of the plot, so as to respect rights of way and fulfill the same function as before, improving existing paths in terms of width and roadbed. Consideration will in any case be given in the construction project to the repositioning of paths and all types of services thereby affected. The definition of earth movements should make due provision for the definitive disposal of the topsoil, which in no case should be covered by poorer quality material. It should rather be collected and put to good use elsewhere. When designing the equipment disposition, and when work is underway thereon, all attempts will be made to conserve all trees on the plot that are not directly affected by the platform, so that they shield the transition compound from outside observers.

1.7.2.2.13 Other Environmental Considerations Other considerations or aspects to take into account in the design, as aesthetics, noise, of leakage/spills, waste management, etc., are described in TB 250 (CIGRE WG B1.19 2004).

1.7.2.3 Technical Aspects 1.7.2.3.1 Topography It is convenient, for reasons of standardization of supporting structures, economy of space, access to equipment, even distribution of stresses between equipment terminals and easy connection of equipment, to level the ground where the transition compound is to be built (small slopes, to allow necessary drainage, must, of course, be provided). To level the area required by a transition compound may be a costly and timeconsuming task, so it is better to choose a site as flat as possible but not subject to flash floods. Taking into account topographic characteristics it is convenient to evaluate the consequences, concerning leveling works, of small displacements and changes of geographic orientation. In the mountain regions, a transition compound must be placed as far as possible from avalanche corridors. Leveling costs may force the reduction of the dimensions of the transition compound.

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1.7.2.3.2 Geological and Geotechnical Characteristics of Soil The soil must allow the construction of roads and foundations. The minimum bearing load is usually about 50 kN/m2. The existence of geological faults is usually sufficient reason to reject a particular location. Siting a transition compound in the areas of unused mines can lead to severe problems due to ground subsidence and such locations are best avoided. In zones subject to earthquake hazards a careful study is essential, as earthquake intensity may vary dramatically in places located only some kilometers apart. A high water level may require the construction of drainage facilities, increasing costs, and causing construction delays. Terracing costs and maximum possible inclination of the talus are a consequence of geological and geotechnical characteristics of soil. A low value of soil resistivity is desirable, and this should be measured before erection of the transition compound. Additional actions such as increasing the site area and inputting earthing facilities may be necessary. 1.7.2.3.3 Access The equipment is generally of shape and weight compatible with any common transportation network. The transport procedure must be checked both ways (to and from transition compound site) and measures taken to maintain it during the transition compound lifetime. Small difficulties may be solved by the use of lower loader, or by temporary reinforcement of bridges. In the most difficult cases, improvements in the transportation network may be necessary. Another aspect to be considered is the access of operators (for manned transition compounds) and maintenance teams (for unmanned transition compounds). 1.7.2.3.4 Line Corridors The cost of modifications to existing lines to allow their connection to the transition compound must also be evaluated. The consideration of future extensions with additional line entries may have different consequences upon the various sites being analyzed. Line corridors have great influence on the geographical orientation of the transition compound and may impose the choice of a transition compound layout. 1.7.2.3.5 Pollution Pollution causes the deposition of small particles on the insulators. The relationship between creepage distances and pollution level is indicated in IEC Standard 60071-2 (IEC 60071 1993–12). As pollution levels may change (increase) with time, a small over-dimensioning is recommended. In extreme cases, in heavily polluted or dry zones, cleaning facilities or the use of protective products may be necessary. Saline and some types of industrial pollution can cause corrosion in supporting structures, and protective coating or the use of concrete supporting structure may therefore be needed.

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Nevertheless, whatever measures are taken, the risk of failure and the equipment and maintenance costs will always increase with the pollution level. Whenever possible the prevailing winds should flow through the transition compound towards the origin of the pollution (sea, industrial zones, highways. . .) or, the transition compound should be protected by some natural barrier (e.g., hills or trees).

1.7.3

Overvoltage and Insulation Levels

All equipment installed in a transition compound must be designed by taking the rated power frequency voltage of the network into account. The temporary overvoltages at power frequency caused by, for example, sudden loss of load or earth faults switching overvoltages and lightning overvoltages. In order to determine its capability, it is subject to voltage tests as follows: (a) Lightning impulse withstand voltage (1.2/50 μs) (b) Switching impulse withstand voltage (250/2500 μs) (c) Power frequency (50 or 60 Hz) (wet and/or dry) The set of test voltage values determines the insulating level. Standard insulating levels are defined in IEC Standard 60071 although the network parameters may dictate other values (IEC 60071-1, -2) (IEC 60071 1993–12). The necessary insulation level depends on the insulation co-ordination, that is, on the properties of different parts of the network (mainly lines), the protection used against overvoltages (surge arresters ZnO are very effective), on altitude and also on the required reliability of the transition compound (permissible probability of flashover).

1.7.4

Current Rating and Overcurrents

The instantaneous load flow within a transition compound depends on the state of the entire electrical network. Usually a complete network analysis including development of network in future is required to determine the nominal values of currents flowing in an individual transition compound circuit. It is theoretically possible for maximum current flow to occur with a relatively low total production of electricity in the network. For example, the supply to a pumped storage power station or when utilizing the by-pass facility within a transition compound. While designing a transition compound it is necessary to consider the following two aspects of the effect of current.

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(a) The thermal effect (including induced currents) (b) The mechanical effect on conductive items of plant and their support structures Precise thermal modeling of equipment is very difficult as many factors influence the resultant temperatures of conductive parts, for example, previous loading, ambient temperature, wind speed, and solar conditions. Thermal design is therefore empirical and is proven by type test covering nominal current rating and short-circuit current rating. Standard procedures have been devised to predict the thermal behavior of conductors, particularly with respect to sag. It may be possible to assign a short-term current rating in excess of the nominal but the analysis leading to this must be to ensure that no “hot spots” are overlooked. Methods of calculating short-circuit current values are given in IEC Standard 60909 (IEC 60909 2016–01) and the effects of short circuit current can be evaluated in accordance with IEC Standard 60865-I (IEC 60865 2011–10).

1.7.5

Electrical Clearances

It is not possible to test the whole HV installation by corresponding test voltage. Therefore minimum clearances in air between live parts or between live and dead parts in the air are stated, to obtain the required insulation level in arrangements which have not been tested. As the clearances are stated universally, they must assume the insulation in the worst case of spark gap with sufficient reliability. Smaller clearances are permissible if the particular arrangement has been tested by the prescribed insulation test (IEC 60071) (IEC 60071 1993–12). The values of minimum distances to live parts in the air also depend upon practical experience and, therefore, some differences can be found when comparing rules in different countries. The specified electrical clearances must be maintained under all normal conditions. Exceptionally reduced electrical clearances may be allowed. For example, in the case of conductor movement caused by short-circuit current or by extremely strong wind.

1.7.6

Direct Lightning Stroke Shielding

A transition compound should be protected against direct strikes by lightning, where there is a significant probability that lightning discharges will occur. The following are characteristics of the lightning phenomena that make it difficult to engineer the direct stroke protection:

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• The unpredictable, probabilistic nature of lightning • The lack of data due to the infrequency of lightning strokes • The complexity and economics involved in analyzing a system in detail There is no known method of providing 100% shielding short of enclosing the equipment in a solid metallic enclosure. The uncertainty, complexity, and cost of performing a detailed analysis of a shielding system has historically resulted in simple rules of thumb being utilised in the design of lower voltage facilities. Extra high voltage (EHV) facilities, with their critical and more costly equipment components, usually justify a more sophisticated study to establish the risk vs. cost benefit. A four-step approach can be utilised in the design of a direct lightning stroke protection system. (a) Evaluate the importance and value of the facility being protected (b) Investigate the severity and frequency of the lightning phenomena in the area of the transition compound facility and the exposure of the transition compound (c) Select an analysis method consistent with the above evaluation and then lay out an appropriate system of lightning stroke protection (d) Evaluate the effectiveness and cost of the resulting design The frequency of the lightning phenomena is often defined by the Ground Flash Density (GFD) or by the keraunic level. GFD is defined as the average number of strokes per unit area per unit time at a particular location. Keraunic level is defined as the average annual number of thunderstorm days or hours for a given locality. Two typical methods for the analyses of the effectiveness of a direct lightning stroke protection system are: 1. The classical empirical method with: (a) Fixed angles (b) Empirical curves 2. The electrogeometric model For additional information about severity and frequency of lightning phenomena, and protection system analyses, see IEEE 998 – Guide for direct lightning stroke shielding of substations (IEEE 998 2012).

1.7.7

Earthing for Personnel Safety

An earthing system, engineered for personnel safety, ensures that a person is not exposed to a dangerous electric voltage gradient, when in the vicinity of facilities that are connected to earth. A personnel safety earthing system controls the effects of

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the temporary earthing path, established by a person exposed to a voltage gradient in, or in the vicinity of the transition compound. During earth fault conditions, the flow of current to earth will produce voltage gradients within and around a transition compound. During an earth fault, the maximum voltage gradients along the earth surface may endanger a person in the area. Moreover, hazardous voltages may develop between metal structures or equipment frames that are connected to earth, and nearby surfaces on which a person may stand. The following circumstances can contribute to hazardous voltage gradients and a risk to personnel: (a) Relatively high earth fault current (b) High soil resistivity (c) Distribution of earth fault currents such that a significant ground return current flows (d) Presence of an individual at such a point, time, and position that the body is bridging two points with a voltage difference (e) Insufficient contact resistance to limit current through the body to a safe value under the above circumstances (f) A fault duration such that the duration of the flow of current through the human body is for sufficient time to cause harm The effects of an electric current passing through the vital parts of a human body depend on the duration, magnitude, and frequency of this current. The most dangerous consequence of such an exposure is a heart condition known as ventricular fibrillation, resulting in immediate arrest of blood circulation. The magnitude and duration of the current conducted through a human body at 50 or 60 Hz should be less than the value that can cause ventricular fibrillation of the heart. The safety earthing system should be engineered to limit the magnitude of the human body current by limiting the step voltage and the touch voltage during earth faults. High speed clearing of earth faults reduces the probability of exposure to electric shock, and reduces the duration of current flow through the body, which limits the severity of bodily injury. The allowable earth fault current value may therefore be based on the clearing time of primary protective devices, or that of the backup protection. For additional information about the criteria, and the design of safety earthing systems, see IEEE 80 (IEEE 80 2013), Guide for safety in AC substation grounding. For guidance on the effects of current on the human body refer to IEC 60479 (IEC 60479 2018–12). Definitions: Step Voltage – The difference in surface potential experienced by a person bridging the distance of a human step without contacting any other conductive part (IEEE 80) (IEEE 80 2013).

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Touch Voltage – The maximum potential difference between the accessible earth surface and dead part which can be touched by a hand of person standing on the surface (IEEE 81) (IEEE 81 2012). See ▶ Chap. 2. Safe Current – The current which can flow through the human body without threat to the life and health of exposed person (IEC 60479-I, 2) (IEC 60479 2018–12). Maximum step and touch voltages are set to levels which will limit the current flowing through an exposed person to the safe current level. The proposed methods of service and repair work must be considered in the design of a transition compound. In most of the countries, the minimum clearance between live parts and personnel is standardized. The following parameters are usually defined: (a) (b) (c) (d)

Minimum height of live parts above the accessible surface Minimum height of the lowest parts of insulators above the accessible surface Minimum horizontal distance between a live part and protective rails, fences, etc. Minimum distance between a live part and a human body (or conductive tools) during the work in the transition compound

The main circuit, once isolated, must be considered a live part until it is earthed. It is generally required to check for voltage on the conductor before applying the earthing device.

1.7.8

Corona and Radio Interference

All devices must satisfy the specified level of radio noise. The limits of radio noise are stated by national standards.

1.7.9

Acoustic Noise

National regulations or standards generally give the permissible acoustic noise level. An acoustic study for the planned transition compound should be carried out to determine the acoustic conditions of the various items of equipment. Within the framework of this study, the nature, distribution, and number of sources of noise for the final installation and at intermediate stages has to also be considered.

1.7.10 Water Contamination All noxious materials in the transition compound must be used and handled without leakage. The vessels must be, where possible, leakproof.

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In most countries additional measures against detrimental materials are required. Oil pits are designed to catch some proportion of the oil (or other liquid) and to prevent oil from burning. If a central underground tank is used, it must be large enough to contain the volume of the largest oil-filled equipment, any rainwater collected since the tank was last emptied and the volume of water resulting from operation of the water spray fire protection system (where used). When no oil leakage occurs, the rainwater may be drained off. Otherwise decontamination is necessary by such means as mechanical separation, filtering, or chemical cleaning.

1.7.11 Mechanical Forces 1.7.11.1 Weight In addition to the normal weight of apparatus, conductors, structures, etc., temporary loads must be considered, especially the weight of frost and ice (depends on local climate) and loads imposed by maintenance staff access. The strain during erection must also be considered (lifting of structures, asymmetric pull of conductor, etc.). 1.7.11.2 Wind Loading The wind pressure may substantially influence the strain exerted on structures and footings and may also reduce the clearances between conductors (in the case of turbulent wind) or between the conductors and grounded structures (consideration should be given to insulators in V formation where problems occur). Standard values for wind speed are recommended by IEC but local conditions must always be considered. When calculating the wind loads on bundle conductors the screen effect from the other subconductors may be taken into consideration. The effect of wind on insulator strings should be taken into account. The wind loads can be transmitted to apparatus through either rigid or flexible connections. 1.7.11.3 Earthquake Earthquakes occur in different parts of the world. Designers should consider the probability and the expected severity of a possible earthquake. Because the horizontal acceleration is about 0.3–0.5 g (the vertical acceleration is less than 50% of the horizontal) and the frequency of the earthquake is 0.5–10 Hz, EHV equipment that resonates in this frequency band may be damaged. Support insulators are particularly vulnerable. Tubular aluminum conductors are also thought to resonate during earthquakes and, if required, “dampers” or “slide supports” may be fitted. Equipment in the transition compound is liable to suffer from damage where the ground conditions are not stable. Therefore, particular attention should be paid to site preparation to ensure “solidity” of the ground.

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1.7.11.4 Short-Circuit Generally, equipment is type tested in a short-circuit laboratory to determine its dynamic behavior with the exception of support insulators. Insulators are generally tested to meet loads in static mode. The short-circuit strength of the conductors is usually only calculated, the calculation methods being verified by testing of typical arrangements. IEC 60865-1 can be used both for rigid and flexible connections, the background to the calculation methods is detailed in CIGRE Brochure 105 (CIGRE SC 23 1996), published in 1996. Equations presented in these publications do not take into account the flexibility of insulators and this may result in over-specification of the required strength of insulators, especially where the application is of non-ceramic insulators. Advanced methods can be used for specific arrangements, to validate simple evaluations, or to limit short-circuit tests to the minimum number of configurations. They give access to much more comprehensive data than simple methods (e.g., dynamic effects, supporting structure stress and strain, spacer compression, connection to apparatus, insulator and supporting structure flexibility, etc.). 1.7.11.5 Combinations of Forces The probability of simultaneous occurrence of various mechanical forces will be dependent upon local conditions. Calculations should normally include specified combinations of: a) Wind loads on conductors and equipment b) Ice loads c) Short circuit loads d) Earthquake loads whenever necessary e) Maintenance and/or erection loads f) Weight of equipment and reaction forces g) Static conductor tension Additionally, mechanical loads due to low ambient temperatures should be taken into account.

1.7.12 Civil Design Civil design includes supporting structures, foundations, facilities (internal roads, rails, site surface. . .), fencing, and buildings.

1.7.12.1 Supporting Structures Supporting structures include terminal gantries and support. Whereas reinforced concrete may be used for HV transition compounds, supporting structures of EHV transition compounds are commonly made from welded or bolted open profile steel lattice, or of tubes. In some cases, aluminum structures are used for their low weight, resistance to corrosion and suitability for using in strong magnetic fields but it should

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be noted that the buried portion must be made of steel in order to avoid electrochemical corrosion. Calculation of loads is usually covered by national standards and regulations which specify safety factors and load combinations.

1.7.12.2 Foundations Calculation methods are given by national or company standards. Dimensioning is carried out according to the loads on the structures and additional forces. Depending upon the type of soil and the loads, foundation types can be: (a) (b) (c) (d) (e)

Poured concrete with or without steel reinforcement Prefabricated reinforced concrete Concrete slab (mostly used in indoor applications) Drilled (suitable in hard soil) Auger bored piles

Steel stubs or anchor bolts, to which the structures are attached, are usually cast into the foundation, a template often being used to locate such fixings prior to the concrete being poured. Alternatively, the foundation pads can be drilled (after setting) using the structure as a template and anchor bolts secured using epoxy cement.

1.7.12.3 Site Facilities Facilities for maintenance and operational needs must be taken into account in transition compound design. Where access by crane or trucks has to be provided for installation, maintenance, or replacement operations, roads or tracks have to be constructed. The surface of the site will also influence access. Usually stone chippings or grass are used to reduce dust levels. Stone chippings are also effective in limiting “touch” and “step” voltages (See Sect. 1.7.7). 1.7.12.4 Fencing External fencing reduces the possibility of entry to the site by unauthorized persons. Special measures are usually defined in national standards. Special attention should be paid to “touch” voltages where metallic fencing is used. Internal fencing is used mostly for defining areas where access is restricted, rails or wire fencing can be used for this purpose. 1.7.12.5 Buildings The design of buildings has to conform, where relevant, to national and utility standards. Their main role is to contain and give shelter to protection relays, SCADA equipment, auxiliary equipment, battery systems, fire protection pumps, etc. For economic reasons (reduction of the length of cable runs, reducing auxiliary supply voltage, minimizing first investment) several dispersed buildings rather than one central building can be built in a transition compound.

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Whether a transition compound is manned or unmanned will determine the extent of the facilities required locally for the operators. Normally a transition compound building is provided with a septic tank. Fences, buildings, civil works, and supporting structures can influence the aesthetic impact of the transition compound on the environment.

1.7.13 Fire Protection The use of fire protection systems and/or measures is mainly based on: (a) Minimizing the hazard for the operators and the public and protecting the environment (b) Limiting the damage to adjacent apparatus, equipment and buildings (c) Minimizing the loss of customer’s service To minimize the risk of fire damage, passive protection measures should also be taken to prevent a propagation of fire or to limit damage, for example, fire resistant materials, synthetic terminations. See TB 720 (CIGRE WG B1.51 2018). Fire protection of cables in indoor and outdoor HV transition compounds is usually only by passive measures to reduce the fire propagation – fire stops (concrete, steel, mineral wool, sand, silicone) and/or fire resistant painting. In installing fire barriers care must be taken to ensure that hot spots are not introduced. Power and control cables should be installed along separate routes, for example, separate cable racks or separate trenches.

1.7.14 Transition Compound Security To control entry to a transition compound by unauthorized persons, the site should be equipped with security measures. These measures serve two purposes: protection of public and personnel safety and protection of assets against toss and/or damage. Transition compounds are a high voltage environment which can present potential safety hazards to untrained and/or unaware people. Furthermore, the theft of copper grounding wires from perimeter fencing or from inside a transition compound could affect the integrity of the transition compound grounding system, thus potentially compromising the safety of the intruder as well as Utility staff. Damage or loss of transition compound operating equipment could also result in loss of supply to customers and material/property losses. Transition compound security measures may include fences (in some cases with electrified wires), walls, entrance/equipment locks, photoelectric motion sensing equipment, video surveillance systems, computer security systems, lighting, or landscaping. For each transition compound an assessment should be made

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to determine which measure and/or combination of measures are most appropriate. For guidance on the effectiveness of transition compound security measure and criteria for security refer to the IEEE Std. 1402 “Guide for Electric Power Substation Physical and Electronic security” (IEEE standard 1402 2021).

1.7.15 Energy Efficiency in Transition Compounds Internal energy efficiency improvements should be treated as an integral part of everyday good business practice and responsible asset management. Energy savings reduce operating costs and contribute to the overall efficiency and competitiveness of the business. Sale of the energy saved could contribute to the annual gross revenue. In transition compounds energy savings could be achieved through equipment selection, installation of energy-efficient buildings and design of the compound services. Energy efficiency measures to be considered by electrical designer include reducing the corona effect in HV switchyards and use of compact conductors. For station services, use of alternative energy sources for station services (e.g., solar panels, wind turbine generators) should be economically evaluated for energy efficiency purposes. For outdoor lighting, use of energy efficient lamps, minimizing the number of fixtures, manual on/off switches, timers, and use of motion sensors will reduce the energy consumption at very little additional cost.

1.8

Commissioning

Commissioning covers all the measures that need to be taken on-site in order to assure the correct functioning of single components of equipment and the transmission system as a whole. Besides the type test, routine test, and sample tests which are done in the factory, additional on-site tests are required; these tests help to ensure that the equipment specifications are met and they serve to detect any damage caused by transportation, shipping, or erection which may modify the characteristics. In general, all installations are subject to commissioning tests. Typical examples of commissioning tests are: • Proving the wiring that provides remote control, signaling, and measurement functions • Tests for correct operation of remote control, signaling, and measurement equipment

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• Checking of electrical clearances and conductor sag for the jumpers • Tests after installation of underground sections Commissioning tests are the most important quality assurance checks when an installation is transferred to the user after erection. The extent of contractual and system acceptance tests, the responsibilities, and the procedure of repair or correction in case of detected defects is subject to agreement between the companies concerned. Test after installation of cable systems has the purpose to check the integrity of the system when the installation has been completed. The cables are routine tested in the factory; the accessories are assembled at site. A DC oversheath test and an AC insulation test are recommended. With the oversheath test, it is common practice, to check the bonding equipment of the cable and to verify that appropriate connections have been made. DC voltage test on oversheath at 10 kV as prescribed by IEC 60229 (IEC 60229) allows to assess the cable conditions after the unreeling and installation. For installations where only the oversheath test is carried out, quality assurance procedures during installation of accessories may, by agreement between the purchaser and the contractor, replace the insulation test. The basic approach for an insulation test after installation of cable systems is that typical faults originated during assembly of accessories should be detected effectively by exposing the system to adequate electrical stresses, without harming the system under test. The crucial question is the level, duration and the availability of test voltages. A DC Voltage test is an appropriate and easy way to test laminated cables after installation but DC testing is not recommended for testing extruded cable systems as reminded in recommendations for on-site testing after installation published in Electra 173 (1997) by CIGRE WG 21.09. Nowadays, IEC has issued IEC 62067 (EHV cable systems) (IEC 62067 2022–04) and Edition 3 of IEC 60840 for HV cables and systems (cable and accessories) (IEC 60840 2020). The requirements in those standards for test after installation are in line with the CIGRE recommendations of 1997. AC testings of the main insulation at Uo for 24 h combined with stringent accessory installation quality assurance procedures have been proven to be satisfactory to guarantee the quality of the cable system. Where an AC testing at higher test voltage within the range of 1.1 to 1.7 Uo is required, the use of dedicated test equipment such as series-resonant test system must be planned: it is necessary to have access to terminations and to disconnect the underground cable system from the network. As the series-resonant test equipment commonly used is rather cumbersome (lorries of 40 T), access must be provided in the vicinity of the terminations and HV connections from the testing equipment to the cable system must be established while respecting sufficient distances between live parts and surrounding equipment (Figs. 1.37).

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Fig. 1.37 Tests on HV/EHV cable circuits

1.9

Operation

Extruded cable systems are generally designed for a service life of 40 years and even more. As far as there is no external aggression and no water ingress, there is no reason for a reduced service life if they have been manufactured and tested appropriately and if they are operated within their rating limits. Nevertheless, in case of breakdown, in order to limit the duration of the unavailability of the cable system, it is necessary to have an established repairing procedure. Consequently, the main issues to be addressed during Operation are: • Operation within the design rating limits. • Prevention from external aggression. This issue is covered in TB 398 Published by WG B1.21 (CIGRE WG B1.04 2005). • Repairing procedure. Several CIGRE TB (279,680,773,825) deal with this topic (CIGRE WG B1.04 2005; CIGRE WG B1.47 2017; CIGRE WG B1.52 2019; CIGRE WG B1.60 2021). See also ▶ Chap. 9.

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Historically, underground cable systems have not generally been loaded to their design ratings. This situation is changing, and cable systems are likely to be more heavily loaded in the future as Utilities work their systems harder and make more use of their assets. Although rare, there have been examples of failures within cable systems that have been operated above their maximum operating temperatures. Increased congestion of services has an impact on circuit ratings arising from closer proximity of other circuits and other heat sources. Changes in depth due to construction activities can also reduce ratings. Lack of understanding of the external thermal environment, including inadequate attention to the thermal backfills, etc. presents further risk to the performance of underground cables. Continuous or at least periodic monitoring of cable temperatures can reduce or even eliminate this risk. As a consequence, temperature monitoring systems are being installed with new underground distribution and transmission cable systems. Retrofitting of such systems would also be of great interest but complete distributed monitoring is unfortunately not practical. The output of such monitoring systems is now being used in conjunction with other parameters to forecast and provide guidance regarding the short-term overload capability of cable circuits under emergency conditions. At the CIGRE Study Committee 21 (Underground Cables) meeting held in August 2000 it was agreed that a Working Group be established to review “Thermal Monitoring of Underground Cables” (CIGRE WG B1.02). The work of CIGRE WG B1 02 has been published in Technical Brochure 247 which was introduced in Electra 213 (April 2004) (CIGRE WG B1.02 2004a; CIGRE WG B1.02 2004b). More recently (February 2019), WG B1.45 has published TB 756 “Thermal Monitoring of Cable Circuits and Grid Operators use of Dynamic Rating Systems” (CIGRE WG B1.45 2019).

References CIGRE Electra 173 After laying tests on high voltage extruded insulation cable systems (1997) CIGRE JWG 21/33: Insulation Coordination for HV AC Underground Cable Systems, CIGRE TB 189 (June 2001) CIGRE SC 23: The Mechanical Effects of Short Circuit Currents in Open Air Substation, CIGRE Technical Brochure No. 105 (October 1996) CIGRE TF B1.26: Earth Potential Rises in Specially Bonded Screen Systems, TB 347 (2008) CIGRE WG 21.13: Operating Characteristics of Long Links of AC High Voltage Insulated Cables, Session Report Report 21-13 (1986) CIGRE WG 21.17: Construction, Laying and Installation Techniques for Extruded and Self Contained Fluid Filled Cable Systems, TB194 (2001)

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CIGRE WG 23.03: General Guidelines for the Design of Outdoor AC Substations, TB No. 161 (2000) CIGRE WG 23.04: Engineering Guide on Earthing Systems in Power Stations, CIGRE Technical Brochure No. 213 (October 2002a) CIGRE WG 23.04 “Design Guidelines for Power Station Auxiliaries and Distribution Systems” (CIGRE Technical Brochure No 197, February 2002b) CIGRE WG B1.02: Optimization of Power Transmission Capability of Underground Cable Systems Using Thermal Monitoring, Electra No. 213 (April 2004a) CIGRE WG B1.02: Optimization of Power Transmission Capability of Underground Cable Systems Using Thermal Monitoring, TB 247 (2004b) CIGRE WG B1.04: Maintenance of HVAC Underground Cables and Accessories, TB 279 (2005) CIGRE WG B1.08: Cable Systems in Multipurpose or Shared Structures, TB 403 (2010) CIGRE WG B1.19: Technical and Environmental Issues Regarding the Integration of a New HV Cable System in the Network, TB 250 (2004) CIGRE WG B1.23: Impact of EMF on current rating and cable systems, TB 559 (2013) CIGRE WG B1.30: Cable Systems Electrical Characteristics, TB 531 (2013) CIGRE WG B1.35: A Guide for Rating Calculations of Insulated Cables, TB 640 (2015) CIGRE WG B1.41: Long Term Performance of Soil and Backfill of Cable Systems, TB 714 (2017) CIGRE WG B1.45: Thermal Monitoring of Cable Circuits and Grid Operators use of Dynamic Rating Systems, TB 756 (2019) CIGRE WG B1.47: Implementation of Long AC HV and EHV Cable Systems, TB 680 (2017) CIGRE WG B1.48: Trenchless Technologies, TB 770 (2019) CIGRE WG B1.50: Sheath Bonding Systems of AC Transmission Cables – Design, Testing, and Maintenance, TB 797 (2020) CIGRE WG B1.51: Fire Issues for Insulated Cables Installed in Air, TB 720 (2018) CIGRE WG B1.52: Fault Location on Land and Submarine Links [AC and DC], TB 773 (2019) CIGRE WG B1.56: Power cable rating examples for calculation tool verification TB 880 (2022) CIGRE WG B1.60: Maintenance of HV Cable Systems, TB 825 (2021) CIGRE WG C4.204: Mitigation Techniques of Power Frequency Magnetic Fields originated from Electric Power Systems, TB 373 (2009) IEC 60071: Insulation Coordination. IEC International Standard (1993–12) IEC 60229: Electric cables - Tests on extruded oversheaths with a special protective function (2007–10) IEC 60479: Effects of Currents on Human Beings and Livestock. IEC International Standard (2018–12) IEC 60840: Power Cables with Extruded Insulation and Their Accessories for Rated Voltages Above 30 kV (Um ¼36 kV) up to 150 kV (Um¼170 kV) – Test Methods and Requirements (2020) IEC 60865: Short-Circuit Currents, Calculation of Effects – Part 1: Definitions and Calculation Methods. IEC International Standard (2011–10) IEC 60909: Short-Circuit Currents in Three-Phase A.C. Systems. IEC International Standard 2016–01 IEC 62067: Power Cables with Extruded Insulation and Their Accessories for Rated Voltages Above 150 kV (Um¼170 kV) up to 500 kV (Um ¼ 550 kV)-Test Methods and Requirements 2022–04 IEEE 80: Guide for Safety in AC Substation Grounding (2013) IEEE 81: Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System (2012) IEEE 998: Guide for Direct Lightning Stroke Shielding of Substations (2012) IEEE standard 1402: Guide for Electric Power Substation Physical and Electronic Security (2021)

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Pierre Argaut graduated as an electrical engineer from Institut d’Electrotechnique de Grenoble in 1971. He joined Delle-Alsthom (HV Switchgear Manufacturer) in November 1971 and took several positions before heading the R&D Department on GIS. After being operations manager of the South European Pipeline, he joined SILEC in 1988 and retired at the end of 2010. His last position with SILEC was senior vice president. In Study Committee B1 (Insulated Cables), Pierre has held position of working group member (21.09;21.06;21.07;21.17), French SC member, working group convener (B1.19), special reporter (2010), advisory group convener (Tutorial Advisory Group till 2010), and chairman of SC B1 from August 2010 to August 2016. He received the Technical Committee Award in 2000, the Distinguished Member Award in 2002, and the title of Honorary Member of CIGRE in 2016. Pierre was in the final stage of publication of this volume when he passed away peacefully in May 2022. He is missed by all his colleagues. Pierre will be remembered for his contributions, but mostly for his brilliant intelligence, his natural gift of teacher to colleagues and friends, his vitality, his permanent attentive ear for everybody, his desire to be always inclusive.

2

Safe Work Under Induced Voltages or Currents Unnur Stella Gudmundsdottir

Contents 2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.1 Definition of Induced Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.2 Inductive Coupling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.3 Capacitive Coupling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.4 Conductive Coupling (Earth Potential Rise, or EPR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.5 Trapped Charge and Dielectric Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.6 Limits for Induced Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.6.1 Acceptable Currents Passing Through the Human Body . . . . . . . . . . . . . . 2.1.6.2 Impedance of the Body . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.6.3 Touch Voltage Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Principles of Safe Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Risk Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2 Earthed Working . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2.1 Earthed Working Without Currents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2.2 Earthed Working with Currents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2.3 Earthing Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.3 Insulated Working . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.4 Protection Against Re-energization During Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 Work Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.1 Measuring Earthing Resistances/Earth Electrode Impedances . . . . . . . . . . . . . . . . . . . 2.3.2 Cable Pulling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.2.1 Cable Pulling for Cables in Open Trenches, Ducts, and HDD . . . . . . . . 2.3.2.2 Cable Installation When Ploughing Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . .

66 68 68 69 70 71 72 72 73 74 76 78 79 81 82 83 87 89 90 90 91 91 93

This chapter is part of the Output of TB 801 published by WG B1.44 convened by Unnur Stella Gudmundsdottir from Denmark in 2020 “Guidelines for Safe Work on Cable Systems under Induced Voltages or Currents”. Some appendices of the TB have not been reproduced in the Chapter. U. S. Gudmundsdottir (*) Siemens Gamesa, Kolding, Denmark e-mail: [email protected] © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_2

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2.3.3 Cable Jointing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3.1 Cable Ends Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3.2 Joint Components Parking (If Applicable) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3.3 Conductor Connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3.4 Joint Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.4 Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.4.1 AIS Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.4.2 GIS Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.4.3 Transformer Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.5 Work on Link Boxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.6 Cable Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.7 Removing Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.8 Working Procedure in Special Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.8.1 Installation and Repair in Tunnels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.8.2 Installation and Repair Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4 Method of Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.1 Inductive Coupling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.2 Capacitive Coupling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.3 Conductive Coupling: Rise of Earth Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 Conclusions and Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendixes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A: Recommendations: Touch Voltage Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A1: Recommendations Toward IEC on Setting Standard Touch Voltage for Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A2: Calculations of Touch Voltage Based on Body Current . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix B: Calculation of Series and Mutual Impedances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix C: Cable Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C1: Primary Voltage Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C2: Oversheath Voltage Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C3: Testing and Configuring Special Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C4: Measuring Earth Electrode Impedances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C5: Special Situations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C6: Searching for a Fault . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D: Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2.1

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Introduction

During several phases of a cable system life (installation/maintenance/testing/ upgrading/removal), it can be necessary to work under voltages or currents induced by an energized system. For example: • • • • • •

During the pulling or the laying During the jointing operations in the installation process When checking or maintaining link boxes During the repair of a cable after fault In the upgrading process of an existing circuit When removing the cable for disposal at the end of its life

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As hazardous conditions could occur, it is important to provide all parties that could be involved (utilities, manufacturers, installers, testing institutes. . .) with guidelines for safe work on cable systems, including a clear terminology. Most of the time, induced voltages are generated and transmitted by the cable and appear at the places where accessories are or will be installed. It is therefore very important to consider this issue from the cable system standpoint to fully understand mechanisms that lead to induced voltages. Content In this chapter (Technical Brochure 801), different types of cable arrangements and installation are covered. Tunnels, open trench, ducts, HDD, ploughing and offshore installations are considered. Special safety precautions and appropriate equipment are indicated for different setups. This chapter references the risks associated with induced voltage on cable systems only; it does not appraise or scrutinize other possible safety issues associated with other hazards on cable systems, such as mechanical stresses, etc. . . . Section 2.1, starts by discussing and identifying the induced voltage phenomenon which can have several origins. With the purpose of identifying what is a hazardous environment due to induced voltages or currents, there is a need for identifying the limit of touch voltages. As this varies from country to country, and as there are several different standards discussing the topic, the task of the Working Group B1.44 has included an in-depth appraisal of these standards and guidelines and a thorough consideration to what should be recommended and included in appropriate International Standard. The basic principle underlined in the guide, is that before the start of any work on power cable systems, it is highly recommended that a risk analysis and the calculation of possible induced voltages be carried out. This suggested risk analysis is explained in the Principles of Safe Work in Sect. 2.2. Three different principles of safe work are given and detailed: Earthed working without currents (which is the recommended method), earthed work with currents and insulated working. In Sect. 2.3, a detailed summary of safe working procedures is given for several stages of work on cable systems: laying/pulling, cutting, jointing, terminating, testing, removal. It is reminded that all these works must be carried out by qualified and certified personnel only. Section 2.4 provides the calculation methodology of the three different types of induced voltages. Some real examples on cables systems experiencing induced voltages, from different countries, are detailed in appendices. Conclusions and general recommendations are given in Sect. 2.5. Section “Appendices” gives Recommendations toward IEC concerning touch voltages and includes some useful relevant appendices proposed in TB 801.

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Definition of Induced Voltages

There are several types of induced voltages that can affect the potential of the cable core, screen and metal sheath. The different types can be divided into three categories depending on how they are transferred from an electrical source to the object of induction (CIGRE TB 95 1995). • Inductive coupling • Capacitive coupling • Conductive coupling All three issues must be evaluated when dealing with induced voltages. The influence from each coupling depends on the presence of other electrical systems in the surroundings of the cable, and how the cable system is bonded to earth.

2.1.2

Inductive Coupling

An insulated conductor which runs in the proximity of a power line or a cable, either on the full route or on a part of its route, is subject to voltages induced by magnetic coupling. The coupling is due to time-varying magnetic flux from the source of the induction being linked with a circuit formed by the conductors of the object of the induction. Current in a nearby cable or overhead line (OHL) in service, whether it is during normal conditions or due to fault conditions, will induce voltage longitudinally on the insulated conductor (which is either being installed, repaired or maintained). If the distance is small, and especially if there is asymmetric current in the system in service (for instance short circuit current due to a fault) the induced voltage can become several kVs. This induced voltage will be longitudinally on all metal parts of the cable whether in or out of service, i.e., armor, metal sheath, conductor and parallel earth wires (such as Earth Continuity Conductors). The magnitude of the induced voltage, due to inductive coupling, depends on the current in the source system, the distance between the two systems and the length of parallelism of the two systems. It should be noted, that the magnitude of the inductive coupling induced voltage is independent of the systems voltage level. How to perform calculations of induced voltages is explained later in Sect. 2.4 and several examples of calculations are given in Appendix C. As a rule of thumb, Table 2.1 can give worst case scenario during normal operation and fault conditions. The correct evaluation should however be done as described in Sect. 2.4.1. Table 2.1 Simple rule of thumb for worst case scenario for induced voltages

Closed trefoil formation Flat formation with 0.4 m between phases

Load 1000 A 1V 7,5 V

2000 A 2V 15 V

Fault 10 kA 3300 V 3300 V

40 kA 13,100 V 13,300 V

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The calculation shown in the example above is based in the following preconditions: Parallel length is 1000 m and distance between cable system and object of induction is 5 m. The earth resistivity is 100 Ωm and the burial depth of both cable system and object of induction is 1 m. For the fault situation, the fault is assumed to be one phase to earth and the return current is only through the earth.1

2.1.3

Capacitive Coupling

Capacitive coupling is the result of electric field around an energized power system. The electric field is associated with a capacitance between the source and any un-earthed conductive object exposed to the field. Together with the capacitance between the un-earthed object and earth, a capacitive voltage divider is formed, so that for an alternating voltage source, a proportion of the source voltage appears on the object. Therefore, overhead lines or substation busbars can only influence insulated cables that are not shielded neither by the earth nor by an earthed screen. This influence occurs in both normal operation and fault conditions (CIGRE TB 95 1995). On the opposite, underground and offshore cables cannot generate capacitive coupling as the electric field is contained inside the shielded insulation. Power frequency voltages appear between the insulated conductor of the cable and the earth; their magnitudes depend mainly on the voltage level of the OHL, the distance between OHL and the insulated conductor, and on the OHL operating conditions (normal operation or faults). It should be noted, that the magnitude of the capacitive coupling is independent of the current flowing in the systems. While risks from capacitive coupling on underground or submarine cables are generally lower than on other conductor systems, there is still a potential for capacitive coupling. Unearthed metal parts of a cable system near high voltage conductors can become capacitively coupled to the high voltage conductor. This is as an unearthed metal object in an electrical field will pick up a voltage. Normally cables are buried and as the ground is at earth potential the cable is effectively shielded from any high voltage conductors. However, there are times when a cable system is exposed to electric fields (for example, HV stand-by links laid on the ground).

1

This is used here for simplification of calculation and understanding. In normal situation, it will be rare that all the fault current will go true the earth.

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Due to capacitive coupling, electric charge can be induced on the conducting parts of an insulated cable: • Even after removing the source of the capacitive coupling, the electric charge can remain for some time on unearthed conductors (“static electricity”). Therefore, if a cable sheath is left disconnected from earth for an extended period of time, it is possible for the sheath to be exposed to standing voltage which will require discharging before any work on the sheath can take place (this discharge current is generally not dangerous). This voltage can often be small in magnitude and will not reappear if the sheath is connected to earth, making it different from inductive induced voltages. • If the source of capacitive coupling is permanent, the magnitude of the permanent current resulting from earthing the cable (through a wire or accidently through a human body) is proportional to the length of parallelism of the routes. It is generally not dangerous for underground cables. Whenever a cable is left disconnected, the metal sheath and core conductor should be shunted and locally earthed, to prevent standing voltage. An example of calculating capacitive coupling can be found in Appendix C. It should be noted that only a part of the cable system needs to be exposed to the electric field for the whole cable to be affected.

2.1.4

Conductive Coupling (Earth Potential Rise, or EPR)

Earth currents (such as fault return currents) flowing through the earthing impedance of an earthing system (such as a tower, substation, at jointing bays or power plant) produce an Earth Potential Rise (EPR) of the earth system with respect to any remote earth. Conductors connected to that earth system can transfer the potential rise to any other earth system where they may be connected, which may be many kilometers away. Cable systems often connect two different earthing systems (between different substations). In such situations, consideration has to be given to the transfer of EPR. The situation already exists on normal operation of HV systems (where EPR is created by induced currents or stray currents) and is aggravated when there is a fault on one part of the system that will cause EPR at the location. The cable will transfer this rise of earth potential to another location that has a different earth potential. Therefore, there can be a voltage difference between two “earthed” objects, one earthed locally and the other remotely. An example is given in Fig. 2.1 above where work is being conducted at a joint bay in the middle of a route. If there is a fault at one of the earth mats (and even in presence of induced or stray currents), then there is the possibility for the voltage at the other earth mats to be different.

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earth mat 1

earth mat 2

Power cable

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earth mat 3

Termination

Link box

Fig. 2.1 Cable system between different earthing systems

2.1.5

Trapped Charge and Dielectric Polarization

Under the influence of external electric field, bonded positive and negative charges, i.e., dipole, could be polarized after a length of time as shown in Fig. 2.2. This is known as dielectric polarization. At the same time, any present free charge could drift toward either conductor screen or insulation screen following the electric field, which is known as space charge/trapped charge phenomenon. After the removal of the external field, polarized dipoles and trapped charges may remain for a period of time, which can result in potential rise in conductor or metallic sheath before the insulation slowly recovers to its neutral state. Note that above two mechanisms can apply to both cable insulation and oversheath. For DC cables after operation or testing, a potential rise (or “return voltage”) can occur to cable conductor again after removing the conductor earth connection if the cable is not discharged for a sufficient period of time. Note that cable suppliers shall suggest the length of the discharge period to ensure safe level of trapped charge. Fig. 2.2 Simple cross section of a cable with polarization of inner insulation, when metal sheath is not earthed

conductor insulation

metal sheath oversheath

semi-conducting layer

Dipole

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Normally, the trapped charges and dielectric polarization are not of a problem for ac cables, but it is still required to discharge the cable by earthing after testing and operations. For example, trapped charge or polarization can occur in the cable oversheath after dc oversheath test, with results in a potential rise in the metallic sheath layer. Therefore, the metal sheath must be earthed appropriately after the sheath test. Although it may not be the general practice for ac cables, precaution shall be taken for trapped charges or polarized dipole inside insulation if tested with dc voltage.

2.1.6

Limits for Induced Voltages

In order to ensure safe working condition when working on cable systems, the acceptable level of effect on the human body needs to be determined. It is not the scope of this work to determine the acceptable touch limits or currents passing through the human body. This has been studied in several literature, and the information is taken from a number of these literatures for information purposes. The acceptable limit is considered in several standards. A list of standards giving limits for touch voltages can be found in Appendix A. None of these are specifically applicable to high-voltage underground cables within and between substations.

2.1.6.1 Acceptable Currents Passing Through the Human Body The danger to humans by electrical shock is dependent on the magnitude and the duration of the current flowing through the human body (IEC Std. 61936-1 2021). Concerning acceptable limits of touch voltage, a distinction based on the duration of the influence must be made: (a) Long-term influence (b) Short-term influence (c) Very short-term influence (e.g., Discharge of a build-up potential) Figure 2.3 shows a curve allowing for a direct calculation of the maximum allowable body current as a function of exposure time, divided in zones referring to the effect on the human body. Figure 2.3 shows four zones depending on the effect on the human body. The zones represent the effects on the human body, as shown in Table 2.2. Figure 2.3 is based on a current path through the body from the left hand to both feet. This is one of the most critical current paths through the body as the current passes through the left side of the chest. For other current paths through the body a heart current factor is used. The heart current factor can be seen in Table 2.3. In order to use the curves in Fig. 2.3 the acceptable reaction on the human body must be determined. For this, curve c2 is often chosen (IEC Std. 61936-1 2021; IEC Std. 50522 2022; IEC Std. 50341-1 2012). In other applications a distinction is made between trained workers and civil people. For this situation c1 may be used for civil people and c2 for trained personnel (ITU-T Std. K33 1996).

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Fig. 2.3 Time/Current curves of effect ac current through the human body (IEC Std. 61936-1 2021) Table 2.2 Effects of current zones on the human body (IEC Std. 61936-1 2021) Zones AC-1 AC-2 AC-3 AC-4

Boundaries Up to 0.5 mA curve a 0.5 mA up to curve b Curve b and above Above curve c1 c1–c2 c2–c3 Beyond curve c3

Table 2.3 Heart rate factor (IEC Std. 61936-1 2021)

Physiological effects Perception possible but usually no startled reaction Perception and involuntary muscular contractions likely but no harmful electrical physiological effects Strong involuntary muscular contraction Patho-physiological effects may occur such as cardiac arrest AC-4.1 probability of ventricular fibrillation increasing up to 5% AC-4.2 probability of ventricular fibrillation up to 50% AC-4.3 probability of ventricular fibrillation above 50%

Current path through body Left hand or both to feet Left hand to right hand Right hand to feet

Heart current factor 1.0 0.4 0.8

2.1.6.2 Impedance of the Body For practical purposes it is more convenient to use acceptable voltage limits instead of limits of currents through the human body. To transform the current limits in Fig. 2.3 into voltage limits, the impedance of the current path including the human body must be determined. The total impedance of the current path consists of:

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• Source impedance (Zs) • Body impedance (Zb) • Additional impedance – Shoes or clothes (Ra) – Contact impedance. Earthing impedance at the place of contact to the earth (Rb) 2.1.6.2.1 Source Impedance (ZS) The Source impedance is dependent on the length of the cable subject to induced voltage. This value may be difficult to determine and therefore as a worst-case condition normally taken to be zero (CIGRE TB 95 1995). Source impedance has to be taken into consideration both for capacitive coupling and for contact with an external semiconductive layer. 2.1.6.2.2 Body Impedance (Zb) The total body impedance depends on several factors among current path, touch voltage, duration of current flow, frequency, degree of moisture of the skin, surface area of contact, pressure exerted, and temperature (IEC Std. 61936-1 2021). IEC Std. 60479-1 (2018) provides values for body impedance categorized between humidity (dry, wet or salt water wet) at the point of contact, and area of contact (small, medium or large area of contact). In addition, for all of these combinations the impedances are given as a function of touch voltage and statistical variation within the population (IEC Std. 61936-1 2021). Often dry condition, large area of contact and the statistical median is chosen. Given these conditions, the only remaining variable is the touch voltage. 2.1.6.2.3 Additional Impedances (Ra and Rb) Additional impedances can be divided into two categories: Shoes or clothes (Ra) and contact impedance (Rb). The applicability of the Shoes and clothes impedance is dependent on the current path. This impedance is very dependent on the state of the footwear or clothes. Due to the unpredictability of this parameter it is often taken as zero (CIGRE TB 95 1995). 2.1.6.2.4 Summary of Impedance Effects The total impedance is the sum of all impedances forming the current path. Many of the impedances are very situation-specific and so are difficult to determine in general. Due to the uncertainty of the impedances it is often chosen to include only the body impedances as a worst-case consideration. How to calculate this is explained further in Appendix B2 of TB 801.

2.1.6.3 Touch Voltage Limits As mentioned in the beginning of this chapter acceptable touch voltages are considered in several standards. These standards are to be used for different parts of high voltage system, but none of them are specifically applicable for HV cable systems.

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Fig. 2.4 Touch voltage the human body can tolerate, as a function of clearance time (IEC Std. 50522 2022)

Even though they are intended for different parts of high voltage systems there seems to be a generally accepted curve for touch voltage. Consideration of the curve of allowable body current against duration, together with presumed impedance values, leads to a curve of allowable touch voltage as a function of clearance time. This widely applied curve is given in both IEC Std. 61936-1 (2021) and IEC Std. 50522 (2022). This curve is also shown in Fig. 2.4, which shows the touch voltage the human body can tolerate, as function of clearance time. This curve is calculated based on the theory described in Sects. 2.1.6.1 and 2.1.6.2 and further described in Appendix B2 of TB 801. For this “general” curve in Fig. 2.4 the following assumptions are made: 1. C2 curve used for acceptable effect on the human body – 5% risk of ventricular fibrillation 2. Current path through the human body – left hand to both feet 3. Body impedance (dry conditions, large area of contact and probability 50%) 4. No additional impedance In general, the consideration above can in many cases be seen a realistic worstcase consideration. It is not in the scope of this work to determine acceptable touch voltage limits for work on high voltage cable systems, however there is a clear need for considering

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acceptable touch voltage limits on cable systems. Appendix A is therefore allocated to a recommendation toward IEC on the scope of setting standards for touch voltage limits on cables systems, within and between substation areas. It is recommended to use the curve in Fig. 2.4 as a starting point and to use Fig. 2.3 as a basis for the calculations, as the voltage/time curve can be obtained by looking at the current/time curve and the impedance of the human body. To give a further understanding of this, the calculations are explained in Appendix B2 of TB 801. 2.1.6.3.1 Long-Term Influences It is generally considered that the danger threshold is around 30 mA (IEC Std. 61936-1 2021). The limit of acceptable continuous touch voltage is different between countries but normally around 50–65 V (CIGRE TB 95 1995). 2.1.6.3.2 Short-Term Influence Short-duration influence may arise during fault situations. Due to the short duration the acceptable touch voltage is typically significantly higher than for continuous influence. Limits for short-duration influence can be determined using the method explained above. For some situations the probability can also be considered that people are actually in contact with the hazardous voltage at the moment of a high-voltage fault. 2.1.6.3.3 Very Short-Term Influence Very-short-term influence typically arises from discharging a trapped charge. In general, the danger is often considered negligible when the discharge is lower than 2.5 mC (CIGRE TB 95 1995).

2.2

Principles of Safe Work

When installing a new cable circuit or when working on an existing cable system there may be an imminent safety hazard due to dangerous induced or transferred voltages and/or heavy circulating currents even though the cable to be worked on is disconnected and isolated from electrical system and earthed. It is important to be aware that while it may be safe to work on an out-of-service insulated cable under normal system/grid operation conditions, dangerous voltages can occur unpredictably at any time due to external faults in electrical system or due to switching, lightning, or other voltage surges. As a result, it is imperative that when planning work under influence of induced voltages the developed working procedures must include an assessment of safety hazards (electrical risks) and to implement the most suitable safe working conditions by considering the three basic safe working principles:

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• Earthed working with currents • Earthed working without currents • Working insulated (with induced or standing voltage) One should note that earthed working without currents, refers to inductive currents in the system. There will still be small currents due to capacitive coupling. Before carrying out any operation on an electrical installation an assessment of the electrical risks shall be made. This assessment shall specify how the operation shall be carried out and what safety measures and precautions are to be implemented to ensure safety. If a cable system is fully or partly parallel to another underground cable (UGC) or OHL in operation, a special attention must be given during the handling. There are four different ways of how to handle this: 1. The cable system is placed at sufficient distance from the parallel UGC or OHL. Sufficient can be difficult to evaluate but IEC 50522 (2022), sets up guidelines for this. By using this method, the longitudinally induced voltages during normal operation will not be an issue. 2. The one phase to earth short circuit current is reduced as much as possible, as this current will increase the induced voltage linearly. Examples for reducing short-circuit current: • Isolating the neutral-to-earth connection on some neighboring transformers • Weakening the mesh density of the network by creating multiple electrical nodes in the neighboring substations Such actions may be taken in some places, to facilitate workers electrical safety achievement, but are generally not feasible. It is important when calculating induced voltages, to use the actual maximum short circuit level brought by the local network (in accordance with IEC 60909 standard (2016)), and not to use the short circuit level used in design definitions for other equipment like busbars or breakers (this is normally much higher than actual values). 3. The parallel system is always disconnected (switched off) during installation, handling or repair of the cable system. This can be used in some cases, but not always. Otherwise, to limit the inducing current transit in the parallel HV line, a specific network configuration may be chosen to give alternate routes for the current transit 4. Work on the switched off and earthed cable system is considered as work under voltage if parallel lines are still energized, and special work method is adopted. This method will often need to be used, as the methods 1–3 are not feasible. In this case, the following must be considered: (a) More distance between systems decreases the induced voltages (b) Reducing the length where the lines are parallel reduces the induced voltages (c) An angle between systems reduces the induced voltages. There is no significant longitudinally induced voltage on systems with above a 45
displacement angle (CIGRE TB 95 1995)

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(d) Use of screening conductors and/or ECC installed along the power cable circuit reduces the induced voltage (e) Lower earthing resistances reduce the induced voltages (f) Contact resistance should be as low as possible to reduce the induced voltage (g) The inductive induced voltage is linearly dependent on the current of the system in service

2.2.1

Risk Analysis

Prior to carrying out any work or operation on an electrical installation it is important to carry out a desktop risk analysis. This risk analysis should specify how the operation shall be carried out and what safety measures and precautions should be implemented to ensure safety. Three different levels of risks were identified for the purposes of this brochure, depending on the types of work to be done: • No risk: All systems in the vicinity can be taken out of service during all working phases • Low risk: System to be worked on is taken out of service during all working phases while a nearby system is taken out of service only during predefined critical working phases • High risk: System to be worked on is taken out of service during all working phases, while a nearby system is in service during all (or part of the) working phases Working on live systems is not recommended and should only be considered for exceptional cases in low voltage systems, medium voltage systems, or high voltage earthing systems. A risk analysis includes work on cable pulling/laying, jointing, termination, maintenance, repair and removal of cables and/or accessories. The risk analysis should include calculations of maximum induced voltage and potential rise of the soil, for capacitive, inductive and conductive coupling. If the cable undergoing repair or other work is partly or fully in parallel with either an OHL or UGC (IEC Std. 50522 2022), sets up distances to be used for determination if the induction effect from the parallel system should be evaluated. The magnitude of the induced voltage depends on several parameters such as the spatial distribution of other power lines in the vicinity, lengths of circuits, load on these external circuits, characteristic of the cables, and the earthing scheme in the area. It may be possible to calculate the induced voltage in the concerned circuit with consideration to the electric power lines (UGC or OHL) in the vicinity. The estimate of induced voltages and potential rise of the soil may be obtained analytically by using equations detailed in Sect. 2.4 or by modelling all the transmission circuits or piece of the grid. The electrical parameters, current and voltages, must be calculated in the steady state conditions and under emergency (short-circuit, lightning and switching surges) conditions as well. Several

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cases should be taken into account following the type of fault events that may happen in the neighboring power lines. To validate the model, it is advised to perform some measurements on site to check voltage and current at different points of the circuit. Where it is not possible to accurately calculate the induced voltages due to inaccurate information about the external factors or unknown factors, the worstcase scenario should be adopted for calculation. In the case of induced voltages or EPR above the maximum allowed induced voltage, the risk analysis should also include a recommendation on how to perform the work safely. This recommendation should give the maximum size of possible earthing resistances to reduce the induced voltages, the current rating for the earthing connections and a proper step-by-step description of the physical work. For jointing and termination work, the proper work procedures ensuring safety and earthing should be requested from the person responsible of the work (for instance the manufacturer) of the cable accessory and reviewed by the party or company who employs the work (for instance TSO). In practice a common working safety procedure should be agreed upon and executed where all involved parties (such as manufacturer, contractor, TSO/DSO, etc.) should review and accept the given information within the limits of their own competence and responsibilities. Prior to starting any work, it is important to ensure proper equipotentiality and earthing. The person responsible for the work (for instance Employer) must ensure this is done properly. If it is not feasible to work with equipotentiality or if there is a requirement for insulated working, the type and level of insulated tools should be described in the risk analysis.

2.2.2

Earthed Working

Earthed Working is the method of working where all equipment and conductive materials which are exposed in the work area, are effectively bonded together (equipotentiality) and then connected to earth at the point of work. The earthing method of the de-energized cable circuit is selected subsequent to the risk analysis mentioned in Sect. 2.2.1. As explained later in this chapter, there are two main ways for earthed working. Both applications should be confirmed and approved by local safety office as this may vary between countries and companies. For earthed working, equipotentiality is the most important part of ensuring safe work. Secondly, the connection to earth must be established. The earthing links and connections must be applicable to the estimated induced current, and for safety reasons, when working on conducting material, every step if possible should include two earth connections, one main earthing and one backup solution (Fig. 2.5). The purpose of an earthing system is to control the voltage. It is important to note, that there will always be an impedance between the earthing system and the general mass of earth. This is normally referred to as the earth electrode impedance or earthing resistance.

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NOT LESS THAN 1m AT ACCESS POINT METAL FRAME OF JOINTING TENT

CABLE

EARTH SCREEN

COMMON EARTH BAR EXPOSED METAL PIPE OR SIMILAR METALWORK

Fig. 2.5 Left: Example of a work place with proper equipotentiality and earthing on metal sheath using earthing leads. Right: Example of a work place where earthing is prepared for the work procedures

When a current (either induced or stray) flows through this impedance, a voltage will appear between the soil (i.e., the general mass of earth) and all conductive materials (connected to the earthing system). When this voltage exceeds the maximum allowable value, for electrical safety, one of these following solutions has to be implemented: • Reduce earthing resistance to lower the touch voltage below the maximum admissible value (rarely easy to obtain) • Reduce induced “loop current” by isolating all remote earthing connected to the conductive elements present in the work area • All accessible parts including soil are bonded together. This is easy to obtain in substations where the earthing mesh bring sufficient equipotentiality between soil and earthing system. But more difficult to obtain outside substations where a earthing mesh has to be placed on all soil accessible surfaces (ground and walls) • All accessible parts, soil excepted, are bonded together – and – personnel must be isolated from the soil (ground and walls), e.g., by using an insulation matt • All earthing connections must be able to withstand any possible re-energization The earth resistance must be controlled and designed properly with regards to all safety hazards, such as high inductive induced voltage and EPR. Furthermore, it is important to measure and check the actual earthing resistance when establishing the cable system. There should not be a difference between the actual measurements and the planned values. If it is not possible to obtain planned earthing resistance, the actual values must be used for performing new calculations. For some cases, it would be near to impossible to achieve the required earthing resistance, as it could be necessary with a resistance around and below 1 Ω or due to conditions of the surroundings. In such cases either removing earthings at both remote ends (for instance terminations in substations) and keeping equipotentiality and earthing at the work place, or insulated working can be considered.When applying earthing at the work place and removing earthings at both cable remote ends, those ends must also be secured against touching as there can be high induced

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voltage due to both capacitive and inductive coupling to the surroundings. Using this method, it would be possible to ensure touch voltage below allowed limit, even with a much larger earthing resistance at the joint bay. It is important to remember that longitudinally induced voltages will appear on all conducting connections. This also includes earthing wires and ECC, both with and without an insulation. Any work on these should therefore be carefully planned when in parallel with an UGC or OHL in operation.

2.2.2.1 Earthed Working Without Currents This method is the advised method as it protects against all sources of hazards, including currents, induced voltage, potential rise and capacitive coupling. The use of the method however, is strongly dependent on company policies on far end earthing (Fig. 2.6). The main advantage of this method is that when the current in the work place is very low (e.g., below few A only due to capacitive coupling between the cable and the ground), no dangerous voltage may appear at the working place between the soil (ground and walls) and the interconnected conductive parts. The disadvantages of this method is that dangerous voltages may occur outside the work place. In high resistivity soil at the work area, it might be difficult to obtain a sufficient earthing for ensuring safe work. An example of earthing needed in different soil resistivities, when considering the discharging current, is given in Appendix C3 of TB 801. The method requires to isolate all conductors, metallic screen, amours and Earth Continuity Conductors (ECC) at both remote ends of the section. The earthing of the cable conductive parts is done only at the work location via a local equipotential zone. With all cable conductive components connected as single point bonding, there is no risk from circulating current or EPR from the remote ends, at the working place. This method is not common in all countries and can be difficult to realize in tunnels. The offline power circuit must be protected and secured from inadvertent or accidental energization. This can be done either by physical disconnection of the remote ends from the system, or by a proper procedure involving isolation, earthing and safety documents (such as permit for work). The earthed working without currents is established by:

Fig. 2.6 Earthed working without currents: cable system with earthed conductors in the working place but not at the remote ends

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Fig. 2.7 Cable system with conductors and screens only earthed at the working area. Links within nearest two link boxes (the two on the left of the figure) are removed to ensure no earthing of metal sheaths through link boxes

• Ensuring no re-energization according to Sect. 2.2.4 • Earthing must be removed at remote ends • Internal link connections and earth connection must be removed in the two nearest link-boxes, one in each direction, as shown in Fig. 2.7. This properly breaks the screen continuity and ensures no connection to earth outside of the work place • If it is difficult to open the two link-boxes to remove the internal link connections, one needs to remove the earthing connections at all link-boxes on the cable route and at remote ends. If there are any existing earthing connections at the cable remote ends or in link-boxes along the route, this will result in the setup earthed working with currents as described in Sect. 2.2.2.2 • Induced and standing voltages at the open end has to be handled and the area has to be secured against touching • Equipotential bonding of all metal parts and the work place, to protect against any potential difference or EPR from a nearby system • There must be only one earthing connection. This is in the work place, where all metal connection must be equipotential and earthed together In some cases, it is important to be able to do simultaneous work on several joints, keeping the remote ends disconnected. Here there can occur circulating currents between the multiple work places. Similar situation will be, in the case of open remote ends, but where metal sheaths are still earthed in inaccessible link boxes along the line.

2.2.2.2 Earthed Working with Currents In this method, potential differences are controlled, but large currents can flow. All metal objects must be equipotential connected to avoid hazard due to potential differences. Furthermore, EPR from remote ends can be transferred to the work place (Fig. 2.8). The main drawback of this method is that dangerous voltage may appear at the working place between the soil (ground and walls) and the interconnected conductive parts. As a consequence, soil has to be equipotential (e.g., covered with an earthing mat) or to be isolated from the operators (e.g., isolating blankets on the walls and the floor).

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Fig. 2.8 Earthed working with currents: cable system with earthed conductors in the working place and at the remote ends

One advantage of this method is to allow for simultaneous working zones at different places along the cables. Another advantage is that the earthing connections and internal connections in link boxes do not need to be disconnected. In this method, all conductors, metallic screen, amours and ECC at both remote ends of the section are earthed. Care must therefore be taken with proper earthing bonds and connections to prevent arcing. The basic requirements of these working conditions are: • Management of higher circulating currents by suitably sized bonding tools and connections • The joint bay working area including the floor, sidewalls, and metal parts must be at equipotential. If this is not implemented, then the working zone is not safe due to possible hazardous potential differences. • The risk of possible sparking has to be considered. Sparking can occur during the connection of the core conductors and sheaths of the two cables, and when an earth connection is disconnected from a cable conductor. In this sort of situations, the most secure solution might be to switch off the parallel system(s) during the most critical working operations/steps to eliminate the risk of overheating and oxidation of joint component metallic parts.

2.2.2.3 Earthing Equipment Requirements for earthing equipment include: • The equipment must be suitable for the expected currents, including standing and short-circuit currents where applicable. • The earthing equipment shall be designed and manufactured in line with applicable national or international standards. • The user of safety equipment must have a system in place to monitor the conditions of the equipment in respect to testing and maintenance records and period in service. These records must be available for inspection before use. • In addition to the formal recorded tests, equipment must be visually inspected before each use. • The owner of the equipment is responsible for suitable storing to secure the equipment is not damaged or stolen.

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Depending of their functionality the earthing equipment can be divided into five categories as follows: 1. Equipment for earthing of the high voltage conductor at terminations. This includes both earthing for protecting against re-energization (primary earth) and for controlling voltages (drain earth) 2. Equipment for earthing within link boxes 3. Equipment for earthing metal parts during installation 4. Equipment for earthing of conductor and screen during cutting and jointing 5. Equipment for earthing of portable equipment Minimum requirement for each category are given in the below list of 1–5: 1. To earth the high voltage conductor at terminations (primary earth), long earth leads are normally required. The earth connection is applied using a long insulating pole. The pole must be suitable for the system voltage. The earth lead must have a clamp that can be applied and released using the pole. The leads and connectors are normally required to be able to withstand the short-circuit current (magnitude and duration). In some situations (e.g., when the cable has been physically disconnected from the system and re-energization is not possible), a lower category of drain earths can be used, which do not necessarily have to withstand the short-circuit current. The leads should be highly visible so that they will not be accidentally left in place or accidently removed before end of work (Figs. 2.9 and 2.10).

Fig. 2.9 Example of primary earth

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Fig. 2.10 Example of a drain earth

2. Earthing wires secured by suitable clamps or connections shall be used to earth the link terminals in link boxes. The clamps or connectors shall be provided with insulating handles (Fig. 2.11). 3. Metallic equipment (pulling wire, winch, drum support, lorry) used for cable installation should be locally equipotential and earthed. The equipment includes earth spikes driven into the ground and necessary bonding leads to make temporary earthing in the field, including sliding earthing of the pulling wire 4. To earth the cable screen and conductor during cutting and jointing earth leads with clamps or spring connectors are typically used. The purpose of the earth leads is to ensure equipotentiality of the cable screen and conductor to the potential of the working place. The leads should be flexible and sized according to the expected current. Prior to cutting cables, the metal sheath and conductor should be earthed using for instance a spiking gun or a hydraulic cutter (as explained in Sect. 2.3.3.1). The spiking gun shoots a metal blade into the cable, connecting conductor to the metal sheath. Prior to shooting the metal blade into the cable, it should be connected to the local earth. An alternative to using spiking gun, is using a hydraulic cutter followed by a metal connection into the core and sheath, such as shown in Figs. 2.12 and 2.13 5. Within substations area, it is assumed that all fixed equipment is equipotential with the local earthing mesh. Portable equipment in substations such as scaffolding, vehicles, cranes and man-lifts must also be earthed to the substations

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Fig. 2.11 Earthing connections to link terminals

Fig. 2.12 Examples of cutting cable and a hydraulic cutter

Fig. 2.13 Connection of earthing to cable with metal connection into the core and sheath conductors

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earthing mesh. For moveable equipment, the earth connections must be frequently removed and re-applied. However, these connections must be easily distinguishable from primary earthing connections, so that primary earthing connections are not disturbed by mistake. For instance, they can be in a different color.

2.2.3

Insulated Working

Insulated working is the method where the worker is insulated from contact with objects at different potentials. The principle in such working method is shown in Fig. 2.14 and an example of insulated tools is shown in Fig. 2.15. Insulated work is not the preferred solution but in some cases necessary, such as tunnels, where earth potential is far away or only available via ECC, or during specific steps of the jointing procedure. If the procedure is not according to local safety rules, it must be properly evaluated and approved by safety organizations prior to use. In the case of insulated work conditions, it is necessary that insulating tools, cloths and additional equipment must be utilized. This may include (but is not limited to) an insulating platform, mats or sheets appropriate to create an equipotential working insulated area by connecting all metallic structures which may

INSULATING SHEET APPLIED TO TENT FRAME WHERE CONTACT IS POSSIBLE

INSULATING SHEET

INSULATED PLATFORM

BRIDLING BAR

Fig. 2.14 Principles of insulated working

CABLE

INSULATING MAT

COMMON EARTH BAR

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Fig. 2.15 Examples of insulating working tools

be accessed by the operators during their activity. The choice of the protective equipment characteristics, including the defined voltage limits, depends on the type of work and allowed touch potential. Typically, the following items are used: • Insulating mat – Class 2 according to IEC Std. 61229 (2012) with a proof test voltage of 20 kV (rms) for 3 min • Insulating boots – Class 0 according to BS EN Std. 50321 (2018) with a withstand voltage test of 10 kV (rms). Type D and with FO additional requirement according to IEC Std. 20344 (2021) • Insulating gloves – Gloves made of elastomer or plastic material, class 0 according to IEC Std. 60903 (2002) with a withstand voltage test of 10 kV (rms) for 3 min; gloves with higher class may result in a difficult use for the operator due to complex handling • Insulated tools – Insulated and insulating hand tools shall be manufactured and dimensioned in such a way that they protect the user from electric shock. Reference standard (IEC Std. 60900 2018) with a voltage test of 10 kV (rms) for 3 min • Insulating sheet/blankets – Class 2 according to IEC Std. 61112 (2009) with a withstand voltage test of 30 kV (rms) for 3 min. Electrical insulating blankets shall be manufactured of elastomer, plastic, or other proper material, and produced by a seamless process. The maximum thickness is recommended 3.8 mm for elastomer type and 2 mm for plastic type; the minimum is determined only by the ability to pass the test define in the aforementioned standard All equipment shall be inspected for damage or defects before use and persons carrying out insulated working shall not accept materials from, or make physical contact with, anyone outside the insulated environment (Fig. 2.16).

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Fig. 2.16 Checking insulation glove integrity

2.2.4

Protection Against Re-energization During Work

No work should be allowed on a live system. Therefore, re-energization must be prevented properly. Examples for such work are: • Removal of a section of busbar or of cable connections from the busbar system to create an air gap between the cable termination and the switch gear or other category of equipment • Removal of cable conductor connection inside GIS • Removal of the connection from an overhead line • Use of primary earthing, locked switches and permit for work Generally, most countries have local rules for how to prevent re-energization of a system under work. These rules must be followed at all times.

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Work Procedures

This guideline briefly indicates how to manage the working procedures for installation, maintenance, repair and removal of underground cables under risk of induced voltages or rise in earth potential. The possible and relevant kinds of works are: earthing, pulling, jointing (new joints or repair), terminating, work on link-boxes for testing, searching for a fault, maintenance activities and removing cables. An underground power cable circuit when out of service may be subject to high induced voltages caused by the magnetic field from other power transmission or distribution lines running in parallel and local potential rises in case of simultaneous short-circuit event. These induced voltages and potential rises of the soil are safety hazards for workers. That is why safety precautions must be taken prior to and during the intervention. This chapter presents the different steps of how to perform the work.

2.3.1

Measuring Earthing Resistances/Earth Electrode Impedances

When measuring the earthing resistance, for instance of a joint bay, any connections (such as metal sheath, ECC, etc.) must first be disconnected from the earthing system. For measuring the earthing resistance, there are many possible methods. In a conventional method, current is injected into the electrode system under test by a current source connected to earth remotely, and the resulting rise of earth potential in the electrode under test is measured with respect to another remote earth reference. When using this method, it is important to make sure that the reference earth is not overlapping with the equipotential zone of the earthing system being tested. This will need test leads much longer than the equipotential zone, such as at least 15 times the largest diameter of the equipotential zone (Figs. 2.17, 2.18, and 2.19). Fig. 2.17 Setup for measuring earthing resistance

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Fig. 2.18 Fall of potential from an earthing electrode to remote earth

Fig. 2.19 Equipment for measuring earthing resistance

2.3.2

Cable Pulling

2.3.2.1 Cable Pulling for Cables in Open Trenches, Ducts, and HDD During the process of cable pulling, the cable must be earthed when it may be exposed to induced voltages or currents due to adjacent lines or cables under voltage.

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When it is written that the cable must be earthed, this refers to that all metallic parts of the cable should be kept equipotential by interconnection and earthed. This includes (but is not limited to) the conductor, metallic sheath and armoring of the cable as well as any ECC. The easiest way to guarantee a safe working environment for the cable installation is to use a pulling eye (at the winch side) mounted on the core conductor which is connected to all other metallic parts of the cable as well. At the drum, the cable metallic parts and winch must be equipotential and earthed as well, however at this end a proper bonding lead, such as Cu bonding, connecting all metallic parts to earth should suffice. Be aware that for some situations it might not be possible to reach low enough earthing resistance and for these situations it can be necessary to work with induced voltages. Alternatively, the pulling of the cable can be performed with one earthing point only (earthed working without currents). Any metallic part or piece of the machinery required for cable pulling must be earthed. This includes (but is not limited to) the winch (and truck), drum pay-off, steel wire, vehicles, etc. The earthing equipment should be according to Sect. 2.2.2.3. The steel frames of the pay-off installation, or drum support, of the high voltage cable drums must be earthed before the works can begin by using a proper earthing connection of sufficient size from the installation to the earthing grid or via an earthing rod. Often the cable inner end will be insulated with a cap. If possible, this cap should be kept on during pulling and a care taken to perform earthing of the cable end prior to removing it, as part of the jointing procedure in Sect. 2.3.3. Should this not be possible, e.g., during pulling in alpine areas where you must pull the cable downhill and fix the cable on the drum with a solid connection to avoid slipping, the extra cable pulling eye, mounted on the inner end, should be earthed as well to avoid any risk of discharge to the operator. This earthing should be kept in place during any reposition of the cable end after pulling operations are completed. Before the pulling operation can commence, the (metal) pulling wire must be pulled into position. Normally a non-metallic messenger rope is used for this operation (for ducts it is usually blown in). After positioning the metal pulling wire but before connecting it to the cable pulling eye an earthing connection should be attached to the metal pulling wire. Alternatively, it is possible to place a sliding earthing, such as metal chain over the pulling wire (Fig. 2.20). The cable pulling winch and connecting steel wire must be equipotential and connected to earth at all times during the cable pulling operation. Depending on the moisture content of the earth, it may be possible to use the outriggers of the winch truck as sufficient earthing for the installation itself. However, in dry environments it may be necessary to earth the installation on the earthing grid or via an earthing rod. After the pulling of the cable, before the connection to the winch is removed, a new earthing wire must be attached to the cable pulling eye, before the pulling wire is detached from the cable. After this the pulling wire may be released. It should be noted, that the pulling wire, when released, may still be under influence of induced voltages or currents.

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Fig. 2.20 Sliding Earth on pulling wire

If the cable is cut (due to surplus cable length on the drum, or during repair operations) the procedure for earthing of the cable during jointing should be followed. This procedure may be found in Sect. 2.3.3. In addition to the above one should be aware, when pulling cables within substation and for recovering situations, of the capacitive coupling from other live systems. Depending on the distance and length it may be recommended to earth the metallic parts of the cable.

2.3.2.2 Cable Installation When Ploughing Cables Ploughing techniques, or mechanical laying as it is also often named, is a cable laying method combining excavation and laying all three phases, protection tape and possibly earthing cable and fiber optic cable in a single operation with a simultaneous backfilling see Fig. 2.21 (CIGRE TB 194 2001). Normally when using this method, there is no electrical connection from the cables to the machine, however it is recommended to keep the already installed end of the cables insulated to prevent induced voltages at the working area. Even if the cable system includes a non-insulated ECC or an improved earth connection with bare copper wires, there is no risk of induced voltage on the machine, as these bare conductors are naturally earthed in the trench. When reaching the end of the cable section, this end should be either insulated or earthed, dependent on whether the far end is still insulated. In general, it should be avoided to earth both ends of the cable section.

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Fig. 2.21 Example of cable ploughing of underground cables

2.3.3

Cable Jointing

Cable jointing can be required for either newly installed circuits after cable pulling, or for existing circuits under cable repair/upgrade. The recommendations in this section is applicable to both situations. Prior to any cable jointing which is subject to induced conditions, a safety work procedure is chosen from either Earthed Working Without Currents (Sect. 2.2.2.1 – recommended procedure), or Earthed Working With Currents (Sect. 2.2.2.2), or Insulated Working With Standing Voltage (Sect. 2.2.3). Where Earthed Working Without Currents (Sect. 2.2.2.1) can be achieved, all the conductive parts inside the work zone are equipotential and locally earthed at all times during the work. There is no need of insulating tools as all the conductive parts are interconnected and earthed locally inside the work zone. Where Earthed Working with Currents (Sect. 2.2.2.2) is adopted, safety work procedure on live systems shall be enforced (e.g., appropriate insulating tools). Besides the hazards associated with circulating current (e.g., heat), unexpected potential difference may develop between the earthed conductive part and surrounding objects (e.g., trench wall) as the circulating current can flow through the earth in between causing a dangerous potential difference. For instance, only 8A current where the earthing resistance is 20 Ω, will result in a touch voltage of 820 ¼ 160 V. To eliminate these associated hazards, sufficiently sized earthing links/wires shall be used to reduce the heat loss from circulating current, and additional equipotential zone can be established inside the work zone. Where temporary Insulated Work with Standing Voltage (Sect. 2.2.3) applies, safety work procedure on live systems shall be enforced (e.g., appropriate insulating tools) because local earthing is not available or impossible to achieve. Although Earthed Working Without Currents is recommended here, it is understood that this work procedure has not been adopted in some countries, where the other two procedures are adopted as alternatives. To implement Earthed Working Without Currents as recommendation, all the conductive parts inside the work zone are to be equipotential and locally earthed at all times during the cable ends preparation. For operations where the earthing needs to be temporarily removed, Insulated Work with Standing Voltage or a safe work

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procedure for live systems are to be enforced (e.g., appropriate insulating tools), until Earthed Working Without Currents is reinstated. To illustrate the necessary Health and Safety precautions during cable jointing activities, a jointing example based on the recommended Earthed Working Without Currents procedure is explained below, when using one-piece slipover pre-molded joint. Generally, cable jointing consists of following four stages: 1. 2. 3. 4.

Cable ends preparation Joint components parking (if applicable) Conductor connection Joint completion

In Sects. 2.3.3.1, 2.3.3.2, 2.3.3.3, and 2.3.3.4, focus is given onto the key earthing requirements throughout the above four stages and are applicable for various joint types in principle under Earthed Working Without Currents. In case of paper laminated insulation, the insulation can be reconstructed using proper PPE and the insulated work method (Sect. 2.2.3). Please always refer to relevant manufacturer manuals/instructions or national specifications for a comprehensive jointing procedure.

2.3.3.1 Cable Ends Preparation The cable ends need to be appropriately prepared before the conductor connection. To prepare cable ends after pulling during installation, following specific precautions are recommended to be considered: (a) If not already realized the pulling eye shall be earthed (b) If no other local cable earthing exists, all the cable conductive parts (e.g., SC layers, metallic screen, conductor) shall be preliminarily earthed using a earthing spike (c) Once all the cable conductive parts are preliminarily earthed through spiking, the cable end can be properly prepared by layer-by-layer peeling (d) During the layer peeling, each conductive layer (e.g., oversheath SC layer/ coating, metallic screen, intermediate SC layers, conductor) shall be properly earthed, before removing the layer underneath (e) Once all the cable conductive parts (e.g., SC layers, metallic screen, conductor) are properly earthed (Fig. 2.22), the spiked cable section can subsequently be removed To prepare cable ends after cutting during repair/maintenance/upgrade, following specific precautions are recommended to be considered: (a) If no other local cable earthing exist, all the cable conductive parts (e.g., SC layers, conductor, metallic screen) shall be preliminarily earthed using a earthing spike on both sides of the damaged cable section

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Fig. 2.22 Cable spiking and conductive layer earthing (before removing the spiked section)

(b) The damaged cable part can subsequently be removed using earthed cutting tool (c) Once the damaged cable section in the middle is removed, the two resulting cable ends (with one earthing spike each) shall be separately prepared by layerby-layer peeling following the same precautions as for cable ends after pulling during installation (d) Before removing the spiked cable section, all the conductive layers of the two cable ends shall be properly earthed (Fig. 2.23)

Fig. 2.23 Properly earthed cable ends with earthing wires (after removing the spiked section)

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2.3.3.2 Joint Components Parking (If Applicable) For joints, further cable end preparation process is required to park joint components (e.g., joint main insulator, metallic protection casing, etc.) before the conductor connection. The process exposes the cable insulation a length back from the conductor jointing point by removing associated outer layers (e.g., metallic screen, oversheath, etc.), and park slipover joint components before the conductor connection. During the joint components parking, following specific precautions are recommended to be considered: (a) Any metallic tool used for layer peeling and removing shall be locally earthed (b) Before removing the oversheath and metallic screen length (incl. associated earthing wires shown in Fig. 2.23), a second earthing point for the SC oversheath layer/coating (if applicable) and metallic screen shall be made through local oversheath peeling and removing (Fig. 2.24) at a designated length away from the conductor jointing point (Figs. 2.25 and 2.26) Fig. 2.24 Establish the second cable screen earthing point at a designated length away from the conductor jointing point

98 Fig. 2.25 Oversheath and metallic screen removal

Fig. 2.26 Completion of insulation exposure and layer peeling

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(c) During the joint components parking, the cable conductor earthing wire might be temporarily removed. Insulating tapes shall be applied to wrap the exposed conductor before removing the earthing wire, and insulating conductor expansion cone shall be applied immediately after removing the earthing wire (Figs. 2.27 and 2.28)

Fig. 2.27 Conductor insulating tapes and expansion cone

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Fig. 2.28 Main joint insulator parking

2.3.3.3 Conductor Connection Once joint components parking is completed, the two cable conductors will be connected using a conductor connector in various forms (e.g., screwed connector, compressed connector, welded connector, etc.) During the conductor connection, following specific precautions are recommended to be considered:

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Fig. 2.29 Conductor connector installation and earthing transfer

(a) When conductor insulating tapes and expansion cone are removed, local conductor earthing shall be reinstated before the connector placing (b) All the required connector and tools shall be placed on the cable without interrupting the existing earthing of the cable conductor, screen, and SC layers before installation (Fig. 2.29)

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Fig. 2.30 Various connector types and earthing illustration

(c) Once the connector is in contact with the two cable conductors, the local conductor earthing can be transferred onto the connector (wrap around it, for example, Fig. 2.29) (d) A local earthing connection shall be always retained for the connector and the two connected conductors before pulling back the joint main insulator (Figs. 2.30 and 2.31)

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Fig. 2.31 Conductor connection completion

2.3.3.4 Joint Completion After conductor connection, the pre-parked joint main insulator is firstly fitted to its final position by pulling back over the connector (Fig. 2.32). Subsequently, metallic protection casing is normally installed outside the joint insulation body, and the whole object is subsequently enclosed by a non-metallic joint shell. During the joint completion, following specific precautions are recommended to be considered:

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Fig. 2.32 Joint insulation body back pulling and fitting

(a) The cable metallic screen local earthing shall be retained while the joint metallic protection casing is slipped over it (if applicable). One way of doing so is to keep the earthing of joint metallic protection casing, directly connect cable metallic screen to the casing, and then remove the individual screen earthing (b) For a sectionalized joint with cable screen interruption (for cross bonding purpose as an example), an insulation ring is placed between the two joint metallic protection casings in connection, and the casing earthings are replaced by two bonding leads before applying a final non-metallic joint shell (c) For non-sectionalized joint with cable screen continuity, either the two joint metallic protection casings are in direct contact without insulation ring in between or a direct link shall be installed across the insulation ring

2.3.4

Terminations

All steps and earthing requirements described in Sect. 2.3.3 are also valid during the installation of cable termination. When working on cable terminations it is important not only to consider the hazards within the cable system but also those generated by the item of equipment that the cable is being connected on to, for example overhead lines or earth systems, as these may also introduce other hazards to the work. Furthermore, when earthed working with currents, all metal tools and scaffolding must also be properly earthed. Although this chapter presents the hazards and normal

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earthing requirements for different types of terminations, the termination manufacturers procedures must be followed correctly. For all types of terminations, mentioned in this chapter, parallel systems should be shut down if possible when a cable system has to be connected toward an overhead line or a busbar. All conducting parts such as cable conductor, cable metal sheath, cable armor and overhead line or busbar have to be earthed at the working side only, to allow earthed working without currents. If the cable system is within an internal substation system, it is possible to have the same earthing network at both ends of the cable system. In this case, all conducting parts can be earthed at both ends and having the same earth potential. Prior to starting the termination work, the cable ends are recommended to be prepared in a similar manner as described in Sect. 2.3.3.1.

2.3.4.1 AIS Terminations Before the AIS termination can be connected to an overhead line or a busbar, the cable metal sheath should be connected directly or via link box toward Sheath Voltage Limiter (SVL) or earth potential depending on the system layout. The metal sheath should never be kept floating without any SVL (Fig. 2.33). 2.3.4.2 GIS Terminations At connections of cable systems toward GIS several different constructions are possible: • Oil filled and non-pluggable cable termination at a GIS which has an additional opening at the area of the connection to the busbar inside. Using this additional opening, the termination can be earthed during the complete installation. • Oil filled and non-pluggable termination at a GIS which does not have an additional opening at the area of the connection to the busbar inside. The connection is screwed to the head armature of the termination and afterwards

Fig. 2.33 AIS termination connected to overhead line (on the left) and to busbar (on the right)

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U. S. Gudmundsdottir

connected to the busbar by a clamping construction. The head armature of the termination has to be earthed as long as possible. The connection to earth potential has to be removed from the head armature before the connection to the busbar is realized. In such case the other end of the cable system must be earthed, and if possible, connected toward the same earth potential as the GIS busbar. Due to induced voltages a potential difference between the cable conductor and the busbar can occur leading to a small internal arc just before the contact is realized. If any, the internal arc happens inside an encapsulated area and is of no danger for people or other equipment, but the contact resistance may increase. • Dry termination plugged inside its socket which is already mounted inside the GIS. During the plug-in process the connection to earth potential has to be removed from the conductor before the connection to the busbar is realized. In such case, the other end of the cable system must be earthed, and if possible, connected toward the same earth potential as the GIS busbar. Due to induced voltages, a potential difference between the cable conductor and the busbar can occur leading to a small internal arc just before the contact is realized. If any, the internal arc happens inside an encapsulated area and is of no danger for people or other equipment, but the contact resistance may increase. Dry pluggable termination can also be installed using the conventional way of non-pluggable terminations. The cable metal sheath should be connected directly or via link box toward SVL or earth potential depending on the system layout.

2.3.4.3 Transformer Terminations All connecting methods for GIS are also valid for transformer terminations. But in most cases transformer connections are screwed connections to a busbar which is mounted after the final installation of the termination into the transformer and are sometimes covered by corona shields. During the complete installation all conducting parts have to be connected to the same earth potential. The cable metal sheath should be connected directly or via link box toward SVL or earth potential depending on the system layout. When a cable system has to be connected on one side to a GIS and on the other side to a transformer it is recommended to start with the GIS side as the GIS can be solid earthed if necessary.

2.3.5

Work on Link Boxes

Link Boxes are major elements of bonding systems of high voltage (HV) and extrahigh voltage (EHV) cable circuits. They are designed to operate under the same environmental conditions as the cable system; i.e., direct buried or in underground enclosure, tunnels, underground vaults, or in above ground cabinets and other specially allocated places. Depending on the position within the cable bonding architecture, most link boxes are provided with SVLs connected to the link boxes

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removable links which, in turn, are connected to the cable metallic sheath or screens via the link cables. Link boxes cannot be considered individual elements in a cable bonding system because they incorporate the interfacing system components such as: SVLs, bonding lead terminations, removable links, inner and outer earthing connections, and, possibly, other devices such as High Frequency Current Transformers (HFCT) or Optical Fiber (OF) sensors. Work or testing on any element of the cable bonding system or link boxes in live systems should never be allowed. This is due to the following risk factors: • Transient overvoltages due to switching and lightning surges propagation on the cable system including link boxes and SVLs • The switching surges which are of a longer duration than the lightning surges could be followed-up by power frequency currents which may determine the failure of SVLs due to thermal instability and, as a result, risking the safety of the personnel working on that piece of equipment • Furthermore, the operator working/testing the link box components could be exposed to induced voltages in excess of permissible values, should a cable fault take place while the earthing leads would be detached The following work procedures, relates to work on link boxes, in a circuit out of service, but with a possible risk of induced voltages from nearby circuits still in service. Until proper earthed conditions have been established, fitting or removal of disconnecting links, SVL connections or Bonding Connections must be carried out using Insulated Working procedures. When link boxes are installed outside the substation earthing grid, the soil may not have the same potential as the locally earthed elements. So the operator has to insulate himself from the soil or build up an equipotential area, in order not to be exposed to induced voltages. In some cases, the housing of a link box may be connected to a local earth and not connected to the earth associated with the cable sheaths. Before work is carried out on the cable sheath disconnecting links and SVL connections in these link boxes, the two earths must be connected together using Insulated Working procedures. In link boxes not fitted with special connecting points for the attachment of Bonding Connections it may be necessary to adjust or remove the links prior to the fitting of Bonding Connections. This must be done using Insulated Working procedures. Where the facility exists, link boxes should be locked after each operation and an approved notice attached. This notice must not be removed until work has been completed, the links returned to the normal operating position and the box finally locked (Figs. 2.34 and 2.35). As previously explained, in general, the circuit is taken out of service during maintenance works with link boxes. In some countries, though, there are two exceptions for measurements of metal sheath currents, either in special link boxes with sensors or directly on the link cable.

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Fig. 2.34 Handling of a non-energized link box before achieving local earth

Fig. 2.35 Example of work on link boxes

The following steps describe the opening of the link-box to start with work (maintenance, repair, installation, etc.). • Check you are working on the switched off system • Opening of the outer cover and inner cover (if existing) by use of insulated working • It is recommended to measure if there is still induced voltage or/and current on the links to be able to adapt the working procedure accordingly • Set the proper earth connections before opening the links by use of insulated working. It is also recommended to keep the local earthing side of the removable link connected, also when opening the link from the cable screen side • Disconnect the SVL

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2.3.6

109

Cable Testing

When performing tests on cables, special attention must be given to the induced voltages or currents. Some tests imply applying voltage or current on the conductor or on the metallic sheath. Therefore, when preparing the cable for the test, preventive actions are needed: e.g., disconnect the cable from the network, earth on both ends, remove some of the earthing, manipulate link boxes (including SVLs), etc. While connecting and disconnecting test equipment to cable metal parts, in the presence of other circuits in service, induced voltage and currents can appear. Following precautions must always be taken: • Due to induction, the circuit must be earthed at the point of work while connections are being made or removed • The links and terminals within the link box must be treated as subject to induced voltages. Precautions to be taken include: – Temporarily earthing the link terminals with temporary earthing clips before handling them – Using insulating tools and gloves – Using a test instrument which automatically discharges the test voltage on completion of each test or – Allow enough time for the automatic discharge, followed by earthing with a temporary earthing clip before handling • It is sometimes possible to plan the sequence of operations to minimize the risk. For instance, when testing a section which is earthed at one end and protected by SVLs at the remote end: – Disconnect the earth links at the earthed end – Go to the SVL-protected end, temporarily earth the cable sheath terminals and disconnect the SVLs – Test each phase in turn from the SVL-protected end, with the remaining phases earthed, again earthing each phase on completion – Re-fit the SVLs, then remove the temporary earths – Return to the earthed end and re-fit the earth links • On completion of voltage tests, the voltage must be discharged and it must be considered that there are return voltages for a certain time depending on the type of cable and the level of the test voltage (especially after testing with dc) The same precautions must be adopted when using fault location techniques as they imply applying voltage or current to the HV terminal or metallic sheaths. In case of manipulating link boxes, precautions must be adopted as induced voltage or currents could appear. Detailed precaution for some individual tests can be found in Appendix C.

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U. S. Gudmundsdottir

Removing Cables

The removal of cable line may be necessary in some circumstances. For example, the installation of new cable lines in the same authorized route due to space limitations and authorization difficulties or environmental constraints. Considering that in most cases cable removal occurs at the end of life, following description is based upon assumption that the cable will not be re-used and then discarded after recovering recyclable materials such as metal parts. In order to describe the activities and precautions necessary to safely remove a cable line under induced voltages, a typical installation scenario has been considered such as a cable line connecting two electrical stations (cable line 1) with the presence of parallelisms along the route (cable or overhead line in service – line 2 and 3 Fig. 2.36). The following procedures can also be used for other installation scenarios such as mixed lines, etc. However, it should be noted that each situation shall be individually evaluated considering geometrical configuration of the cables, lengths of parallelism, current levels, etc. The magnitude of induced voltage depends on previously mentioned parameters. The cable line to be removed is initially earthed at both ends according to IEC Std. 50110-1 (2013) requirements. Before starting any activities on the cable, it is recommended to disconnect both ends of the line from earthing system of electrical stations and short-circuit together conductor and metal sheath/armor or other metal parts in order to avoid any potential difference between conductor and metal sheath generated by capacitive coupling. The area must be inaccessible as hazardous potentials may arise on metal parts under influence of adjacent lines; these potentials are proportional to the parallelism length of cable to which it is necessary to operate (Fig. 2.37). In this configuration, the circuit is isolated from electrical stations and the transfer of hazardous potentials at the working area (EPR) through the conductor/metal sheath/armor is avoided, especially in the event of a failure in a substation. In case of not being able to isolate the ends the situation shown in Fig. 2.38 will appear. For this situation a potential difference represented by EPR UEA and UEB transferred to the workplace, could be present between the two cut sections. Cable line 1

Substation A

Substation B

Area of parallelism

Cable line 2 in service

Cable line 3 in service

Substation C

Fig. 2.36 An example of network with parallel lines

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Substation A

Substation B Earthing system B

Earthing system A Cutting section

Earthing of metal parts at cutting point

Fig. 2.37 Circuit with both ends isolated from substation’s earthing system

UEA≠UEB Substation A

Substation B Earthing system B

Earthing system A

Cutting section

UEA

UEB UEA≠UEB

Fig. 2.38 Circuit earthed at both ends

For the same reason, it is advisable to disconnect cable metal sheath and any other connections from the earthing system of joint bay along the route. In particular, if the cable to be removed (Line 1) is placed next to another in service (Line 2) with metal screens connected to the same earthing system, it is necessary to interrupt the continuity of the screens and disconnect them from the common earthing system. Potential difference of some kilovolts could be transferred to metal screen of Line 1 in case of failure on Line 2. To do this, bonding leads have to be cut with adequate protective devices such as gloves and insulating mat (see Sect. 2.2.3). Obtaining the configuration of Fig. 2.37, attention must be paid only to the induced voltage due to the presence of other cable or overhead lines in the vicinity. Before proceeding to work on the cables to be removed, these must be uniquely identified. The cable with floating potential has to be cut into minor sections for subsequent removal. The cutting must be executed with appropriate protective insulating devices such as gloves and insulating mat, as possible discharges may occur during cutting operations. As a precaution, an earthing conductor could be used to earth cable at both sides of cutting point before cut it; this also allows safely the subsequent handling of the two sections just cut. The connection of earthing conductor to cable can be made, for example, drilling a hole in the cable or using a nail (see Fig. 2.13); during this work protective insulating devices must

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be used. After cutting the cable, metal parts of the two cut sections must be earthed at the workplace. In particular, the pulling head are recommended to be installed keeping cable earthed all the time; if this is not possible, insulating gloves have to be worn. The other end of the cable, at a distance that may vary from a few meters up to a few hundred meters depending on the recoverable length, must be insulated using an insulating hood in order to prevent any touching and to permit the pulling out from trench or pipe. The pulling head is then connected to the winch that has to remain earthed during pulling operations. It is also advisable to consider possible voltage that may arise between the pulling head (earth at the workplace) and the winch wire at the moment of the connecting the pulling head. Before connecting the wire and during the cable removal operation it is recommended to place a metal chain or wire over this (winch) wire in such a way that the pulling wire is dragged along this metal chain or wire. Once the cable has been retrieved outside the trench or pipe, it can be cut into smaller sections or wound onto a drum for transportation. Before the connection to the (winch) wire is removed, a new earthing wire must me attached to the cable end, before the (winch) wire is detached from the cable. In case the cable will be rewound onto drum, handling must be done keeping cable end and drum earthed. Even if short cable sections are handled, it is recommended to perform the removing using the method described above, as in reality many scenarios may arise. It is therefore always appropriate to act as indicated above and according to the points summarized below. 1. Avoid transferring potentials to working area through metal parts (conductor, screen, armor) of cable line object to removal; to meet this requirement, the line must be physically disconnected from earthing systems to which other power lines are connected. 2. Earth at working area or make any metal part of the cable inaccessible; if that is not possible, handle the cable with protective devices such as gloves and insulating mat. 3. Earth machinery and equipment (i.e., winches, drums, etc.) during all operations. It is important to remind that induced voltage linearly decrease by reducing the length of parallelism.

2.3.8

Working Procedure in Special Conditions

2.3.8.1 Installation and Repair in Tunnels Increasingly cable systems are being installed in tunnel systems containing multiple circuits. Tunnel systems pose a more difficult problem due to the nature of most tunnels being sealed structures, it is not always possible to achieve local earthing (Fig. 2.39).

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Fig. 2.39 Example of cables in a tunnel

On all works in tunnel, national laws, security and evacuation regulations and the safety regulations of the contractors have to be considered, as well as any fire hazards inside the tunnels evaluated. Before starting each work, a working agreement between utility and contractor about the present situation in the tunnel has to be executed. In this agreement all parties must be informed about energized systems, the expected level of magnetic field and working conditions. Employees of other companies having utilities in the tunnel must also know and be trained about the behavior in case of emergency, in the handling of the security equipment and the way to the next emergency exit. This chapter will only focus on safety hazards due to induced voltages. However, many countries do not allow cable pulling, repair, jointing, or other work to be performed in a tunnel, unless all systems in the tunnel are taken out of service. It is therefore advised in general, not to work in tunnels with cable systems in service due to unforeseeable cable and joint faults. If this is not feasible, then the precautions in this chapter must be considered. Principles of safe work, work procedures, and earthing methods of previous chapters are applicable also in tunnels, but additional attention has to be given to ensure proper local earthing at the working site. For example, it can be necessary to bring in a temporary earthing conductor. However, special awareness has to be given to this conductor by applying the same precautions as cable pulling regarding induced voltages. On shorter parallel cable length in tunnel, considering the earth resistance, earthed working with currents can be sufficient. On longer cable length the safest work condition might be earthed working without current by earthing the working area and isolating the cable system anywhere else. In case of working with no current, earth can be achieved by connecting to local metal structures in the tunnel system. For cables with semiconductive outer layer, there may be a small risk of electrical shock when touching the cable simultaneously with a fault happening on the HV network to which this cable system is connected. This risk is only real if the cables

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Fig. 2.40 Tunnel installation

have large conductor cross sections (more than 630 mm2) and the cable installation is in a touching trefoil configuration, as shown in Fig. 2.40, and the metal sheath voltage is above 5 kV. A summary of case studies for different cable sizes and cable layout is given in Table 2.4. To reduce the risk of electric shock from outer semiconductive layer in Table 2.4 Risk for electric shock from an outer semiconductive layer in tunnels, during HV fault (clearing time 250 mS)

Cable 90 kV 630 mm2

225 kV 1000 mm2

Semicond. linear resistance 300 Ω/m

300 Ω/m

3 kΩ/m

Cable layout Vertically separated cables Touching trefoil

Touching trefoil

Semicond. earthings None

Maximum allowed sheath voltage for electrical safety 12.5 kV

None Every 200 m Every 100 m None Every 200 m Every 100 m None

5.5 kV 12.6 kV 35 kV 4.2 kV 6.4 kV 17.6 kV 9.5 kV

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tunnels, it is possible to earth the outer cable sheath for instance every 100 m, by using metal cleats when tightening and attaching cables to the wall and earthing structure in the tunnel. 2.3.8.1.1 Cable Pulling in Tunnels During the process of cable pulling in tunnel or galleries, several parts of the cable must be earthed when they may be exposed to induced voltages or currents due to adjacent lines or cables under voltage. In this chapter a description will be given concerning the earthing of the cable during cable pulling with machinery in tunnels or galleries. Earthing the cable always means that all metallic parts of the cable should be commonly earthed. This includes (but not limited to) the conductor, the metallic sheath, armoring of the cable, as well as any ECC. The metallic pulling wire will be touching the rollers used along the cable route for installation. Earthing of rollers can be achieved by connecting them to the supporting steel structure if it is properly earthed. If this is not possible the rollers can be kept insulated from earth. A continuous temporary earthing wire will mostly circulate the same induced voltage as the metallic pulling wire. During the pulling, the cable outer sheath will be touching the earthed rollers. This ensures there is no capacitive charge on the outer semi-conductive layer or graphite during installation. It normally is sufficient to earth one roller at each side of the tunnel to achieve a sufficient discharge of the cable outer sheath. Not always all rollers inside a tunnel can be properly earthed. The end of the cables on the drum must be isolated avoiding any possible direct contact with them. In cases where this is not possible, e.g., during pulling in alpine areas where you must pull the cable downhill and fix the cable on the drum with a solid connection to avoid slipping, the drum and inner end of the cable on the drum must be earthed. Prior to removing the inner cable end from the drum, after cable pulling, the inner cable end must be earthed. This earth must be kept on during any repositioning of the cable. In this situation, one would be aware that the pulling method is now being done as working with currents and in such a case, touch voltages may arise between metallic parts and the earth. Precautions, as mentioned in Sect. 2.3.2, should be followed. The conductor and the screen are electrically connected through the pulling eye and they are also connected with pulling wire which in turn is earthed through the rollers and winch at cable end. It is recommended not to touch the pulling eye away from the earthing point (pulling station) with bare hands. Use sufficient insulating gloves instead. Cable pulling in general should be done similar as described in Sect. 2.3.2. 2.3.8.1.2 Jointing in Tunnels Jointing work can either be done by working with standing voltage (insulated work) or by earthed work (with or without currents). In the case of earthed working method with currents, care must be taken to the quality of the earthing point as local earthing is not always possible in tunnel systems. It might be necessary to use a temporary

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ECC to ensure proper earthing point in the tunnel. However, it should be noted, that induced voltage will also appear on this earthing connection, for the length of the parallel section. In this case all precautions for insulated work has to be taken and special care should be taken at the transition from the equipotential work zone to the tunnel outside. The jointing work in general should be done similar as described in Sect. 2.3.3.

2.3.8.2 Installation and Repair Offshore During installation of offshore cables, both three phase and single core cables, the surrounding water will at all times give perfect earthing conditions. Furthermore, there will not be any direct connection to the metal parts of the cable during the installation procedure. In the case of very long offshore cables, where there is a need for an offshore joint, made on the vessel or barge, there might be a situation where care needs to be taken due to possible induced voltages. For instance, for wind farm connections, there are examples of export cables of several tens of kilometers, or even more than 100 km, which are installed in parallel with other offshore wind farm connections in service with less than 1000 m lateral distance. Furthermore, there are examples of very long export cable connections to offshore wind farms, where more than 1 export cable is used in parallel for connecting the same windfarm. In such cases, both the jointing program, termination and repair procedures must be carefully evaluated, as it will most often not be possible to apply for disconnection of another wind farm, and preferable to keep production transmitted through a healthy cable in a system of two or more cables connecting one windfarm. Whenever installing a joint or termination offshore, it is recommended to work with currents and keep earthing of all metal parts at all times. This includes core, metal sheath, metal armor and any metal part in fiber optic or fiber optic tube. This is due to the fact that the vessel or platform are steel structures with good connection to water, providing almost a perfect equipotential earth. For very long cables, it is possible to disconnect cores at each cable end, and earth at the repair/jointing area. This method is however not recommended, as the metal sheath and armor will have continuous earthing which will cause a voltage difference between core and metal sheath/armor. As for onshore cables, first the size of the induced voltages and currents should be calculated prior to commencing any work, according to Sect. 2.4. Normally there would be no OHL in the vicinity and the water connection provides almost a perfect earth, only making the inductive induced voltage of interest. However, in the case of EPR in an onshore substation, where the metal screen is already connected, this EPR can be transmitted to the place of work, as explained in Sect. 2.1.4, unless the offshore cable metal screen is already earthed properly at a transition joint (between offshore and onshore cables). When calculating the

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Fig. 2.41 Working on a submarine cable, similar to normal jointing preparation as described in Sect. 2.3.3.1

inductive induced voltages, it is important to include the entire cable length already installed and jointed. Therefore, if an offshore joint or termination is the last jointing work to be done, and the transition joint is already in place, then the combined onshore and offshore parallel cable length must be included in the calculations. Should the level of either inductive induced voltage or EPR become higher than voltage limits, the jointing or termination procedure must ensure proper earthing of all metal parts at all times. This includes possible bending restrictors, offshore joint casing, metal armor, metal sheath, cable core, metal tube, and/or armor of fiber optic cable, termination scaffolding, and any metal support structure used at the jointing and termination site. The work should in all other aspect be done according to Sect. 2.2.2.2, using the earthed working with currents method. In repair situation, or when the submarine cable is already connected to the underground cable, to avoid excessive induced voltage on the core conductor, the far ends of the core conductor should be disconnected and isolated, while the local earth is kept. In this case, one needs to be aware that the metal sheath and armor are earthed continuously through the sea water, while the core conductor is not. This is especially important for submarine cables connected with land cables, as the induced voltage will appear due to parallel lines with the land part of the cable connection (Fig. 2.41). As a special case for submarine cables, it should be noted, that the semiconductive outer sheath of the single core cables and the metal sheath will always have a earthing connection through seawater, as the fillers of the three phase cables are filled with seawater. It is therefore also possible to earth the cores by connecting these points, as shown in Fig. 2.42.

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Fig. 2.42 Earthing connection of the three cores through the metal sheath and outer semiconductive layers. The earthing connections are attached with screw connection

2.4

Method of Calculation

As described in Sect. 2.1, there are three types of coupling between systems which can be categorized as potentially dangerous due to induced voltages. These are: Inductive coupling, capacitive coupling and conductive coupling. To ensure safe working and to know which type of work procedures to use, as well as to have knowledge of critical voltages, it is important to calculate the induced voltage levels, prior to starting any work. In this section the calculation methods for the three coupling types are explained. The first section is about inductive coupling. It is shown how screening from other earthed parts (metal sheath, ECC, other cable cores) reduce the voltage levels due to inductive coupling. The second section is about capacitive coupling. The calculation method of capacitive coupling is shown for a simple system and it is explained how the method can be expanded to a more complex multi conductor system. The third section is about conductive coupling, where it is explained how rise of potential from conductive coupling can be calculated.

2.4.1

Inductive Coupling

As described in Sect. 2.1.2, the amplitude of the induced voltage depends on the current in the system in service, the distance between the system in and out of service and the parallel length of the two systems.

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The longitudinally induced voltage can be calculated using Eq. 2.1 U i ¼ Z 12  I

ð2:1Þ

Where: Z12 I

is the mutual impedance between the two conductors is the inducing current, of the cable/OHL in service

It is important to note, that Eq. 2.1 does not include the screening factor of other metallic parts, such as the metal sheath or other cables. Therefore, the induced voltage based on Eq. 2.1 will always give the worst case scenario for induced voltage. If the calculated induced voltage based on this will be below allowed induced values, no further evaluation is needed. However, if the calculated results are too high compared to allowed values, it is possible to have a look into the more detailed setup of the system and analyze the actual screening factors. As shown in Fig. 2.43, the metal sheath, when giving a closed earthing loop, of each cable (as well as other earthed metal parts) will have a screening effect on the inductive coupling. The induced current in the earthed metal parts, will cause an opposite magnetic field, which will reduce the induced voltage of the cable out of service. The size of this reducing current is depending on both the earthing and connection resistance and the resistance of the earth. The larger these resistances, the less screening effect the earthed metal parts have. In the case of single point bonded systems, there is no closed earthing loop. Therefore, this screening effect is not existing. However, single point bonded systems are normally only for shorter cable systems, which will have shorter parallel distance and hence lower induced voltage. For an ECC to give a screening effect, it is important it is intact. Therefore, when installing an ECC or when performing maintenance work on the ECC a continuity test should be done.

Fig. 2.43 Screening of the longitudinally induced voltage when the screen forms a closed loop

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Fig. 2.44 Change in the magnetic field will cause a current in the nearby earthed metal parts which will cause a reduction of the change in magnetic field. In this figure, BSC is caused by a short circuit current on a cable in service, Bind_s is caused by the induced current in the metal sheath and Bind is caused by the induced current in nearby earthed metal parts (U. S. Gudmundsdottir 2010)

AC circuits, by their sinusoidal nature, generate magnetic fields. The induced current in nearby earthed metal parts is based on Lenz’s law. The change in the magnetic field around a conductor (for instance due to normal operation or short circuit fault current), will induce currents in nearby metal parts, which will work to reduce the increasing magnetic field (Fig. 2.44). The induced current in the cable which is out of service can be calculated using Eq. 2.2. ZS  I inds þ Z Sind  I ind ¼ Z coreS  I SC ZindS  I inds þ Zind  I ind ¼ Z coreind  I SC )

I inds I ind

¼ I SC 

ZS

ZSind

ZindS

Z ind

1



Z coreS

ð2:2Þ

Zcoreind

Where: Zs Zcores Zind Zinds ¼ Zsind Zcoreind

is the series impedance of the metal sheath is the mutual impedance between conductor and metal sheath of the cable in service is the series impedance of the out of service cable is the mutual impedance between metal sheath and cable out of service is the mutual impedance between the cable in service and the nearby cable out of service

The series impedance of the earthed metal parts (such as metal sheath) includes the earth and earthing resistances, as is shown in Eq. 2.3, U. S. Gudmundsdottir (2010) and CIGRE TB 531 (2013)

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Zs ¼ Re1 þ Re2 þ l  Rr þ Rs þ j Zcores

121

ωμ0 De ln 2π rs

ωμ De ¼ Re1 þ Re2 þ l  Rr þ j 0 ln 2π d cores

Ω ð2:3Þ Ω

where: l Rr Rei RS μ0 De rs dcore  s

is the parallel length in m is the resistance of the earth is the earthing and connection resistances at end i. is the series resistance of the metal sheath is permeability of vacuum, 4π  107 is the Carsons equivalent depth is the radius of the metal sheath is the distance between metal sheath and conductor

Other series and mutual coupling impedances are calculated the same way. If the system has an ECC or is solid bonded, then the largest part of the current will go through the ECC or metal sheaths of the other cables. In this case, the calculations can be simplified by including only those parts and neglecting the earth return. When the metal sheath is included as a screening factor, the induced voltage can be calculated by using Eq. 2.4. It should be remembered that the size of the screening current is related to both the earthing and earth resistances. V ind ¼ Zcoreind  I core þ Zinds  I s

ð2:4Þ

where: Icore ¼ ISC Is

2.4.2

is the short circuit (fault) current is the current induced in the metal sheath

Capacitive Coupling

An unearthed cable in an electric field, e.g., laid in parallel to OHL, will be charged with potential. The phenomenon simplified could be explained using capacitive division: V2 ¼

C1 V C1 þ C2 1

Where: V2 V1 C1 C2

potential of metal sheath potential of overhead line capacitance between overhead line and metal sheath stray capacitance from metal sheath to earth

ð2:5Þ

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Naturally metal sheath potential V2 increases with higher V1 and C1 values, however is reduced by stray capacitance C2. In realistic conditions C1  C2, such as where a cable is exposed to E-field under OHL during parallel installation. At the instance when a person touches the metal sheath, C2 is discharged through the resistance Rh which is a sum of resistances of human body, shoes and protective gear such as gloves. A superimposed current would flow through Rh comprising two current components; (1) a transient discharge current component Idis from C2 within RhC2 circuit following an exponential decay; (2) a constant capacitive current component Iconst due to capacitive coupling through C1 to OHL (Fig. 2.45). The realistic case with a three phase overhead line must be treated as a multiconductor system considering all partial capacitances. A simplified method for calculation of the capacitive coupling is as follows. The constant current component Iconst can be calculated based on electric field strength E at location of the object and the equivalent area of the object, S: I const ¼ jωe0 ES

ð2:6Þ

where ω ¼ 2πf is angular frequency. Electric field strength, E, under OHL can be conveniently calculated using using e.g. method of images or maybe it is already known from actual measurements for specific towers. When cable is laid on the ground, the equivalent area, S, of the cable of the length L with metallic screen radius rs, can be approximated as a half-cylinder (excluding end effects) on a ground plane: S ¼ 4r s L

ð2:7Þ

Where the cable is lifted above the ground, e.g., on rollers, the equivalent area, S, of a cylinder with center line at a height h above ground could be used for the case: S¼

Fig. 2.45 Simplified circuit of capacitive coupling

2πh ln

2h rs

L

ð2:8Þ

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123

The stray capacitance, C2, from metal sheath to earth can be calculated according to the following: C2 ¼

2πe0 ln

2h rs

L

ð2:9Þ

And floating potential of cable metal sheath, V2, becomes: V2 ¼

I const jωC2

ð2:10Þ

Finally, the discharge current can be calculated according to the following: I dis ðtÞ ¼

2.4.3

V 2 RhtC2 e Rh

ð2:11Þ

Conductive Coupling: Rise of Earth Potential

As it was described in Sect. 2.1.4, fault currents flowing through the earthing electrode into earth will cause the EPR. The fault current will return from the fault location to the power source in various paths. These paths include screen wires of the faulted power cable/s, ECC installed along the cables, top wires of OHL lines, earth itself and other metallic infrastructure installed in the ground. Once again this is a multi-conductor problem which needs to consider selfimpedances of cable conductors, screens, ECC, mutual inductances between them and also earthing resistances. Additional system complexity in the model is introduced with cross-bonded systems. It should be noted that reliable calculation of earthing resistances is difficult to achieve if the soil is inhomogeneous or layered. Due to the complexity of the return path system, accurate analysis of EPR requires advanced software dedicated for transient studies or calculation methods using the Complex Impedance Matrix (CIM) and Node Voltage (NV) which are presented in EPRI (2005), together with some typical simplified situations. It should be also noted, typically only 5–15% (for cables with cross bonded sheaths) or 30–60% (for cables with an ECC and with sheaths earthed in only one point) of the current will return through earth, whereas the largest part of the current will return through any available metallic path in parallel. Therefore, one typical situation from CIGRE TB 347 (2008) is presented in this section. It considers an underground cable between two substations with a fault occurring in one of the substations. The situation can be schematically represented as shown in Fig. 2.46.

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Fig. 2.46 Graphical presentation of a fault occurring in one substation, for a cable connection between two substations (CIGRE TB 347 2008)

In Fig. 2.46, following parameters are: Isc Is Ig Z’s Z’m Ra Zb

short circuit current current component returning through cable metallic screen current component returning through earth distributed impedance of metallic screen distributed mutual impedance between cable conductor and metallic screen earthing resistance at substation a earthing impedance at substation b. Zb is the resulting value of the local earthing grid resistance (Rb) in parallel with the impedance of all the interconnected earthing systems (e.g.: Tower earthing resistances of all OHL connected through earth wire to substation b; or remote substations connected to substation b through earth wire or through the sheaths of HV interconnecting cables). In this calculation, Ra and the cable between a and b have to be excluded from Zb as they are separately taken into account

Distributed self and mutual impedances need to be calculated using expressions developed by Carson and Pollaczek (CIGRE TB 531 2013) since earth is acting as a part of the return path for the current. ωμ0 ωμ D þ j 0 ln e 8 2π rs ωμ ωμ D Z 0m ¼ 0 þ j 0 ln e 8 2π rs Z 0s ¼ R0s þ

R0 s rs ω ¼ 2πf μ0 ¼ 4π ∙ 107

distributed resistance of metallic screen radius of cable metallic screen angular frequency permeability of free space

ð2:12Þ

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De  659 ρ

ρ f

125

Carsons equivalent depth resistivity of earth

The size of the current part flowing into the earth for the cable link of length l can be expressed as: Ig ¼

Z 0s  Z0m l I sc Ra þ Rb þ Z 0s l

ð2:13Þ

And finally EPR in substations a and b can be found: U a ¼ I g Ra Ub ¼ I g Z b

ð2:14Þ

As Ig is the current flowing into the earth, we can calculate Ib: the part of this current driven into the earth through the local earthing grid of substation b Ib ¼

Zb I Rb g

ð2:15Þ

Other typical examples would include a cable connection with a substation at one end and an OHL connection at the other end. For such a situation, the current return path will be different, as the earthing wire of the OHL becomes part of the return path. The difference will be in the earthing resistance and the size of Ig. More detailed description of different types of examples can be found in EPRI: AC Transmission Line Reference Book – 200 kV (2005). The EPR decreases with the distance from the location where Ig is flowing into/ from the earth. The decrease of the potential depends on earths resistivity. If earths resistivity is not homogeneous in the area the potential decrease curve can obtain “stepped” shape instead of smoothly decreasing profile. Naturally the potential distribution in proximity of the earthing electrode will also depend on its geometry. If we assume that the distance d, from where the fault current is flowing into the earth, to where the potential is measured is greatly larger than the size of the earthing electrode and that earths resistivity is homogeneous and known, the voltage distribution around an earthing electrode point can be approximated by a hemisphere under the ground level with radius d. The potential distribution in earth, as a function of d in this case can be expressed as: U ðd Þ ¼

ρI b Z ρI g ¼ b: 2πd Rb 2πd

ð2:16Þ

For good earthing connections, through proper Cu metal screen of the cables or through a possible ECC, EPR at a fault location will be situated on all part of the metal sheath/screen or earthing wires, until another earthing point is reached. This is why EPR at a substation can be transmitted toward a jointing location at some

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distance from the substation. The size of this voltage will depend on size of the resistance in the metal sheath/screen or earthing conductor, from the point of EPR to the jointing location.

2.5

Conclusions and Recommendations

This chapter presents and discusses several aspects of induced voltages on power cable systems. Three types of induced voltages have been considered; (i) inductive coupling, (ii) capacitive coupling, and (iii) conductive coupling (EPR). The focus of this chapter is on how to calculate induced voltages on the cable to be worked on, how to plan the works in case of induced voltages and how to proceed with the work in situations where there is a risk of hazardous voltages or currents due to induction. One of the important findings that have been identified, is that there is no clear guidance or an appropriate standard for the evaluation of maximum permissible touch voltage for cable systems outside of substations. As a result, in this chapter are cited several standards and guidelines which are related and used in different countries. Furthermore, is included a recommendation to IEC to update the existing standard IEC 61936 (2021), where are given the limits of touch voltages as a function of clearance time, for cable systems within substations. The recommendation is mentioned in Sect. 2.1.6.3 and explained further in Appendix A. Assuming that there is a risk of induction, two main principles of safe work are introduced; i.e., the “Earthed work” and “Insulated work”. For the earthed working conditions it is possible to apply either earthed working without currents, where there is only an earth connection made locally at the workplace or, to apply earthed working conditions with currents, where the cable is also connected to earth at the cable far ends. Throughout this chapter, all principles are addressed, but the brochure recommends earthed working conditions without currents as a primary solution to ensure safe work where there is a risk of induced voltages either by inductive coupling, capacitive coupling, or EPR. It is however obvious that there are a few steps, where one needs to be extremely careful, such as when earth connections need to be removed, due to work stages, or where it may be difficult to obtain an effective local (at the workplace) earthing connection. In these situations, insulated working conditions are introduced. In all cases, prior to starting the work, it is recommended to calculate the induced voltage from the energized circuits in proximity and use the data in risk analysis for that particular work location. These calculations can be essential in choosing working methods, earthing types, and link box connections during the work. Furthermore, all installation works under induced voltage, should always be carried out by qualified and certified personnel only. In the Appendices of this chapter are included several examples of how to perform induced voltage calculations and some actual case studies from several countries.

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127

Appendixes Appendix A: Recommendations: Touch Voltage Limits A1: Recommendations Toward IEC on Setting Standard Touch Voltage for Cable Systems Limits for touch voltages are mentioned in several standards. These standards are applicable for certain parts of high voltage installations however none of them is specifically written for HV cables. To ensure personnel safety and proper planning, it is recommended that IEC sets up standardized touch voltage limits for cable systems within and outside of substations. There is a large need for such a standard, where countries are using different guidelines and standards. Furthermore, it is recommended to use IEC 60479 as a basis and look at the recommendation in standard IEC 61936-1 and evaluate if the recommendation for induced voltage as function of clearance time can be expanded to cover cable connections between substations instead of being restricted to cable connections within a substation. The voltage limits can be calculated based on the current limits a human body can tolerate. This has already been done in some countries and is explained in Appendix B2 of TB 801 (not reproduced in this chapter). It is worth noting that although IEC 61936-1 clearly states it is not applicable to design of cable installations between separate substations, it seems the curve of voltage limits as a function of time (Fig. 2.4) is in some countries accepted as a “general” curve for all cable systems. The following list shows standards where voltage limits are mentioned. In the list it is specified what is the area of the standard and if cables are excluded. The list may be incomplete. • IEC 60479-1 Effects of current on human beings and livestock – General aspects Focus of the standard is the effects of electrical current in human body. Specifies current limits as a function of current duration • IEC 61936-1 Power installations exceeding 1 kV ac – Common rules The standard includes a graph with touch voltage as function of disconnection time and a method of calculation based on IEC 60479, but it is written that the standard does not apply to design of cable installations between separate installations • IEC 50341-1 Overhead electrical lines exceeding ac 1 kV – Part 1 – General requirements Sect. 6.4 includes dimensioning with regards to Human safety • IEC 50110-1 Operation of electrical installations – General requirements • IEC 50522 Earthing of power installations exceeding 1 kV ac. This standard is mainly for design of earthing systems.

128

•

•

•

•

•

U. S. Gudmundsdottir

Same formulation about cables as in IEC 61936-1, but the voltage limit as a function of clearance time is extended to take shoes into account, for increasing the resistance to earth IEC 61201 Use of conventional touch voltage limits – application guide To be used by committees for determining their own limits. Can be used for determination of touch voltage in regard to area of contact and condition of contact wet or dry. The standard however it is not very detailed and very short IEC 50443 Effects of electromagnetic interference on pipelines caused by ac electric traction systems and/or high voltage power supply systems Limits are given but divided between accessibility of instructed and common people IEEE Std. 80-2000 Guide for safety in ac Substation Grounding Scope – in substations Considers body weight A standard curve is developed ITU-T K68 International Telecommunication Union recommendations regarding interference produced by electric power systems. Specifies touch voltage limits based on IEC 60479 CIGRE TB 95 Guide on the influence of high voltage ac power systems on metallic pipelines

A2: Calculations of Touch Voltage Based on Body Current This appendix of TB 801 is not reproduced in this chapter of the book due to lack of space

Appendix B: Calculation of Series and Mutual Impedances This appendix of TB 801 is not reproduced in this chapter of the book due to lack of space

Appendix C: Cable Testing There are various tests to be done on cable systems. Whenever cables under possible induced voltage or current are tested, the precautions as described previously in this chapter should be applied. However, there are for some test cases some special safety precautions that should be applied. These are described in the below list.

C1: Primary Voltage Testing Applying test voltages to the primary side of a cable circuit requires essentially

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129

• The cable circuit to be disconnected from the network and earthed at both ends • The test voltage source has to be connected to the phase terminations on one or more phases Issues relating to primary voltage testing include the following. 1. The circuit must be earthed while connections are being made or removed. If the circuit is so short that it has both ends within a single earthing system within the same substation, it may be sufficient to earth the remote end. However, many circuits have their remote end at a different substation, and in these cases the circuit must be earthed at the point of work. The earths are then removed to allow the test to proceed. On completion of the test, the earths must be reapplied before the test connections are changed or removed 2. The circuit must be isolated from the rest of the system. This is required to isolate from system voltage 3. Primary earths, able to withstand re-energization, must be applied between the circuit under test and the isolation. These earths remain connected throughout the test procedure 4. There must be a further isolation between the primary earths and the circuit under test, able to withstand the test voltage 5. Drain earths must be available to be applied to and disconnected from the circuit under test as required 6. On completion of testing, the test voltage must be discharged and it has to be considered that there are return voltages for a certain time depending on the type of cable and the level of the test voltage (especially after testing with dc)t Any solution that involves only a single isolation gap at each end is highly unsafe, as different potentials will be at both ends and so the isolator is required to withstand a very high differential voltage. Any solution with only a single earth at each end, which must be removed for the testing, also fails to give protection against re-energization. Such a solution is only applicable when other means to protect against energization provide a similar level of safety.

C2: Oversheath Voltage Testing HV withstand testing of the cable oversheath (and other parts of the sheath bonding system) involves applying a dc voltage typically up to 10 kV to the metallic sheath, typically for 1 min. The test requires the sheath earth connections of the cable section under test to be disconnected from earth. Dependent on the magnitude of the test voltage in relation to the rating of the SVLs (where fitted), it may also require any SVLs to be disconnected.

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U. S. Gudmundsdottir

The circuit must always be out of service for the test. It must also be protected against re-energization by safety systems involving isolation, earthing and safety documents. The links and terminals within the link box must be treated as subject to induced voltages due to rise of earth potential leading to potential differences between joint bays. However, the risk of induced voltages is especially severe if there is an adjacent live circuit. Precautions to be taken include • Temporarily earthing the link terminals with temporary earthing clips before handling them • Using insulating tools and gloves • Using a test instrument which automatically discharges the test voltage on completion of each test • Allowing plenty of time for the automatic discharge, then earthing with a temporary earthing clip before handling It is sometimes possible to plan the sequence of operations so as to minimize the risk. For instance, when testing a section which is earthed at one end and protected by SVLs at the remote end: 1. Disconnect the earth links at the earthed end 2. Go to the SVL-protected end, temporarily earth the cable sheath terminals and disconnect the SVLs 3. Test each phase in turn from the SVL-protected end, with the remaining phases earthed, again earthing each phase on completion 4. Re-fit the SVLs, then remove the temporary earths 5. Return to the earthed end and re-fit the earth links

C3: Testing and Configuring Special Bonding When configuring or testing bonding, it is important that the links and terminals within the link box are treated as subject to induced voltages due to rise of earth potential leading to potential differences between joint bays. However, the risk of induced voltages is especially severe if there is an adjacent live circuit. Precautions to be taken include • Temporarily earthing the link terminals with temporary earthing clips before fitting or removing links • Using insulating tools, gloves, footwear, and mats

C4: Measuring Earth Electrode Impedances Cable systems with several joint bays in poor earthing conditions may require to measure the impedance of the earth electrode system during installation as a commissioning test, or later during maintenance.

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131

During this test, the test Engineer working at the installation under test is handling connections to two different remote earth zones. Accordingly, precautions are always required against induced voltages due to rise of earth potential leading to potential differences between joint bays. There is also a risk of induced voltage by induction if there is an adjacent live circuit. During earth system impedance measurements, the circuit under test must be switched off and protected against re-energization. If it is required to disconnect all sheath earth links within the link box to make connections with test leads, the same precautions for any work on links and terminals are required: • Temporarily earthing the link terminals with temporary earthing clips before handling them • Using insulating tools, gloves, footwear, and mats If the test leads are connected to a system which is subjected to induced voltages, while a second testing person (called the assistant) is standing outside the equipotential zone, additional precautions must be taken. 1. The most basic precaution is that the test leads must be disconnected from the test instrument, and this from earth at the joint bay, whenever the assistant handles them. To achieve this, the test Engineer will disconnect the leads and ensure that they are securely insulated from earth, then provide a clear visual or voice signal to the assistant. The assistant can then approach and handle the test leads and stakes under the direction of the Engineer as necessary to achieve the required test. On completion, the assistant will stand well clear of the test leads and stakes, and make a clear visual or voice signal to the Engineer, who will reconnect the test leads to his instrument and proceed with the measurements. This final step is still hazardous, but is in the controlled environment of the joint bay and under the personal control of the Engineer, who is also best able to appreciate and counter the risks 2. In addition to this, the assistant should wear insulating gloves and footwear 3. The test Engineer and the test set should stand on an insulating mat. The test Engineer should wear insulating gloves and footwear

C5: Special Situations Certain situations impose especially severe risks during testing. 1. In bipolar dc circuits, one pole may fail while the other is kept in operation. In this case, a large proportion of the earth return current from the active pole will flow along the conductor of the inactive pole if it is allowed to do so. It is only safe to work on a circuit, for instance for fault location of the faulted pole, if all dc circuits in the vicinity are switched off. 2. Rail traction systems often provide power to trains by an overhead catenary wire energized with alternating voltage. The current returns to earth via the wheels of

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U. S. Gudmundsdottir

the train and the rails. From the rails, it may take a variety of earth paths back to the transformer where it originates. If allowed to do so, it may flow in parts of the power system unrelated to the traction supply, causing incorrect operation of switchgear. Circuits feeding a traction transformer from the power system are configured in such a way that there is no unintended earth path between the two networks when the circuit is in operation. It is essential to maintain this configuration when the circuit is not in service, for instance, when removing and replacing sheath earth links for oversheath testing. Failure to do so may cause a severe induced voltage hazard to the testing team.

C6: Searching for a Fault Fault location techniques are applied to primary faults (involving the phase conductor) or to secondary faults (involving only the screen insulation system). Locating these faults typically requires test voltages or currents to be applied to the HV terminal or to the screen earth terminal. The methods for doing this safely are the same as for other testing of the cable system, described in Sect. 2.3.6. Before starting fault location process, it is necessary to arrange the cable object of fault in a particular configuration; to do this, it is necessary to follow some preliminary operations in order to ensure protection against any electrical risks even in case of existing parallel cable lines along the route. Preparation of Cross-Bonded Link Boxes In a cross-bonded circuit, each cross-bonded joint presents a discontinuity in the cable screen, which causes strong reflection of travelling-wave signals. This makes time-domain methods of fault location problematical. To overcome this, it is necessary to remove the cross-bonding links inside the link boxes and replace with temporary links directly across each joint. Precautions should be taken. To do this safely, the below method of preparing a circuit for work on the screen system must be applied first. The following recommendations allow to isolate the cable (phase conductor and metal screen) from the earthing systems of the two electrical stations at both ends during activities on link boxes. This avoids both the circulating current due to the difference of potential between the two earthing systems, and the risk of transferring dangerous potentials to working area along the route due to rise of earth potential at one or another end. Furthermore, having connected the phase conductor with the metal screen of the cable, the phase conductor is simultaneously earthed. Before access to link boxes along the cable route, it is essential to be aware of the type of screen connection (solid bonding, cross-bonding, single point-bonding). To operate in safety at any part of cable line both on the conductor or metal sheath, it is advisable to isolate both ends and disconnect them from rest of electrical system obtaining the configuration described in step 1–6. The mentioned operations, in case of AIS terminations, are summarized as follow:

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133

Connection between cable conductor and metal sheath

Removing of metal sheath connection from earth

Fig. 2.47 Step 6 – Final configuration when searching for a fault

1. Isolate the circuit from the rest of the system 2. Install temporary earthing connections on the HV terminal at both ends of the cable circuit, by means of an insulating rod 3. At the link box at each termination, ensure the connection of the metal screen to earth 4. Connect the HV terminal to the metal screen of the cable itself at both ends of the cable section, by means of an insulating rod 5. Remove the temporary earthing connections on the HV terminal at both ends of the cable section 6. Remove the screen earth links at both terminations obtaining the configuration of Fig. 2.47. This situation is more complex where the cable system is cross-bonded in several sections. To work safely within a major section (between earthed link boxes), the earths must be disconnected in the link boxes at both ends of the section. In some cross-bonded circuits, cross-bonding is achieved by connecting bonding leads between the joints of different phases without the use of link boxes. In this case, no earth connection is provided at the intermediate (non-earthed) joints. This is often done in tunnel installations, where it is impractical to provide earth points within the tunnel. However, it is also done for some buried installations. In these cases, it is possible to provide a temporary earth connection by driving an earth rod, if required.

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Appendix D: Examples This appendix of TB 801 is not reproduced in this chapter of the book due to lack of space

References BS EN Std. 50321: Live Working. Footwear for Electrical Protection. Insulating Footwear and Overboots (2018) CIGRE: The Design of Specially Bonded Cable Circuits, Electra No 47, pp. 61–86. www.e-cigre. org CIGRE TB 194: Construction, Laying and Installation Techniques for Extruded and Selfcontained Fluid Filled Cable Systems, Working Group 21.17. www.e-cigre.org (2001) CIGRE TB 283: Special Bonding of High Voltage Power Cables. Working Group B1.18 (2005) CIGRE TB 347: Earth Potential Rises in Specially Bonded Screen Systems, Task Force B1.26 (2008) CIGRE TB 531: Cable Systems Electrical Characteristics. Working Group B1.30. www.e-cigre.org (2013) CIGRE TB 95: Guide on the Influence of High Voltage AC Power Systems on Metallic Pipelines. Working Group 36.02. www.e-cigre.org (1995) Diez Osorio, A., Francés Pérez, A., Donoso Conejo, G., Nogueroles Laguía, E., El Figel, S., Kabir, M.A.: Lessons Learnt During Reparation of the Morocco-Spain Submarine Connection, CIGRE 2018 paper B1-116 EPRI: AC Transmission Line Reference Book – 200 kV and Above, 3rd edn. EPRI, Palo Alto (2005). ISBN: 1011974 IEC Std. 20344: Personal Protective Equipment – Test Methods for Footwear (2021) IEC Std. 50110-1: Operation of Electrical Installations – Part 1: General Requirements (2013) IEC Std. 50341-1: Overhead Electrical Lines Exceeding AC 1 kV – Part 1: General Requirements (2012) IEC Std. 50443: Effects of Electromagnetic Interference on Pipelines Caused by AC Electric Traction Systems and/or High Voltage Power Supply Systems (2011) IEC Std. 50522: Earthing of Power Installations Exceeding 1 kV A.C. (2022) IEC Std. 60479-1: Effects of Current on Human Beings and Livestock – Part 1: General Aspects (2018) IEC Std. 60900: Live Working – Hand Tools for Use Up to 1000 V A.C. and 1500 V D.C (2018) IEC Std. 60903: Live Working – Electrical Insulating Gloves (2002) IEC Std. 61112: Live Working – Electrical Insulating Blankets (2009) IEC Std. 61201: Use of Conventional Touch Voltage Limits – Application Guide (2007) IEC Std. 61229: Rigid Protective Covers for Live Working on A.C. Installations (2012) IEC Std. 61936-1: Power Installations Exceeding 1 kV A.C. – Part 1: Common Rules (2021) IEC Std. 60909: Short-Circuit Current Calculation in Three-Phase AC Systems (2016) IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System: ANSI/IEEE Standard 81 (2012) IEEE Guide for Working Procedures on Underground Transmission Circuits with Induced Voltage: ANSI/IEEE Standard 1727 (2013a)

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IEEE Guide for safety in ac Substation Grounding: ANSI/IEEE Standard 80 (2013b) ITU-T Std. K33: Limits for people safety related to coupling into telecommunications system from A.C. electric power and A.C. electric field railway installations in fault conditions (1996) ITU-T Std. K68: Management of Electromagnetic Interference on Telecommunication Systems Due to Power Systems (2006) U. S. Gudmundsdottir: Modelling of Long High Voltage AC Cables in Transmission Systems. PhD. Thesis, Aalborg University, Fredericia, Denmark (2010). ISBN: 978-87-90707-73-6

Unnur Stella Gudmundsdottir has a PhD degree in Electrical Power Engineering from Aalborg University in Denmark where she published a book on Modelling of long High Voltage AC Cables in Transmission Systems. After finalizing her studies, Stella worked with the Danish Transmission Operator Energinet, as a Senior Cable Specialist. In 2014 she moved on to a management career, taking over the HV Cable department in Ørsted, the world’s largest renewable energy company. Currently Stella is Head of Global Engineering at Siemens Gamesa Renewable Energy, where she leads a global organization of electrical and mechanical engineers designing and building offshore windfarms around the world. Over the years, Stella has published various papers on HV cables in CIGRE, IEEE, IPST and JiCable. She has been part of several CIGRE C4 and B1 working groups and been the convener for CIGRE WG B1.44.

3

Long AC Extruded Submarine Cables: Recommendations for Testing Cables and Accessories Anders Gustafsson

Contents 3.1

3.2 3.3

3.4

3.5

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.2 Terms of Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.3 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.4 Experience of Extruded AC Submarine Cables Above 170 kV . . . . . . . . . . . . . . . . Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current Technologies for Submarine Cable Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 General Aspects on Water Tightness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.2 Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.3 Insulation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.4 Metal Screen/Sheath . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.5 Armor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.6 Outer Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current Technologies for Submarine Joint Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Factory Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1.1 General Considerations for Factory Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1.2 Typical Procedure for Factory Jointing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2 Repair Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2.1 General Considerations for Repair Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2.2 Typical Procedure for Repair Jointing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Sea/Land Transition Joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General Aspects on Submarine Cable Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Summary of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2 Test Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2.1 Ambient Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2.2 Frequency and Wave Form of AC Test Voltages . . . . . . . . . . . . . . . . . . . . . 3.5.2.3 Wave Form of Impulse Test Voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2.4 Relationship of Test Voltages and Rated Voltages . . . . . . . . . . . . . . . . . . . . 3.5.3 Characteristics of Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.4 Development Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

139 140 141 141 142 145 148 148 150 151 151 153 154 154 154 154 156 156 156 157 159 160 160 161 161 161 161 161 161 161

A. Gustafsson (*) Borealis, Energy, Stenungsund, Sweden e-mail: [email protected] © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_3

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138 3.6

3.7

3.8

A. Gustafsson Routine Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.2 Available High Voltage Test Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.3 Tests on Manufactured Lengths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.3.1 Partial Discharge Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.3.2 High Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.4 Tests on Factory Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.5 Tests on Complete Delivery Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.5.1 High Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.5.2 Partial Discharge Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.6 Tests on Repair Joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.7 Tests on Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sample Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1 Sample Tests on Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.2 Frequency of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.3 Repetition of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.4 Conductor Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.5 Measurement of Electrical Resistance of Conductor and, on Completed Core, of Metal Screen/Sheath . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.6 Measurement of Thickness of Insulation and Cable Oversheath . . . 3.7.1.7 Measurement of Thickness of Metal Sheath . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.8 Measurement of Thickness of Inner Nonmetallic Sheath . . . . . . . . . . . 3.7.1.9 Measurement of Diameters of Conductor, Core, and Metal Sheath . . . 3.7.1.10 Hot Set Test for Extruded Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.11 Measurement of Capacitance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.12 Measurement of Density of HDPE Insulation . . . . . . . . . . . . . . . . . . . . 3.7.1.13 Partial Discharge Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.14 Lightning Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.15 Volume Resistivity of Conductor Screen, Insulation Screen, and Semiconductive Polymeric Sheath . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.1.16 Examination of Completed Cable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2 Sample Tests on Factory Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.2 PD Measurement and AC Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.3 Lightning Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.4 Hot Set Test for Extruded Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.5 Tensile Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2.6 Pass Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.3 Sample Tests on Repair Joints and Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Type Test on Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.2 Range of Type Approval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.3 Summary of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.4 Preparation of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.5 Check on Insulation Thickness of Cable for Electrical Type Tests . . . . . . . . . . . . . 3.8.6 Mechanical Tests on Complete Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.6.1 Cables and Factory Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.6.2 Repair Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.7 Longitudinal/Radial Water Penetration (LWP, RWP) Test . . . . . . . . . . . . . . . . . . . . . . 3.8.7.1 Background to the LWP, RWP Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.7.2 Conductor Water Penetration Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.7.3 Metal Sheath Water Penetration Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.7.4 Radial Water Penetration Test for Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.8 Electrical Tests on Complete Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

162 162 163 164 164 164 164 165 165 165 166 166 166 166 166 166 166 166 167 167 167 167 167 167 167 167 167 167 168 168 168 168 168 168 168 169 169 169 169 169 169 170 170 171 171 171 171 172 172 174 175 176 177

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3.8.9 Non-Electrical Tests on Cable Components and Complete Cable . . . . . . . . . . . . . . 3.8.9.1 Check of Cable Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.2 Tests for Determining the Mechanical Properties of Insulation Before and After Aging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.3 Tests for Determining the Mechanical Properties of Oversheaths Before and After Aging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.4 Ageing Tests on Pieces of Complete Cable to Check Compatibility of Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.5 Loss of Mass Test on PVC Oversheaths of Type ST2 . . . . . . . . . . . . . . 3.8.9.6 Pressure Test at High Temperature on Oversheaths . . . . . . . . . . . . . . . . . 3.8.9.7 Test on PVC Oversheaths (ST1 and ST2) at Low Temperature . . . . 3.8.9.8 Heat Shock Test for PVC Oversheaths (ST1 and ST2) . . . . . . . . . . . . . 3.8.9.9 Ozone Resistance Test for EPR Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.10 Hot Set Test for EPR, HEPR, and XLPE Insulations . . . . . . . . . . . . 3.8.9.11 Measurement of Density of HDPE Insulation . . . . . . . . . . . . . . . . . . . . 3.8.9.12 Measurement of Carbon Black Content of Black PE Oversheaths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.13 Test Under Fire Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.9.14 Determination of Hardness of HEPR Insulation . . . . . . . . . . . . . . . . . . 3.8.9.15 Determination of the Elastic Modulus of HEPR Insulation . . . . . . 3.9 Prequalification Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.2 Range of Prequalification Test Approval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3 Prequalification Test on Complete Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3.1 Check on Insulation Thickness and Test Voltage Values for Electrical Prequalification Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3.2 Test Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3.3 Heating Cycle Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3.4 Lightning Impulse Voltage Test on Cable Samples . . . . . . . . . . . . . . . . . . . 3.9.3.5 Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.10 Extension of Qualification Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11 Electrical Tests After Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.1 High Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.2 Time Domain Reflectometry (TDR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A: Routine Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix B: Sample Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix C: Type Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D: Prequalification Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix E: Extension of Qualification Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix F: After Installation Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix G: Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.1

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178 178 178 178 178 178 178 178 178 178 178 178 179 179 179 179 179 179 180 181 181 181 181 181 181 181 182 182 182 183 183 184 185 186 187 187 187 188

Introduction

This chapter of the book reproduces the Technical Brochure 490 Published in 2012 by CIGRE WG B1.27 convened by A. Gustafsson from Sweden.

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3.1.1

A. Gustafsson

Background

CIGRE Study Committee B1 (formerly 21) has issued different test recommendations in the past, covering both mechanical testing of AC and DC submarine cable systems (Electra 68 and 171) and electrical testing of DC submarine cable systems (Electra 72 and 189). The latest issue for mechanical tests is Electra 171 (Electra 68 REVISION) – “Recommendations for mechanical tests of submarine cables.” The latest issue for electrical testing of DC cables is Electra 189 – “Recommendations of tests for power transmission DC cables for a rated voltage up to 800 kV (Electra 72 – REVISION).” In the year of 2000 a recommendation for HV electrical testing of long AC extruded cables was published in Electra 189 – “Recommendations for testing of long AC submarine cables for extruded insulation for system voltage above 30 (36) to 150 (170) kV”. Tests for AC extruded land cables and accessories have been developed within the framework of IEC. IEC standards for submarine cable systems have not been elaborated, however. In 2001, a new test standard for land cable systems, IEC 62067, was issued. This standard covers electrical and material tests for EHV land cable systems, that is, for system voltages above 150 (170) and up to 500 (550) kV. Only a system approach, that is, cable and accessories which are tested together, is accepted. Within this standard, not only routine, sample, and type tests are included but also a 1-year prequalification (PQ) test of the whole land cable system. Special attention shall be paid to the thermo-mechanical characteristics of the system. Since this PQ-test is time-consuming and expensive to perform a new working group (WG B1.06) was launched in 2002 to issue future recommendations for evolutions of IEC 62067 taking into account the expected innovations in cable technology, the need to reduce the time to market and the overall cost to introduce new evolutions as well as service experience collected by the cable industry. The outcome of this work was published in a Technical Brochure (TB 303) in 2006 reproduced in Chap. 4 of Volume 1 of this book. The most important outcome of the work was: • Pre-qualification test (PQ) test for HV cable systems for electrical stresses higher than 8.0 kV/mm at inner conducting shield and/or higher than 4.0 kV/mm for outer conducting shield. • Extension of qualification test (EQ) for both HV and EHV. In general, this test was introduced to more quickly and less costly re-qualify an already prequalified component of the cable system. The EQ test contains 60 days of heat cycling without voltage followed by a cable system type test. For more detailed information, see TB 303. These tests are now under consideration to be introduced by IEC in the new editions of IEC 60840 and IEC 62067. The purpose of the work by Working Group B1.27 was therefore to investigate how these recommendations and standards could be accommodated for HV and EHV

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submarine AC cable systems and which tests could be introduced, removed, or modified. According to IEC 60840, it is possible to qualify cables and accessories in separate type tests. This is not possible for EHV cable systems type tested according to IEC 62067, since only a system approach is accepted. For the purpose of this chapter, (TB 490) submarine cables and accessories were type tested together as a system in order to be qualified at both HV and EHV levels.

3.1.2

Terms of Reference

At the Paris Study Committee meeting in 2006 Task Force (TF B1.27) was launched to decide the terms of reference for “Recommendations for testing of long AC submarine cables for extruded insulation for system voltage above 150 (170) to 500 (550) kV.” The terms of reference elaborated by the TF were, as given below: • Examination of relevant IEC standards/CIGRE recommendations and documentation. • The work should adapt a system approach. Particular attention should be paid to repair joints as part of the submarine cable system and the Working Group should consider tests with external water pressure, heat cycling, and mechanical handling (during installation of repair joint). • The work should propose development and prequalification tests for the EHV submarine cable system and re-qualification in case of minor changes and define the range of prequalification and type approval for EHV submarine cable systems. • The work should propose tests for long submarine cable lengths – both in factory and after installation and explain clearly the basis for the recommended tests and the range of application. • The work should include a review of currently available technologies for submarine cable and joint design and consider possible implications for testing. • A technical brochure should be prepared for publication. • Introduce updated recommendations for testing of submarine cable systems in the voltage range >36–170 kV. Study committee B1 decided to introduce an updated program, taking into consideration the electrical and mechanical testing at the HV level. This new technical brochure will therefore extend the voltage range to >36–550 kV, thus replacing the existing recommendation in Electra 189 completely.

3.1.3

Scope

This chapter applies to long cable systems intended to be used in AC submarine power transmission systems with rated voltages above 30 (36) kV up to 500 (550)

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kV. It is applicable to cables with extruded insulation and fixed installations.1 The proposed tests are valid for both single-core and three-core AC submarine cables. A test for a single-core submarine cable may not be applicable to the three-core design and vice versa, however. In Electra 171 – “Recommendations for mechanical tests on submarine cables” – different mechanical tests are listed but which test category (routine, sample, type test) they belong to is not clarified. In this chapter (TB 490), reference is made to Electra 171. Special attention is also given to mechanical tests for repair joints under different installation conditions. The tests described in Electra 189 and TB 303 (▶ Chap. 4) have been taken into account and they have been adapted to be as consistent as possible with what is needed for qualifying and testing long lengths of AC extruded submarine cable systems above 36 kV. This chapter, compared to the earlier issues of CIGRE recommendations, will further describe and explain in more detail the rationale behind the tests. Attention has also been paid to the principal design of AC submarine cables, factory joints and repair joints. Additionally, since the possibility of testing long lengths of cables with series resonant test sets has been developed during time, a special chapter is dedicated to this subject. Nowadays, one usually include either fibers in metal tubes (FIMT) or fiber optic cables (FOC) as an integral part of the cable or bundled to the cable or alternatively laid separately distant from the cable. This brochure will not propose any test for fibers, even if it is strongly recommended to check the quality and performance during production and also after installation, taking into account attenuation phenomena, etc.

3.1.4

Experience of Extruded AC Submarine Cables Above 170 kV

Table 3.1 provides a list of installed projects (or decided) at voltages above 170 kV whereas at the time of the publication of TB 490. Table 3.2 lists selected projects of HV submarine cables below 170 kV starting with the first XLPE submarine cable delivered in 1973 between the Swedish mainland and Åland. Figures 3.1 and 3.2 show the loading of a submarine cable on a turntable of a laying vessel and the hang off at platform of a three-core submarine cable.

1

The WG has only taken installation of submarine cables laid on or buried in the seabed, into account. Special applications, for example dynamic cables connecting floating platforms are subjected to other types of mechanical stress and are therefore not considered in the scope of work.

Year 2006 2006 2008 2008 2010 2010 2011 2011 2011 2012 2012 2012 2013 2013

Country, Project Brazil, Santa Catarina Norway, Ormen Lange Canada, Wolf Island Norway, Oslo fjord Qatar, Doha bay Ireland, Cork Harbour 1 Ireland, Cork Harbour 2 Sweden, Nacka sjö USA, NJ-Brooklyn Russia, Russky Island Denmark, Anholt Norway, Oslo fjord Saudia Arabia Malta-Sicily, Italy

Voltage [kV Um] 245 420 245 420 245 245 245 245 362 245 245 420 245 245

Area [mm2] 1
500 Cu 1
1200 Cu 3
500 Cu 1
1200 Cu 1
1600 Cu 1
1600 Cu 1
1600 Cu 1
1200 Al 1
1750 kcmil Cu 3
500 Cu 3
1600 Al 1
1200 Cu 3
500 Cu 3
630 Cu

Table 3.1 Installed and planned HVAC submarine extruded cable projects >170 kV Route [km] 4.5 2.7 8.4 3.2 7.3 3.3 4.3 6.5 11 2.2 24.5 13 45 100

Depth [m] 10 210 30 300 20 10 30 45 20 43 20 300 60 150

Application Interconnection Interconnection Wind farm Interconnection Interconnection Interconnection Interconnection City ring Interconnection Interconnection Wind farm Interconnection Oil platform Interconnection

3 Long AC Extruded Submarine Cables: Recommendations for Testing Cables and. . . 143

Year 1973 1979 2000 2002 2003 2005 2006 2007 2008 2009 2010 2010 2011 2012 2012 2013

Country, Project Sweden-Åland Sweden – Bornholm UK (Isle of Man) Denmark (Horns Rev 1) Denmark (Nysted) Japan (Matsushima-Narao) UAE (Delma Island) Italy (Sardinia-Corsica) Belgium (Thornton Banks) Denmark (Horns Rev 2) Denmark (Rødsand 2) Norway (Gjöa) Australia (Sydney) Tanzania (Zanzibar 2) Norway (Goliat) Spain (Mallorca-Ibiza)

Voltage [kV Um] 84 72 90 170 170 66 145 170 170 170 170 115 132 145 115 145

Area [mm2] 1
185 Cu 1
240 Cu 3
300 Cu 3
630 Cu 3
760 Cu 3
325 Cu 3
300 Cu 3
400 Cu 3
1000 Al 3
630 Cu 3
800 Cu 3
240 Cu 1
1600 Cu 3
300 Cu 3
240 Cu 3
300 Cu Route [km] 55 43 104 20 21 53 42 15 38 42 9 100 3.0 37 106 117

Table 3.2 Examples of installed and planned EHV/HV AC submarine extruded cable projects 170 kV Depth [m] 50 55 100 20 10 75 30 75 24 20 10 500 21 55 500 700

Application Interconnection Interconnection Interconnection Wind farm Wind farm Interconnection Interconnection Interconnection Wind farm Wind farm Wind farm Oil/gas rig Bay crossing Interconnection Oil/gas rig Interconnection

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Fig. 3.1 Loading on turntable on cable laying vessel

Fig. 3.2 Cable hang-off at platform showing a three-core cable prepared for termination works

3.2

Definitions

In this section, definitions of some commonly used terminology in this document are provided. Test definitions are in full agreement with IEC 62067. Factory Joint A factory joint is a joint manufactured in-house between manufactured lengths. They are generally used where the required delivery length is longer than the manufactured length. The factory joint has normally no armor. The design principles of factory joints are provided in Sect. 3.4.1.

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Field Joint A field joint is a joint made on board a cable laying vessel or barge, or in the beach area, between cable lengths which have been armored. They are generally used to connect two delivery lengths offshore. The design principles of field joints are generally the same as for repair joints and are treated as such. Repair Joint A repair joint is a joint between cable lengths that have been armored. They are generally used in repairing a damaged submarine cable or jointing two delivery lengths offshore or in factory. The design principles of repair joints are provided in Sect. 3.4.2. Internal Design of Joint Either the joint is rigid or flexible, single-core or three-core, it has an electrical function based on the design principles to transfer the current, to control and withstand the electrical stresses, to screen the joint electrically, and to protect the insulation system from moisture ingress. These design principles are attributed to the internal design of the joint. External Design of Joint Either the joint is rigid or flexible, single-core or three-core; it has a mechanical function based on the design principles to withstand the impact from the surroundings, to withstand (in some designs) the mechanical bending and to withstand the mechanical tension and torsion during laying and operation. These design principles are attributed to the external design of the joint. Sea/Land Transition Joint (SLTJ) The term “transition joint” is generally understood to involve the connection of two different insulation types. For the purposes of this document, the term “sea/land transition joint” means the interconnection between the submarine cable and land cable, both of which are extruded insulated, but with design differences. The transition joint bay is generally located on, or close to, the shore line. Manufactured Length A manufactured length is a complete extrusion run or a part thereof. It normally does not contain any factory joints but during a failure in routine testing, a factory joint may be part of the manufactured length. A manufactured length has normally not any armor but may contain armor. Delivery Length A delivery length may be one or more manufactured lengths joined with factory joints. A delivery length is typically the intended shipping length of the submarine cable. Long Length The definition of what constitutes a “Long” length is somewhat subjective. In general, underground cables are supplied on individual delivery lengths of a

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thousand meters which are easily transportable. The manufactured or delivery lengths of submarine cables can be more than 100 kilometers, which are beyond the capacity of individual transportable drums; and they are commonly moved from the factory production line directly onto a very large turntable outside the factory, or onto a cable laying vessel. The considerably greater manufactured or delivery lengths of submarine cables imposes a range of practical difficulties on the testing of such submarine cables in accordance with current IEC standards for HV and EHV underground cables. For the purposes of this document, a “long” length is considered to be: • A cable delivery length which includes one or more factory joints, or • A cable delivery length for which the electrical characteristics make the carrying out of high voltage tests and partial discharge tests strictly in accordance with IEC 60840/IEC 62067/IEC 60885-3 impractical in factory test facilities or on site, or • A cable delivery length which cannot be accommodated on an individual transportable drum suitable for moving around the factory to the appropriate test facilities Routine Tests Tests made by the manufacturer on all manufactured components (length of cable or accessory) to check that the component meets the specified requirements. Sample Tests Tests made by the manufacturer on samples of complete cable or components taken from a complete cable or accessory, at a specified frequency, so as to verify that the finished product meets the specified requirements. Type Tests Tests made before supplying on a general commercial basis a type of submarine cable system covered by this recommendation, in order to demonstrate satisfactory performance characteristics to meet the intended application. Once successfully completed, these tests need not be repeated, unless changes are made in the cable or accessory materials, or design or manufacturing process which might change the performance characteristics. Prequalification Test (PQ) Test made before supplying on a general commercial basis a type of cable system covered by this recommendation, in order to demonstrate satisfactory long term performance of the complete cable system. The prequalification test need only be carried out once unless there is a substantial change in the cable system with respect to material, manufacturing process, design, and design levels. NOTE: A substantial change is defined as that which might adversely affect the performance of the cable system. The supplier should provide a detailed case, including test evidence, if modifications are introduced, which are claimed not to constitute a substantial change.

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Extension of Qualification (EQ) Tests made before supplying on a general commercial basis a type of cable system covered by this recommendation, in order to demonstrate satisfactory long term performance of the complete cable system, taking into account an already prequalified cable system. Factory Acceptance Test (FAT) Tests made by the manufacturer on the completed cable to check that each length meets the specified requirements. These tests are often carried out in the presence of the customer. Electrical Tests After Installation Tests made to demonstrate the integrity of the cable system as installed. Submarine Cable System An AC HV or EHV submarine cable system may consist of submarine cable(s), termination(s), and different type of joints. Development Tests Set of tests designed and performed for new cables or accessories, in order to analyze and validate designs, materials, components, production processes, installation conditions, or long-term behavior. The scope and extent is at the discretion of the manufacturer and results usually are confidential. After these development tests, cable and/or accessories are subject to a regular type and/or prequalifying test program.

3.3

Current Technologies for Submarine Cable Designs

The application of submarine cables is increasing due to the development of offshore wind farms, offshore oil platforms, the interconnection of islands, and the interconnection of power systems across harbors, rivers, lakes, gulfs, seas, and inlets. Submarine cables can be either single-core or three-core (Figs. 3.3 and 3.4). The advantages and disadvantages of each design are listed below.

3.3.1

General Aspects on Water Tightness

Submarine cables can be of either wet or dry design. A wet design allows water to migrate into the cable insulation and the conductor. For HV and EHV submarine cables as considered in this document, dry designs are normally used. Water blocking or water tightness in both the radial and longitudinal directions is crucial.

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Fig. 3.3 Example of singlecore cable design

Water tightness is the ability of a dry cable design to resist water penetration to the maximum submersion depth of the submarine cable. Water tightness is important for both normal operation and during cable failures, when the physical integrity of the cable is compromised. Weakness in either conductor or metallic sheath will reduce the water tightness of the cable.

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Profiles

Conductor Conductor shield

Metallic sheath Insulation

Inner plastic sheath

Tapes for assembling

Insulation shield

Armour

Outer sheath (Polypropylene yarn)

Optical fiber

Fig. 3.4 Example of three-core cable design

If a cable fails during its in-service life then water penetration along the cable, either within the conductor or under the metal sheath must be limited. This will minimize the length of cable to be replaced during repair. Water tightness is improved by the conductor design selected, the water blocking used within the conductor, and the type of water blocking utilized under the metal sheath. Typically water penetration would be less than 30 meters; however, depending on different cable designs, the penetration length could be longer and shorter.

3.3.2

Conductors

Conductor design contributes to the water penetration rates or the degree of water blocking of the conductor. Conductor designs can be regular, compressed, compact, solid, Milliken or type “M” stranded conductors, and key-stone shaped. A regular stranded conductor is made up of circular strands with interstices or spaces in between the strands. Compressed conductors have only the outer layer of strands reduced or flattened, but the interstices or spaces in between the remaining strands remains the same as for a regular conductor. By squeezing each conductor layer in a die the compact conductor is formed with reduced spacing in between strands. The solid conductor will not allow any water penetration, but leads to a very stiff cable with higher AC losses. For HV and EHV cables the Type “M” or Milliken conductor is used widely for conductor sizes greater than 800–1200 mm2 to limit the AC losses and to allow for a flexible cable. Semiconducting tapes are normally used in between the segments, but the interstices still exist unless compaction of the layers is included in the design. To guarantee water blocking of the conductor, strand blocking, and water swellable powders, swellable yarns or tapes are added. Strand blocking utilizes

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a compound that is either installed during stranding or laying-up of the conductor or a pumped compound that is forced into the conductor interstices after the cable has been manufactured. Water swellable powders and tapes (with different efficiency in pure water and salty water) are installed in the conductor during manufacture by adding a powder or applying a fabric tape within the conductor.

3.3.3

Insulation System

HVAC submarine cables with an extruded insulation system consist predominantly of cross-linked polyethylene (XLPE). The insulation system consists of an inner conducting screen, insulation layer, and an outer semiconducting screen. The semiconducting inner and outer screens contain carbon black as active conducting filler. The performance of the semiconducting screen compounds and their extrusion is important for HV and EHV cables. For example the properties are controlled by the percentage of carbon added, the carbon particulate size with respect to the base polymer, the dispersion of the carbon through the base polymer, and the extrusion properties. In specific cases a volume resistivity stability test may be useful where these properties are crucial for the final cable performance. The cross-linking of polyethylene (in particular low density polyethylene, LDPE) is an irreversible process (i.e., no re-melting is possible) to form a three-dimensional network that makes the insulation more thermally stable. This process is taking place after the extrusion. Whilst cable with extruded insulation is in general use for electricity distribution and at the lower transmission voltages, extruded materials have only recently become the insulation of choice for many utilities for EHV transmission circuits for underground cables. The first submarine cable using extruded XLPE as insulation system was introduced in 1973 (84 kV) and the first submarine XLPE cable on 420 kV was installed in 2006. Another extruded insulation system that may be used is EPR (ethylene-propylene rubber) but is mainly limited to systems with Um  150 kV. EPR differs from XLPE in that it has fillers for increased mechanical strength and chemical stability. Although EPR is often considered to have better electrical characteristics in the presence of water, the disadvantages are lower electrical design stress and a higher dielectric loss of EPR compounds implying possible use at lower voltages.

3.3.4

Metal Screen/Sheath

The most commonly used metal screen/sheath consists of an extruded lead alloy sheath covered by an extruded anticorrosion polymeric sheath or a semiconducting tape. Other emerging metal sheath materials are under discussion or implementation as alternatives to lead alloy sheaths. The thickness of the metal sheath is set by mechanical and electrical criteria.

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The metal sheath shall exhibit a high level of mechanical performance: consistency, capability of bending during manufacture, and installation as well as resistance to fatigue during operational thermal cycling. The suitability of lead alloys sheaths against fatigue resistance issues has been demonstrated by decades of long experience on HV and EHV submarine cables with laminated insulation and more recently on extruded insulation land cables and on HV extruded insulation submarine cables. The CENELEC standard EN 50307-2002 “Lead and lead alloys – Lead and lead alloy sheaths and sleeves of electric cables” is a good illustration of this fact and the mastering gained in the metallurgical successful control of the lead alloys morphology. Setting practical criteria for maximum permissible strain on the lead sheath by calculation is very difficult because modeling the behavior of the cable during load cycling is complex. The complexity is due to the differences in the coefficients of fatigue resistance. The metal sheath shall also have a minimum cross-section area to allow for the passage of short-circuit currents without exceeding the maximum permissible temperature at the end of the short circuit (IEC 61443). Additional wires could be used on single-core cables to increase the short-circuit current capability. When semiconducting layers are used over each core of a three-core cable a sharing of the short-circuit currents between the three parallel paths has to be taken into account. The continuity of the lead sheath over the factory joints is provided by the application of a lead sleeve of larger diameter over the joint, followed by drawing the sleeve to the under layer diameter and by wiping it to the lead sheath of the cable. The polymeric anticorrosion oversheath is either insulating or semiconducting and is usually polyolefin based. When an insulating oversheath is used, an overvoltage will occur between the metal sheath and the surrounding metal armor during cable system transients. To avoid dielectric breakdown of the insulating oversheath, a semiconducting oversheath is often used. Alternatively, earthing connections have to be inserted between metal sheath and armor at regular distances along the cable. Particular attention has to be paid to the water tightness between metal sheath and armor at the earthing connections. Possible corrosion is to be taken into account. The cross-sectional area, together with the contact resistances, will allow the flow of capacitive current distribution towards the armor and the sea. Possible overheating by short-circuit currents going through these connections is also a sizing parameter. The radial water tightness of the cable is currently provided by the metal sheath only. The longitudinal water tightness is therefore provided only under the metal sheath. Semiconducting water swellable tapes applied either helically lapped or longitudinally wrapped around the core are used for this purpose. For providing circularity to the laying-up of the cores of a three-core cable (support on which the armor will be applied), its outer spaces are filled with

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non-water swellable PP yarns or plastic fillers. A copper tape may be applied as an equalizing counter helix.

3.3.5

Armor

For submarine cable, metal wire armor is normally applied to provide enough tensile strength during the installation. When cable is installed in the sea, pulling tension (T) ¼ cable weight in water (W) x depth of water (d) þ bottom tension (H) occurs on cable. The cable must withstand this tension. Generally the tensile strength is verified by mechanical tests in accordance with CIGRE Recommendation “Recommendations for mechanical test on sub-marine cables” published in Electra 171, 1997. The recommendation requires the cable to withstand the test condition of T ¼ 1.3 W
d þ H (36–170 kV See § 3.6.4 (1) § 3.6.4 Repair joints Test References >36–170 kV See § 3.6.6 § 3.6.5 Terminations Test References >36–170 kV See § 3.6.7 IEC60840 § 9.1 Complete delivery length (FAT) Test References >36–170 kV High voltage test [§ 3.6.5.1] § 3.6.5.1 Partial discharge (PD) test [§ 3.6.5.2] § 3.6.5.2

> 170 kV IEC62067 § 9.2 IEC62067 § 9.2

> 170 kV § 3.6.4

> 170 kV § 3.6.5

> 170 kV IEC62067 § 9.1

> 170 kV § 3.6.5.1 § 3.6.5.2

(1) If the electric stress is higher than 8 kV/mm at the conductor screen or higher than 4 kV/mm at the insulation screen (applicable for the PD test)

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Appendix B: Sample Test (References to IEC 60840 Ed. 4 and IEC 62067 Ed. 2) Sample from insulation or completed core References >36–170 kV > 170 kV Conductor examination [§ 3.7.1.4] IEC60840 § 10.4 IEC62067 § 10.4 Measurement of electrical resistance of conductor IEC60840 § 10.5 IEC62067 § 10.5 and metal screen/sheath (1) [§ 3.7.1.5] Measurement of thickness of insulation and cable IEC60840 § 10.6 IEC62067 § 10.6 oversheath [§ 3.7.1.6] Measurement of thickness of metal sheath IEC60840 § 10.7 IEC62067 § 10.7 [§ 3.7.1.7] Measurement of thickness of nonmetallic inner IEC60840 § 10.6 IEC62067 § 10.6 sheath [§ 3.7.1.8] Measurement of diameters of conductor, core and IEC60840 § 10.8 IEC62067 § 10.8 metallic sheath [§ 3.7.1.9] Hot set test for extruded insulation [§ 3.7.1.10] IEC60840 § 10.9 IEC62067 § 10.9 Measurement of capacitance (1) [§ 3.7.1.11] IEC60840 § 10.10 IEC62067 § 10.10 Measurement of density of HDPE insulation [§ IEC60840 § 10.11 IEC62067 § 10.11 3.7.1.12] Partial discharge (PD) test [§ 3.7.1.13] § 3.7.1.13 § 3.7.1.13 Lightning impulse voltage test [§ 3.7.1.14] § 3.7.1.14 § 3.7.1.14 Volume resistivity of conductor screen, insulation Annex D IEC60840 Annex D IEC62067 screen and semiconductive polymeric sheath (2) [§ 3.7.1.15] Completed cable Test References >36–170 kV > 170 kV Examination of completed cable § 3.7.1.16 § 3.7.1.16 Factory joints Test References >36–170 kV > 170 kV PD measurement and AC voltage test § 3.7.2.2 § 3.7.2.2 Lightning impulse voltage test § 3.7.1.14 § 3.7.1.14 Tensile test § 3.7.2.5 § 3.7.2.5 Hot set test for extruded insulation IEC60840 § 10.9 IEC62067 § 10.9 Test

(1) Can be performed on the complete cable length (2) Can be performed on insulation core NOTE 1: Sample tests from insulation or complete core shall be performed on each extrusion run (one sample), except for PD and lightning impulse that are to be performed from the start and stop of each extrusion run, and examination which shall be performed from one sample from the delivery length NOTE 2: If one sample fails any test, two more samples shall be tested successfully NOTE 3: Sample tests for repair joints and terminations are not applicable as they shall be routine tested

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Appendix C: Type Test (References to IEC 60840 Ed. 4 and IEC 62067 Ed. 2) Main sample Cable and factory joint Test

References >36–170 kV > 170 kV Check of insulation thickness [§ 3.8.5] IEC60840 § 12.4.1 IEC62067 § 12.4.1 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Electra 171 § 2.1 Tensile bending test [§ 3.8.6.1] Electra 171 § 2.2 Electra 171 § 2.2 Test voltage values [§ 3.8.8] IEC60840 § 12.4.1 IEC62067 § 12.4.1 Partial discharge test [§ 3.8.8] IEC60840 § 12.4.4 IEC62067 § 12.4.4 Tan(δ) measurement1 [§ 3.8.8] IEC60840 § 12.4.5 IEC62067 § 12.4.5 Heating cycle voltage test [§ 3.8.8] IEC60840 § 12.4.6 IEC62067 § 12.4.6 Switching impulse test (U  300 kV) N/A IEC62067 § 12.4.7.1 Lightning impulse test [§ 3.8.8] IEC60840 § 12.4.7 IEC62067 § 12.4.7.2 Examination of cable system [§ 3.8.8] IEC60840 § 12.4.8 IEC62067 § 12.4.8 Repair joints Test References >36–170 kV > 170 kV Mechanical tests prior to electrical type § 3.8.6.2 Table 3.4 § 3.8.6.2 Table 3.4 tests [§ 3.8.6.2] Electrical type test [§ 3.8.8] IEC60840 § 12.4.1 to § IEC62067 § 12.4.1 to § 12.4.9 12.4.9 NOTE 1: tan(δ) – separate sample possible Separate samples Test

References >36–170 kV > 170 kV

Cable sample #1 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Tensile bending test [§ 3.8.6.1] Electra 171 § 2.2 Conductor water penetration test [§ 3.8.7.2] § 3.8.7.2 Cable sample #2 Metal sheath water penetration test [§ 3.8.7.3] § 3.8.7.3 Cable sample #3 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Tensile bending test [§ 3.8.6.1] Electra 171 § 2.2 Resistivity of polymeric sheath [§ 3.8.8] IEC60840 § 12.4.9 (if applicable) Cable sample #4 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Tensile bending test [§ 3.8.6.1] Electra 171 § 2.2 Resistivity of semiconducting screens [§ 3.8.8] IEC60840 § 12.4.9 (if applicable)

Electra 171 § 2.1 Electra 171 § 2.2 § 3.8.7.2 § 3.8.7.3 Electra 171 § 2.1 Electra 171 § 2.2 IEC62067 § 12.4.9

Electra 171 § 2.1 Electra 171 § 2.2 IEC62067 § 12.4.9 (continued)

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Separate samples Test

References >36–170 kV > 170 kV

Cable sample #5 Other nonelectrical tests on cable components and IEC60840 § 12.5 on complete cable [§ 3.8.9] Factory joint sample #1 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Tensile bending test [§ 3.8.6.1] Electra 171 § 2.2 Radial water pressure test [§ 3.8.7.4] § 3.8.7.4 Repair joint sample #1 Coiling test (if applicable) [§ 3.8.6.1] Electra 171 § 2.1 Tensile bending test [§ 3.8.6.2] Electra 171 § 2.2 Radial water pressure test [§ 3.8.7.4] § 3.8.7.4

IEC62067 § 12.5

Electra 171 § 2.1 Electra 171 § 2.2 § 3.8.7.4 Electra 171 § 2.1 Electra 171 § 2.2 § 3.8.7.4

NOTE 1: Cable sample #2 is only applicable to designs with an earthing connection between lead sheath and armor NOTE 2: Cable sample #3 is only applicable to designs with a conducting polymeric sheath between lead sheath and armor. It may be the same sample as cable sample #4 NOTE 3: Repair joint sample #1 may be a separate sample or taken from the type test circuit

Appendix D: Prequalification Test (References to IEC 60840 Ed. 4 and IEC 62067 Ed. 2) Cable system Cable, factory joint and repair joint References Test >36–170 kV > 170 kV Summary of prequalification test IEC60840 §13.2.1 (1) IEC62067 §13.2.1 [§ 3.9.1–§ 3.9.2] Test voltage values [§ 3.9.3.1] IEC60840 §13.2.2 (1) IEC62067 §13.2.2 Test arrangement [§ 3.9.3.2] IEC60840 §13.2.3 (1) IEC62067 §13.2.3 Heating cycle voltage test [§ 3.9.3.3] IEC60840 §13.2.4 (1) IEC62067 §13.2.4 Lightning impulse test [§ 3.9.3.4] IEC60840 §13.2.5 (1) IEC62067 §13.2.5 Examination of cable system [§ 3.9.3.5] IEC60840 §13.2.6 (1) IEC62067 §13.2.6 (1) For projects where thermo-mechanical aspects have to be considered, the prequalification test arrangement has to be representative of the actual installation conditions NOTE 1: The conditions for prequalification of submarine cable systems are given in § 3.9.1–§ 3.9.2

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Appendix E: Extension of Qualification Test (References to IEC 60840 Ed. 4 and IEC 62067 Ed. 2) Cable system Cable, factory joint and repair joint Test Extension of prequalification test [§ 3.10]

References >36–170 kV > 170 kV IEC60840 §13.3 IEC62067 §13.3

NOTE 1: The conditions for extension of prequalification of submarine cable systems are given in TB – §10

Appendix F: After Installation Test (References to IEC 60840 Ed. 4 and IEC 62067 Ed. 2) Cable system Test High voltage test [§ 3.11.1] Time domain reflectometry (TDR) (1) [§ 3.11.2]

References >36–170 kV > 170 kV IEC60840 §16.3 IEC62067 §16.3 § 3.11.2 § 3.11.2

(1) Recommended NOTE 1: To be performed when the installation of the cable and its accessories has been completed

Appendix G: Abbreviations AC AEIC DC EHV EPR EQ FAT FIMT FOC HDD HDPE HEPR HV

Alternating Current Association of Edison Illuminating Companies Direct Current Extra High Voltage Ethylene Propylene Rubber Extended Prequalification Factory Acceptance Test Fibers in Metallic Tubes Fiber Optic Cable Horizontal Directional Drill High Density Polyethylene Hard Grade Ethylene Propylene Rubber High Voltage

188

HVAC ICEA IEC IEEE JEC LDPE LWP PD PE PQ PVC RWP SLTJ TB TDR TF VLF WG XLPE

A. Gustafsson

High Voltage Alternating Current Insulated Cable Engineers Association International Electrotechnical Commission Institute of Electrical & Electronics Engineers Japanese Electrotechnical Committee Low Density Polyethylene Longitudinal Water Penetration Partial Discharge Polyethylene Prequalification Polyvinylchloride Radial Water Penetration Sea/Land Transition Joint Technical Brochure Time Domain Reflectometry Task Force Very Low Frequency Working Group Cross-linked Polyethylene

References “Application of XLPE submarine power cable for extra high voltage”, 8th Jicable (19–23 June 2011), Paper A6.4, H. Yanagawa, O. Matsunaga, T. Nakagawa, S. Asai “Armouring loss in three-core submarine XLPE cables”, 8th Jicable (19–23 June 2011), Paper A7.3, D. Palmgren, J. Karlstrand, G. Henning CIGRE TB 268: Working Group B1.05, “Transient voltages affecting long cables” (2005) CIGRE TB 303: Working Group B1.06, “Revision of qualification procedures for HV and EHV AC extruded underground cable systems” (2006) ELECTRA 68: CIGRE Working Group 21.06, “Recommendations for mechanical tests on submarine cables” (1980) ELECTRA 171: CIGRE Working Group 21.02, “Recommendations for mechanical tests on submarine cables” (April 1997) ELECTRA 189: CIGRE Working Group 21.02, “Recommendations for long AC submarine cables with extruded insulation for system voltage above 30(36) to 150(170) kV” (April 2000) “Energy transmission on long three core/three foil XLPE power cables”, 6th Jicable (22–24 June 2003), G.E. Balog, G. Evenset, F. Rudolfsen “Factory testing of long submarine XLPE cables using frequency-tuned resonant systems”, CIRED Turin (June 2005), J. Karlstrand, G. Henning, S. Schierig, P. Coors IEC 60815-1 Ed.1 Part 1-2: Selection and dimensioning of high-voltage insulators intended for use in polluted conditions (October 2008) IEC 60840 Ed.1: Tests for power cables with extruded insulation of rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) (1998) IEC 60840 Ed.2 and Ed. 3: Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV)) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements (February 1999/April 2004)

3

Long AC Extruded Submarine Cables: Recommendations for Testing Cables and. . .

189

IEC 62067 Ed.1: Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV)) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements (October 2001) “Polymer insulated high voltage cables”, IEEE electrical insulation magazine (May/June 2006), Vol. 22, No. 3, V. Vahedy “Power loss and inductance of steel armoured multi-core cables: comparison of IEC values with “2.5D” FEA results and measurements”, Paper B1–116, CIGRE (2010), J.J. Bremnes, G. Evenset, R. Stolan “Qualification of a long 345 kV submarine XLPE cable system”, 8th Jicable (19–23 June 2011), Paper D4.6, J. Karlstrand, D. Palmgren, J. Antonischki, J. Johansson, B. Zettervall “Qualification, supply and installation of the world’s first 420 kV XLPE submarine cable system in Norway”, 7th Jicable (24–28 June 2007), Paper A9.3, G. Evenset, J.-E. Larsen, B. Knutsen, K. Faugstad “Quality control of extruded HVDC cables: Comparison of AC, VLF and DC voltage stress on flat samples with contamination”, NORD-IS (2009), F. Mauseth, E. Ildstad, M. Selsjord, R. Hegerberg, M. Jeroense, B. Sanden, J.-E. Skog “Selection of cable sheath lead alloys for fatigue resistance”, IEEE transactions on power apparatus and systems, Vol. PAS-96, No. 1 (January/February 1977), D.G. Havard “Sinusoidal 0.1 Hz test voltage for diagnostic PD measurements of high voltage cable systems”, 15th ISH (27–31 August 2007), K. Rethmeier, P. Mohaupt, S. Seifert, V. Bergmann, W. Kalkner “Submarine power cables – Design, installation, repair, environmental aspects”, Springer Verlag (2009), ISBN 978-3-642-01269-3, T. Worzyk “Teknik i ASEA”, ASEA AB Västerås (1983), ISBN 91-7260-765-3 “The fatigue life of lead alloy E as a sheathing material for submarine power cables”, IEEE/PES (20–25 July 1986), Summer Meeting Mexico City, P. Donelli, F. Donazzi, W.G. Lawson “The Oslo fjord project – The first project with long length 420 kV XLPE insulated submarine cables”, 8th Jicable (19–23 June 2011), Paper D4.5, T. Skeie, J. Elders, A.E. Rod “The selection of the frequency range for high-voltage onsite testing of extruded insulation cable systems”, IEEE electrical insulation magazine (November/December 2000), Vol. 16, No. 6, E. Gockenbach, W. Hauschild

Dr. Gustafsson has more than 25 years of experience of R&D and engineering management where about 20 years was within ABB in the area of HV cable systems. Dr. Gustafsson started his career in ABB 1993 and has except for 2.5 years in 2003-2005 worked within several functions within ABB on R&D and engineering on HV cables and accessories for both underground and submarine cables. During the years 2012-2014 he was R&D Manager at the ABB HV Cables unit in USA. After a short 1.5 year period outside the cable area in health care engineering he started in 2018 at Borealis as manager for application development and technical service on wire and cable applications. He is an active member of CIGRE and has acted as convenor for WG B1.27 on testing of HV submarine cable systems and is presently convenor for JWG B1/D1.75 on cable/accessory interfaces. In 2012 he received the Technical Committee Award for outstanding contribution to the work of SC B1. Dr. Gustafsson earned his M.Sc. and Ph.D. degrees in Polymer Technology at Royal Institute of Technology in Stockholm, Sweden.

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Basics on Construction and Installation Methods Yves Maugain

Contents 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Description of the Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.1 Main Cable Systems Configurations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.2 Cable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3 Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.2 Accessory Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.3 Compatibility of the Accessory with the Cable . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.4 Compatibility of the Accessory Performance with that of the Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.5 Compatibility of the Accessory with the Cable System Design and Operating Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.6 Compatibility of the Accessory with Specified After Laying Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.7 Maintenance Requirements of the Accessory . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3.8 Economics of Accessory Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Construction Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.1 Definition of the Main Technical Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2 Description of Traditional Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2.1 Ducts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2.2 Direct Burial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2.3 Tunnels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2.4 Troughs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

192 193 194 194 197 197 198 200 203 205 209 209 210 212 212 212 212 218 224 231

The content of this chapter is mainly coming from TB 194 published by WG 21.17, convened by Y.Maugain (France) in 2001. When appropriate, information coming from further WG is added. Y. Maugain (*) CIGRE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_4

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4.5

4.6

4.7

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4.3.3 Description of Innovative Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.1 Bridges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.2 Shafts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.3 Horizontal Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.4 Pipe Jacking/Microtunnelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.5 Mechanical Laying (Fig. 4.31) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.6 Embedding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3.7 Use of Existing Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cable Installation Design and Laying Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 Cable Installation Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1.1 Installation Design in Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1.2 Installation Design for Buried Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1.3 Transition Between Different Installation Types . . . . . . . . . . . . . . . . . . . . . . . 4.4.2 Cable Laying and Installation Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2.1 Cable Pulling Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2.2 Installation Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2.3 Installation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2.4 Adaptation of the Cable System Design to the Technique/ Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . External Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.1 Location (Urban vs. Rural) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.2 Right of Way . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.3 Magnetic Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.3.1 Flat Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.3.2 Trefoil Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.3.3 Vertical Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.3.4 Comparison Between Overhead Lines and Buried Links . . . . . . . . . . . . . . 4.5.3.5 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.4 Existing Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.5 Legal Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.6 Safety Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.6.1 Protection of the Link from External Damage . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.6.2 Protection of the Environment from a System Fault . . . . . . . . . . . . . . . . . . . 4.5.6.3 Protection of the Workers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.6.4 Protection of the Public . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.6.5 Safety of the Different Laying Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.7 Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Design of A Link . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6.1 Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6.2 Study cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

235 235 237 240 254 261 266 269 272 272 272 286 287 291 291 295 299 303 312 312 313 313 313 317 320 323 324 325 327 328 328 329 330 331 331 332 333 333 339 346

Introduction

“Construction Techniques” and “Installation Techniques” At the beginning of the Working Group 21.17’s work, and before publication of TB 194, the difference was not very clear since both words were being used to define the same processes in a number of countries.

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Throughout TB 194 and this chapter, the terms have to be considered as follows: The term “construction techniques” is considered as relating to the techniques used to create the cable route, mainly covering the civil works such as trenching. Likewise the term “installation techniques” is considered to relate to the cable system design and cable installation methods. Cable design issues associated with the laying and installation techniques have also been considered under the general subject of “Installation Techniques”. The cable installation was then the rest : the pulling and backfilling, the fixing when laid in open air and its consequences on accessories installation design Basics for a Newcomer in the Cable World to Design an Underground Link The principle commonly adopted is that a reliable link is based on a reliable cable design and manufacture, a reliable cable system design and reliable construction and installation techniques. It therefore appears necessary to not only give the description of the different techniques, but also to give guidance on the overall design process. For this, it appears that the best approach would be to define the process from the beginning to allow a complete understanding of what is needed to ensure a reliable project. In the following sections of this chapter, a short reminder of the description of a cable system will be made, the various construction methods will be described in detail, the installation methods will be recalled and the options for transitioning from one method to another one will be presented. Then, as introduced in ▶ Chap. 1, the methodology to study a new project will be proposed and a case study will be included.

4.2

Description of the Cable System

The purpose of this chapter is to give a quick overview on the different cable system components, to draw attention to the fact that the cable design is usually dependent upon the construction and installation techniques. An understanding of the cost can be obtained by taking into consideration the cost of the different components and the cost of their installation. The optimum costs can be developed by selecting different solutions depending upon each of the cable system sections along the route. This will be developed in a further section. Where cables interconnect with other circuits, the transition is achieved through a termination. The length of a continuous section of cable is often limited by the size or weight of the cable reel that can be transported to the installation site, sometimes by the safe pulling tension that can be applied to the cable, or by the maximum induced voltage on the metallic screen of the cable. The lengths are then connected in joint-bays. This is achieved through joints (or splices). Joints and terminations, together with the equipment to limit and withstand induced voltages (SVL for example) are the main components of equipment called cable accessories.

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Main Cable Systems Configurations

Various configurations such as single circuit, double circuit and triple circuit lines with different arrangements of transformer and generator connections are in use. Many types of connections comprising overhead lines, underground cables, or both are possible and can be found. The length of such transmission lines and cables can vary significantly. For load reasons, one circuit can consist of several cable systems. Note that in the subsequent figures each cable can consist of several cable systems Main configurations, presented in ▶ Chap. 1 and listed bellow, are representative of the most common practical situations: • • • • •

Meshed underground network: ▶ Fig. 1.1 Siphon: ▶ Fig. 1.4 Substation entrance: ▶ Fig. 1.6 Power Generator output: ▶ Fig. 1.7 Power or auxiliary transformer supply: ▶ Fig. 1.8

4.2.2

Cable

Although the present work is focusing on construction and installation techniques of extruded, it seems useful to give a brief overall view of the different types of cables in service at the present time. These cables belong to two main families: • Cables with extruded insulation: extruded dielectric cables • Cables with lapped insulation: SCFF, HPFF, HPGF. In this book, only extruded cable systems are considered. Transition joints between AC extruded cables and SCFF cables are presented in ▶ Chap. 8 of Volume 1. Transition joints between DC extruded cables and SCFF cables are the topic of ▶ Chap. 7 in this volume Extruded-dielectric cables, also known as solid-dielectric cables, have been introduced for medium voltage cables in the fifties. The first high voltage cables with extruded insulation on 110 kV systems were installed in the 1960’. Insulation materials are either Ethylene-Propylene Rubber (EPR), low/high-density polyethylene (LDPE/HDPE), or crosslinked polyethylene (XLPE). EPR, XLPE, LDPE, and HDPE have been in use for many years. XLPE becomes a predominant choice for high voltage cables up to 500 kV level. Maximum conductor temperature in normal operation is depending on the insulation material: 70
C for LDPE (Fig. 4.1), 80
C for HDPE, and 90
C for EPR and XLPE.

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Fig. 4.1 Typical 400 kV extruded cable (LDPE mid 80s)

• Cable description The conductor is in most cases stranded copper or aluminum, sometimes solid aluminum (Figs. 4.2, 4.3, and 4.4). For sizes generally equal to or larger than 1200 mm2 for copper and 1600 mm2 for aluminum, the conductor is segmented to reduce the ac/dc resistance ratio. A semi-conducting bedding tape is sometimes wrapped over the conductor before extrusion. This prevents the inner semi-conducting layer from entering the strand interstices during the extrusion process and, in turn, facilitates removal for splicing and terminating. The inner semi-conducting layer is extruded over the conductor or semiconducting bedding tape. Its purpose is to provide a smooth interface between the conductor and the insulation, and an uniform electric field. It avoids the presence of air between metallic and insulation materials (no partial discharge) and constitutes a thermal barrier in short-circuit conditions. The insulation and outer semi-conducting layer are the other parts of the dielectric which are preferably applied by triple extrusion process. Indeed, the simultaneous extrusion of the semi-conducting layers and the insulation through a

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Round core single strand

Stranded round core

Oval core

Profile wire core

Milliken segm ental hollow core

Fig. 4.2 Exemples of conductors

Fig. 4.3 Exemples of individual wires

Hollow core

Profile wire hollow core

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Fig. 4.4 Typical XLPE Cable with segmental conductor with insulated wires

common (triple) cross-head is the best solution to eliminate protrusions at the interfaces which are sources of high voltage stress points. A metallic screen made with copper or aluminum wires and/or a metallic sheath carries the capacitive current and the fault current of a specified magnitude and duration before reaching a specified temperature. A metallic sheath is normally applied to prevent the ingress of moisture. Its design must take into account thermal and mechanical considerations. Since extruded dielectric materials have significantly higher coefficients of expansion than metals, the radial volumetric expansion can be quite large. The sheath must remain in good contact with the outer semi-conducting layer during heating and cooling. A jacket or outer covering or oversheath (made of PE or PVC) prevents the corrosion of the metallic sheath and isolates it from the ground. It is also required to protect the cable during handling and pulling operations. Impregnated paper cables, widely used from the beginning of the last century, made possible underground power transmission up to highest voltages. Many grids are still fitted out to a large extent with these cables, even if they are replaced by extruded-dielectric cables to an ever-increasing extent. AC Transition joints between lapped cables and extruded cables are covered by ▶ Chap. 8 in Volume 1.

4.2.3

Accessories

4.2.3.1 General As reminded several times in this book, the reliability and performance of a cable circuit is dependent in equal measures on the designs of the cable and accessory and on the skill and experience of the person who is assembling the accessory. The cable insulation is extruded or lapped in the factory under controlled process conditions using selected materials of high quality. It is equally important that the same quality measures are employed for the manufacture of the accessories in the factory and for their assembly on site onto the specially prepared cable.

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It is essential to select the design of accessory to be compatible with the particular cable type and the particular service application. Compatibility should be validated and be supported by appropriate tests, or service experience. In particular the performance of the accessory is dependent on the quality, skill and training of the jointing personnel in the installation conditions and on the use of the specialized tools required for a particular accessory. The itemized sub-headings below form the basis of the information that is needed by the manufacturer and installer of the cable and accessories. For many applications the cable manufacturer also manufactures, supplies and installs the accessories as part of the complete cable circuit, thus the information is immediately available in-house. In the event that the user purchases the accessories separately from the cable, then the following items form the basis of the questions that should be asked to the manufacturers of the cable and accessories to ensure that the accessories are suitable. As the design of the cable can depend upon the construction and installation technique, the accessory design or selection must be made accordingly.

4.2.3.2 Accessory Types 4.2.3.2.1 Types of Joints A joint is the insulated and fully protected connection between two or sometimes more cables. It is also termed “splice”. The following types exist: • • • •

Straight joint (Fig. 4.5), Transition joint, Screen interruption joint, Y branch joint. The design requirements common to each type of joint are

• A high current connection between conductors, which meets the same performance standard as the cable, including in overload conditions,

Fig. 4.5 Typical straight joint

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• Joint insulation which meets the same performance standard as the cable, • A high current connection to permit the flow of short circuit current between the two cable sheaths or screen wires, • A metallic joint shell or screen wire connection electrically insulated from earth potential to match the insulating integrity of the cable oversheath, • Protection of the joint and cable insulation against the ingress of water, • Protection of the joint metalwork against corrosion, • A tough protective sleeve against mechanical aggressions, • A heat dissipating device to ensure that the joint is not a hot spot along the power link.

4.2.3.2.2 Types of Terminations A termination is the connection between a cable and other electrical equipment. It is also termed pothead. The following types exist: • Metal enclosed GIS termination, (GIS: Gas Insulated Switchgear) • Oil immersed transformer termination • Outdoor termination (Fig. 4.6) Fig. 4.6 Typical outdoor termination (400 kV) with composite insulator

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• Indoor termination • Temporary termination The design requirements common to each type of termination are: • A high current connection between the cable conductor and an external busbar, which meets the same performance standard as the cable, including in overload conditions • Insulation which meets the same performance standard as the cable • A high current connection to permit the flow of short circuit current from the cable metallic sheath or screen wires via a bonding lead to the system earth • A connection to the cable metallic sheath or earth wires which is electrically insulated from earth potential to match the insulating integrity of the cable oversheath • Protection of the cable insulation against the ingress of water and the ingress of pressurized dielectric fluid from adjacent metal clad busbar trunking • Protection of metalwork against corrosion • Provision of support to the cable • Ability to withstand cable thermomechanical loads and external forces such as wind, ice and busbar loading

4.2.3.3 Compatibility of the Accessory with the Cable 4.2.3.3.1 Number of Cable Cores The user should determine whether the cable construction is of single, three core or triplex construction (i.e. three single core cables twisted together). The design of the accessory and the method of assembly is dependent upon the number of cable cores; however, it is unusual for three core extruded cables to be employed above 60 kV. 4.2.3.3.2 Cable Constructional Details For satisfactory service performance, it is most important that the correct size of accessory is selected to suit the particular cable. The outer diameter of the cable insulation, its tolerance, and shape are particularly important in the selection of an accessory employing a premolded component, such as an elastomeric stress cone or an elastomeric joint molding. Such components are designed to fit a specific range of diameters of prepared cable insulation (that is with the insulation screen removed and the insulation smoothed and shaped). The components must not be used outside this range. The minimum diameter is determined by the need to achieve sufficient pressure to eliminate voids at the interface with the cable insulation. The maximum diameter is determined by such considerations as: (a) Preventing damage by over stretching during assembly and (b) Limiting the maximum pressure at the interface such that compression set of the cable insulation and molded insulation is minimized.

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The diameter and tolerance of the conductor and of its compaction (the radio of the effective cross sectional area of the metal to the total area occupied) are needed in selecting a connector that will exhibit stable conductivity and high mechanical strength (see ▶ Chap. 10 in Volume 1). The diameters and tolerances of the cable metallic barrier and over sheath are needed to ensure that accessory metallic flanges and other components can be passed back over the cable during assembly (see ▶ Chap. 5 in Volume 1). The following dimensional and constructional details should be obtained by the user to ensure compatibility of the accessory with the cable: The detailed cable construction should be obtained from the cable manufacturer, which includes the following information as a minimum requirement. Diameters, maximum and minimum tolerances, eccentricity dimensions, construction, and material need to be obtained for each of the following cable components: • • • • • • •

Conductor and special features (e.g. water blocking), if any Conductor screen Insulation (ovality and eccentricity dimensions are required) Insulation screen Screen wires, if any Longitudinal water blocking, if any Metallic barrier, if any, for example, whether an extruded sheath, a welded sheath, or a laminated foil barrier. Also whether of cylindrical or corrugated form • Over sheath • Armor, if any • Special features (e.g., presence of optical fiber or pilot wires). 4.2.3.3.3 Conductor Area and Diameter The user should ensure that the accessory has been designed and tested for the particular cable conductor size. The electrical performance of an accessory design can become critical on large conductor cables because of the high cable insulation screen stress. The user should ensure that the conductor connections in the complete kit of components are supplied to suit the particular conductor construction. The conductor connection must be capable of carrying the same current as the cable conductor and must be capable of withstanding the cable longitudinal thermomechanical forces, depending on the installation design, these being proportional to the cross-sectional area. These aspects are covered in ▶ Chap. 10 of Volume 1. 4.2.3.3.4 Operating Temperature of the Cable Conductor and Sheath The operating temperature of the cable conductor and sheath under continuous, short term overload and short circuit current loading have to be taken into account properly.

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The materials of the accessory must be capable of operating satisfactorily at the operating temperatures specified for the cable. IEC 61443 Standard may be taken as a reference. The short term overload temperatures depend upon the type of cable and application. The temperature of the conductor under short circuit is typically taken as 250
C for XLPE and 160
C for paper insulated cable. The permitted short circuit temperature of the cable extruded metallic sheath or screen wires is determined by the type of metallic sheath and thermoplastic over sheath, this temperature usually being significantly less than that of the cable insulation. • Compatibility of the accessory with the type of cable insulation and semiconducting screens • Physical compatibility with the extruded cable The insulation of the polymeric cable must be identified by the user. There are significant differences between the electrical and mechanical characteristics of extruded insulation. The usual insulants for extruded polymeric cables in the voltage class of 60 kV and above being XLPE (crosslinked polyethylene), LDPE (low density polyethylene), HDPE (high density polyethylene) and EPR (ethylene propylene rubber).

4.2.3.3.5 Chemical Compatibility with the Extruded Cable The type of insulating liquid or lubricant used in joints and terminations should be identified to ensure that these do not affect the properties of the polymeric insulation and semi-conducting screens employed in the cable and accessories. For example, (a) hydrocarbon liquids at elevated temperature can cause swelling of XLPE and EPR insulation and reduction of the conducting properties of screens and (b) silicone liquids can have an effect on silicone rubber components.

4.2.3.3.6 Cable Electrical Design Stresses to be Withstood by the Accessory The user is advised to obtain the magnitude of the cable stresses at the conductor and insulation screens, or obtain the dimensions of the cable, thereby permitting the stresses to be calculated. The unit of stress is kV/mm calculated at U0 voltage. There are significant differences in the magnitude of the electrical design stress employed in cables, these being dependent upon the type and thickness of insulation, the conductor size, the system voltage and the lightning impulse voltage. It is essential that the accessory has been designed and tested to operate at the particular cable design stress. The stress at the cable insulation screen is of particular significance because this normally determines the maximum design stress in the accessory. The insulation screen stress is usually of higher magnitude in those cables designed for high system voltages and large conductor diameters.

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4.2.3.3.7

Mechanical Forces and Movements Generated by the Cable on the Accessory The magnitude of the forces and movements generated by the cable on the accessory depends upon the cable materials, the method of cable manufacture and the type of cable installation design (i.e. rigid or flexible installation). The following mechanical strains are dependent on the cable construction: • Insulation retraction (shrink back) (extruded insulation) • Insulation radial thermal expansion • Oversheath retraction (shrink back) The following forces are dependent upon the cable construction, current loading, operating temperature, method and type of cable constraint and accessory design: • Conductor thermomechanical thrust and retraction, • Sheath thermomechanical thrust and retraction.

4.2.3.3.8 Short Circuit Forces Electromagnetic forces are present during a short circuit between the individual conducting components of the accessory and between the adjacent cables and the accessory. The following information is applicable: • Method of restraint of the accessory and cable, • Method of restraint and the spacing of adjacent cables.

4.2.3.4 Compatibility of the Accessory Performance with that of the Cable System 4.2.3.4.1 Circuit Performance Parameters The current rating and optimum circuit economics are dictated by the cable conductor size, cable material costs, and the method of installation. To achieve the optimum economical solution, it is important that the accessory design is not allowed to limit the performance of the cable. The accessory must therefore match the following cable performance: • Rated voltages (Nominal system voltage U and maximum Um), • Current rating (Current magnitude), • Continuous, cyclic and short time overload (Current magnitude, time and temperature), • Short circuit rating, “phase to earth” and “phase to phase” (Current magnitude, asymmetry, time and temperature),

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• Basic impulse level (Withstand voltages for lightning impulse and switching surge), (Flash over voltage for the system insulation co-ordination of outdoor terminations, if specified). 4.2.3.4.2 Circuit Life Required The accessory should match the design life specified for the particular cable circuit. This is typically requested to be from 20 to 40 years, however some cable circuits are installed as temporary links, for example in an overhead line circuit. Such accessories may be designed to be suitable for quick assembly with a reduction in performance and service life. 4.2.3.4.3 Metallic Screen Bonding Requirements The following information is required on: (a) the type of bonding leads (concentric or single conductors) and their conductor size and overall dimensions and (b) the type of cable bonding scheme, for example, solidly earthed or specially bonded metallic screens (See ▶ Chap. 8) – Magnitude of induced sheath or screen wire voltage under normal and short circuit current – Magnitude of circulating sheath or screen wire current under normal loading – Magnitude of short circuit current – Magnitude of specified over sheath lightning withstand voltage and dc withstand voltage It is important that the accessory design incorporates means of connecting the cable screen wires, metallic tapes or sheath and joint shell to the insulation screen (Fig. 4.7).

Fig. 4.7 Typical screen interruption joint

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4.2.3.4.4 Earth Fault Requirements Some utilities require that short circuit currents be returned within the cable system. The user should ensure that the accessory is also able to withstand this current.

4.2.3.5 Compatibility of the Accessory with the Cable System Design and Operating Conditions The user is advised to ensure that accessory design is a) compatible with the particular cable installation design, as this determines the mechanical loading applied, b) capable of being assembled in the site environmental conditions and c) capable of a satisfactory service performance under adverse climatic conditions. 4.2.3.5.1 Type of Cable Installation Design • Rigidly constrained (cable laid direct in the ground or close cleated) • Flexible unconstrained (cable horizontally snaked or vertically waved) • Semi-flexible (cable constrained, but permitted to exhibit a controlled deflection, for example, at a bridge crossing or adjacent to gas immersed switch gear) • Unfilled duct 4.2.3.5.2 Standard Dimensions for Cable Termination The user is advised to ensure the following dimensional compliance: 4.2.3.5.2.1

Outdoor and Indoor Termination Harmonization with existing equipment of the overall height of the off-going bus bar connector and of the bottom metalwork fixing arrangements to the support structure. 4.2.3.5.2.2

GIS and Transformer Termination Harmonization of the cable termination with both the design of the metal clad switch gear (internal diameter, overall length, off-going bus bar connector, bottom metalwork sealing arrangements and pressure) and the design of the support structure (fixing arrangements for the particular cable constraint selected). See ▶ Chaps. 7 and ▶ 11 in volume1.

4.2.3.5.3 Types of Accessory Installations • Buried in the ground (laid direct) • Jointing chamber • Tunnel • Above ground • Bridge • Tower • Shaft

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4.2.3.5.4 Jointing Limitations in Restricted Installation Locations • Space limitations • Time limitations (for example, arising from road or rail traffic influences) • Tolerance limitations of assembly personnel (for example, arising from extremes of temperature, humidity, vibration, noise, and induced voltage) 4.2.3.5.5 Mechanical Forces Applied to the Accessory • Thermomechanical forces • Earthquake • Vibration • Off-going bus bar at terminations • Wind loading on bus bars at terminations • Ice loading on bus bars at terminations • Short circuit loading on bus bars at terminations • GIS pressure • Angle of installation of terminations • Hydraulic or pneumatic pressure forces at transition joints 4.2.3.5.6 Climatic Conditions Accessories require to be suitable for the extremes of climatic conditions expected both in service and during assembly. Some types of accessories are required to be assembled under controlled environmental conditions. • • • • • • •

Altitude (reduction of electrical strength of air) Air pollution (reduction of electrical strength of outdoor insulator surface) Precipitation (reduction in electrical strength of air and outdoor insulator surface) Salt fog (reduction in electrical strength of outdoor insulator surface) Moisture condensation (reduction in electrical strength of insulator surface) Temperature Atmospheric humidity

4.2.3.5.7 Type of Accessory Outer Protection Required The accessory protection is required to provide corrosion protection and, for a specially bonded cable circuit, insulation from ground. • • • •

Joint box (laid direct in the ground or in air) Pedestal insulator (in air) Moulded sheet insulation (in air, to protect personnel against electric shock) Metallic fences or screens (in air, to protect personnel against electric shock)

4.2.3.5.8 Situations Requiring Special Accessory Protection • Submerged under water • Fire risk, (Fig. 4.8) • Termite infestation

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Fig. 4.8 Joint in tunnel with fire resistant protection

4.2.3.5.9 Quality Assurance Scheme for Accessory Installation Assembly of the accessories onto cable with extruded insulation is the most vulnerable part of a project involving the manufacture. Accessories and cables are manufactured and tested under controlled factory conditions, whereas the in-service performance of the accessory is dependent upon the training, skill, and reliability of the personnel, who are often required to work under adverse site conditions (See ▶ Chaps. 5 and ▶ 6 in Volume 1 of this Book). For many project applications, one company will manufacture the cable and accessories and undertake to complete the installation of the circuit. In other applications the installer may complete the circuit using cable and accessories supplied by different manufacturers. In some applications the installer may only assemble the accessories. For each application the requirements of the QA system are equally rigorous: 4.2.3.5.9.1

Quality Assurance Approval for Installation The user should ensure that the installer provides evidence of an approved quality assurance system for installation to an internationally recognized standard. 4.2.3.5.9.2

Quality Plan The installer is required to produce a Quality Plan for each project, this includes the project time schedule together with the requirements for suitably qualified personnel, training, on-site storage of components and accessories, tools, testing equipment, constructing materials, assembly instructions, preparation of the jointing environment and records of the assembly work. It is important that the records of assembly are traceable to the location of each accessory in the cable circuit. If purchasing

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separately, the user is advised to ensure that, for the purposes of traceability, the quality systems of the cable manufacturer, accessory manufacturer and installer are compatible. 4.2.3.5.10 Training of Personnel When selecting the designs of accessories the user should ensure that training courses are available for the jointing and supervisory personnel. It is strongly advised that personnel receive training on the particular designs of accessories and cable. Examples of the elements of a training course for assembly personnel are : • General training at specific system voltages with the standard range of accessories required by the user • Repeat training after a defined period for those personnel who have completed general training • Specified training on a new accessory or cable design for those personnel who have completed general training At the end of the training course the proficiency of the assembly personnel is normally assessed, for example, by a verbal or written examination, by a practical test and preferably by performing on the assembled accessories an electrical partial discharge test and voltage withstand test. Proficiency is recognized at the completion of training by the issue of a certificate, which should be checked by the user as part of the quality plan for a specific project. In many instances a kit of general jointing tools and a set of general assembly instructions is also issued to the personnel following satisfactory completion of training. 4.2.3.5.11 Assembly Instructions The accessory manufacturer is required to supply a complete set of assembly instructions together with drawings of the particular accessory. The instructions should also include lists of the specified assembly tools, the specified consumable materials and the health and safety precautions. Recommendations for the preparation of the assembly environment should also be given. It is important that the user studies the instructions before work begins to ensure that the workplace is correctly prepared and that all the tools and consumable materials are available. 4.2.3.5.12 Special Assembly Tools Most designs of accessories, particularly those operating at higher system voltages, require special tools which are purchased or hired from the accessory manufacturer. The user should ensure that full instructions are provided and that the personnel are trained in their use. These tools may take the form, for example, of

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(a) Hydraulic compression presses or welding equipment for connecting the conductors (b) Cutting equipment to remove the insulation screen and to shape the cable insulation (c) Assembly machines which stretch and position pre molded elastomeric components (d) Taping machines that apply tape (e) Heated mold tools and mobile extruders for field molded joints.

4.2.3.5.13 Preparation of the Assembly Environment It is strongly recommended that the assembly area for both joints and termination to be enclosed within a tent or temporary building, with the objective of providing a clean and dry environment. The enclosure should be (a) Well-lit to facilitate accurate preparation of the cable insulation, (b) Provided with a sound floor (c) Lined with sealed materials to facilitate cleanliness. In extremes of climate, it is good practice to provide control of temperature and humidity to ensure a. Consistent performance of the personnel b. Consistent properties of the polymeric materials • Joint assembly : • An appropriately sized joint bay or chamber. • The provision of a temporary and/or permanent support for the completed joint. • Termination assembly : • A permanent support structure. • A temporary weatherproof structure during assembly. • Means of lifting the cable and insulator into position.

4.2.3.6 Compatibility of the Accessory with Specified After Laying Tests When the installation of the cable and accessories has been completed, it is standard practice to perform electrical tests to demonstrate that the assembly of the accessories is of satisfactory quality and that mechanical damage to the cable and accessories has not occurred during installation. Different tests can be performed or are being under study.. It is important to ensure that the accessory design is suitable for the particular test:

4.2.3.7 Maintenance Requirements of the Accessory The user should ensure that adequate maintenance tests and checks have been recommended by the cable and accessory suppliers, for example:

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4.2.3.7.1 Monitoring of Fluid Insulation Liquid and gas levels: some types of termination, straight joints and transition joints are filled with insulating liquid or gas and may require to be regularly inspected or monitored in service to ensure that neither the liquid nor gas have escaped. 4.2.3.7.2 Voltage Withstand Tests on the Over Sheath and Joint Protection These tests are similar to the after laying tests, but they are usually performed at reduced voltage levels. 4.2.3.7.3 Shelf Life of Accessories for Emergency Spares The user should ensure that information is provided on the shelf life of the components in an accessory for long term storage as these may vary according to the type of material, the way they are packed and the appropriate temperature and humidity conditions of storage. 4.2.3.7.4 Availability of Accessory Kits for Emergency Spares The user is recommended to obtain either a sufficient stock of spare accessories or to have an agreement with the manufacturer to supply accessories at short notice. The design of an accessory for emergency use may be different from that installed.

4.2.3.8 Economics of Accessory Selection A comparison of the relative costs of different designs of accessory kits should not be undertaken without giving due consideration to the total costs of installation and assembly. The following are the main items of cost: 4.2.3.8.1 Cost of the Accessory Complete with All Components The accessory design should be checked to ensure that it is a complete kit and will be supplied with all the components and assembly instructions for the particular application. Some components that may not necessarily be supplied by all accessory manufacturers are for example: (a) conductor connections and anti-corrosion protection for joints and (b) bus bar take-off connectors and support metalwork for termination. 4.2.3.8.2 Cost of Guarantee and Insurance At the higher system voltages it is more usual for the cable and accessories to be supplied, installed and guaranteed as a “turn-key” project. Under such circumstances the guarantee will usually extend to a specified number of years in service. If the user decides to divide the supply and installation of accessories between companies, it is recommended that the cost of financial self-insurance be considered, because the responsibility for an accessory failure in service can be difficult to apportion between the accessory manufacturer, the cable manufacturer and the installer. 4.2.3.8.3 Cost of Assembly Time The jointing time required to assemble accessories can differ dependent on their design. Similarly the time required to assemble the anti-corrosion protection and the

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final mechanical support to the accessory can be the over-riding factors in determining the jointing time. 4.2.3.8.4 Cost of Preparing the Installation Environment for the Accessory Accessories require the provision of a weatherproof enclosure together with the environmental conditions necessary for jointing (e.g. good lighting, cleanliness and, when necessary, air conditioning. The supply of electricity and gas may be required).

4.2.3.8.5 Cost of Safe Working Conditions In addition to the cost of constructing the installation environment to comply with the regulations for safe working practices, the provision may be required for temporary and permanent protection to (a) The installer’s personnel from electric shock during assembly and (b) The user’s personnel when the accessory is in service. See ▶ Chap. 2.

4.2.3.8.6 Cost of Special Jointing Tools There may be significant differences in purchase cost and hiring charges of the tools required for different accessories.

4.2.3.8.7 Cost of Training Qualified jointers who are trained to assemble the particular accessory should always be employed. The user should decide whether it will be more cost effective to (a) Employ qualified and experienced personnel to assemble the accessories, or (b) Employ qualified and experienced personnel to install the cable and assemble the accessories as part of a turn-key contract, or (c) Incur the on-going costs of training and regular repeat training for his own personnel.

4.2.3.8.8 Comparative Cost of Cable and Accessories The design of the cable can influence the cost of the accessory design. Thus, a reduction in the cost of the cable construction may result in an increase in the cost of the accessories. Similarly, an increase in the cost of installation by laying longer lengths of cable may achieve a reduction in overall costs by requiring fewer joints.

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4.2.3.8.9 Cost of Verification of Accessory Performance If a type test report is not available for the particular cable and accessory in combination then the user is advised to allow for the cost of performing a type approval test.

4.3

Construction Techniques

Twelve high voltage cable construction techniques have been identified and are reported in this section. Four are considered traditional while eight are labeled innovative. They are being used to a varying degree by different companies around the world.

4.3.1

Definition of the Main Technical Terms

See the glossary in Section 4.7

4.3.2

Description of Traditional Techniques

Among the twelve identified techniques, four are categorized as traditional. This is mainly because most or all companies around the world consistently use one or more of them in laying high voltage cables. They have been successfully used for many decades due to their simplicity, relatively low cost and the availability of materials and equipment as well as qualified entrepreneurs to execute the necessary work.

4.3.2.1 Ducts 4.3.2.1.1 Description of the Technique Ducts are normally used jointly with manholes in a system that is favored in urban areas of major cities for its convenience. It offers the possibility of carrying out the civil work independently from the electrical work. Also, the flexibility of cable maintenance or replacement with minimum disturbance to local traffic and economic activities are considered advantageous. In less congested areas, joint bays would replace manholes to reduce cost (Fig. 4.9). Three or more ducts having the proper diameter and wall thickness are placed in a trench at the pre-determined depth and configuration. A layer of special bedding material having low thermal resistivity is placed on the bottom of the trench prior to placing of ducts. Thinner wall ducts could be encased in concrete to form a duct bank. Ducts could also be stacked in two or more layers to accommodate the required number of cables to be installed. Special spacers are used to ensure the exact configuration and to allow concrete to flow between ducts.

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Fig. 4.9 PVC ducts – double circuit

Reinforcing steel rods should be used in special cases such as crossing under railways in order to increase the rigidity of the duct bank. In some cable sections, the space between cables and ducts could be filled using special materials to enhance cable current carrying capacity or restrict its movement. This is recommended in excessively deep installation or when difference in elevation between manholes is substantial. Manholes are underground chambers built to house the joints and other auxiliary equipment such as fluid feeding tanks, sheath cross bonding cables and sheath protection surge arresters. Access to cables and joints is easy using fixed or removable ladders installed in two or more chimneys depending on manhole design (Fig. 4.10). Manhole dimensions depend on the number of cables to be jointed as well as the circuit voltage. Metallic structures are usually used inside the manholes to support cables and joints. All metallic steel members inside manholes should be properly connected to a solid ground rod or bare ground cable loop.

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Fig. 4.10 Manhole in a duct and manhole cable system

Joints should be protected from mechanical forces due to cable expansion under load cycles either by expansion loops or by a rigid clamping system. Manhole dimensions could be reduced if joints and cables are rigidly clamped. Manholes should be designed in accordance with local standards to withstand normal road traffic loads. Most manholes are built in place using reinforced concrete. However recent development in pre cast concrete made it possible to use high quality prefabricated manholes. This would reduce the time needed for assembling the factory pre cast concrete slabs forming manhole walls and the roof. Floors are still poured in place to allow for proper ground leveling and ground water drainage. Joint bays offer a more economical way to house and mechanically protect the joints. They could be regarded as the lower half of manholes. They could also be built in place or assembled using pre-cast concrete slabs Temporary shelter should always be used during jointing operations to protect workers, cables and joints from the elements and ensure a clean environment for jointing operations. Once the joints are completed, the joint bay is filled with thermal back filling material and top slabs placed over the entire length. A warning tape is usually placed about 30 cm below grade level. Joints are not accessible in joint bays. Sheath testing is possible using link boxes located either above ground or in below ground accessible pits where cross bonding cable leads are connected. High Voltage cable circuits are normally installed in dedicated duct banks, often one cable per duct. However, for economic reasons, three cables could be installed in the same duct in case of lower voltages. Also two circuits (six cables) could be installed in the same duct bank. It is not recommended to install more than two circuits in order to reduce the risk of cable damage due to accidental excavation. This would enhance underground system availability as well as maintain a reasonable cable load rating.

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Laying cables in ducts is considered one of the safest type of installation regarding safety in case of short circuit. It should be noted that a good earth cover over the duct bank is necessary to ensure public safety. It is also worth mentioning that manholes could present a safety hazard in case of cable or joint explosion. Empty ducts could be used for a reserve cable provided that sheath bonding is designed accordingly. Fiber optic communication cables could also be installed in the same duct bank . 4.3.2.1.2

Limits of the Technique

4.3.2.1.2.1

Civil Work Civil work includes excavation of trenches and shoring them if necessary, relocation of existing services, placing of ducts and spacers, pouring of concrete to form duct banks and covering them with the proper back filling materials as well as reinstating of all surfaces to their original conditions. It is recommended that construction of necessary manholes or assembling prefabricated ones is often carried out after ducts have been securely placed. Compacting of back filling materials as well as of the soil layers is essential in order to obtain a low thermal resistivity. Long cable lengths could be pulled through straight duct sections provided that cable reels could be transported to site. However, due to factors related to cable route that have to follow existing road and street network, land topography and existing subterranean services, almost all cable routes include bends and offsets that would increase the required cable pulling tensions and thus limit distances between manholes. Cables installed in ducts rarely exceed 800 meters. In major cities the maximum length of open trenches at any given time may be limited by local authorities to a few hundred meters. 4.3.2.1.2.2

Drying of the Soil Over the years, soil drying may occur due to change in back filling materials properties, presence of tree roots or higher than normal cable operating temperatures. This could be avoided by using a proper back fill, compacting of different layers during installation, keeping a tree-free zone along cable route and ultimately by monitoring of cable’s temperature or that of the surrounding soil. Use of thermocouples or fiber optic cables particularly during peak load periods and hot and dry weather spells would ensure this feedback. 4.3.2.1.2.3

Water Drainage Water table level varies with location. In some areas, abundant surface water could hinder civil work progress. Water seeping through the ground during construction should be pumped out, using appropriate equipment, to ensure personnel safety as well as quality of work.

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Although the presence of water around cables and accessories could be considered somewhat beneficial, many utilities do not allow it to accumulate in ducts or manholes to prevent possible premature deterioration of cables and accessories. Ducts would be installed with a continuous slight slope towards manholes. Manholes would be connected to city sewage or storm draining systems through an anti-pollution arrangement particularly in the case of fluid filled cables. Local regulations should be followed and authorization should be obtained for these connections. 4.3.2.1.2.4

Temperature of the Soil/Environment Ducts could be installed in soils that are naturally warm provided that some forced cooling arrangement is foreseen. 4.3.2.1.2.5

Hardness of the Soil In hard rocky soils it would be advantageous to consider alternative techniques to install cables such as micro tunneling described in this document. Technical and economic studies should be carried out in order to compare different viable alternatives. 4.3.2.1.2.6

Stability of the Soil Different soil formation could exist along any cable route. Soil should be tested and its properties investigated by carrying out on-site and laboratory tests. Soil stability should be ensured prior to installation of ducts or duct banks. 4.3.2.1.2.7

Thermal Resistivity of the Soil Soil resistivity should be measured along cable route using appropriate instruments to determine the need for replacing native soil by special thermal back filling. Some laboratory measurements could also be useful in establishing the maximum thermal resistivity and percentage of water content by weight of soil samples. Back filling materials having higher thermal resistivities than that assumed in cable design calculations could lead to higher cable operating temperatures, soil drying out and eventually dielectric breakdown due to thermal runaway. Back filling of trenches should be done in layers that are properly compacted. Local regulations could influence the choice of back filling materials. 4.3.2.1.2.8

Seismicity Ducts could be used in seismic risk areas provided that they have been designed to withstand the expected earth tremors. Both rigid and flexible designs would be acceptable. Some experimental work on a model are advisable.

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4.3.2.1.2.9

Frost Frost and ground freezing occur for short or long duration in many countries. Ducts and duct banks should be placed below the expected frost line in order to avoid damage due to ground movement caused by (severe and frequent) freezing and thaw cycles. In extreme cases where ground is permanently frozen, special arrangement such as placing insulating materials underneath the duct bank is recommended. Non insulated duct installation would risk being damaged due to soil instability caused by heat dissipated from cables. Cable failure might result. 4.3.2.1.2.10

Archaeology Sensitive archaeological areas should be avoided when cable route is selected. However should archaeological finds be encountered during excavation, work should be immediately stopped and local authorities advised .Depending on the importance of the findings, some countries would allow work to continue after proper investigations and documentation are completed. In other cases, an alternative cable route might have to be chosen. 4.3.2.1.2.11

Presence of Termites Cables should be designed to have an anti-termite protection and ducts should be blocked using a proper sealing material such as “ductseal”. 4.3.2.1.2.12

Laying in National Park Local authorities should be consulted and if necessary, alternative techniques such as directional drilling be used to minimize digging in sensitive areas of national parks. 4.3.2.1.2.13

Duration of the Work Civil work duration depends on many factors. The major factors to be considered are, access to site, the nature of soil, depth of excavation, presence of underground services, type of equipment used, weather conditions and restrictions imposed by local authorities. Average construction duration vary also according to the size of the project. Some values, including cable installation, were reported in CIGRE joint working group 21/ 22-01 report issued in May 1996. 4.3.2.1.2.14

Maintenance and Repairing Process Manholes should be periodically inspected to ensure their structural integrity. Although cables installed in ducts are inaccessible, joints could be inspected at manholes. Visual inspection of joints and cables could be done after pumping out any water from manholes. At joint bay locations, only sheaths transposition cables could be reached through hand-holes.

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Periodical jacket testing could be performed from these points. Insulation or jacket faults could be localized using different techniques. Repair should be carried out. This work would require some excavation at fault location. In case of major problems, an existing cable section, between two manholes, could be replaced without any excavation. 4.3.2.1.2.15

Cable Removal After Operation With the introduction of new international standards for environment protection cables would have to be removed at the end of their useful service life and their components disposed of and recycled. It is usually possible to remove cables from ducts without excavation. However, some sections might prove difficult or impossible to remove due to cable snaking, accumulation of dirt, deterioration of ducts and ground up-heaving. In these cases new excavation permits would have to obtained to gain access to cables at locations between existing manholes. Structural integrity of empty manholes should be investigated. Local authorities could impose the demolition of manholes for safety reasons. 4.3.2.1.2.16

Adaptation of the Technique to the Cable System Design Duct and manhole system is well suited for cable installation in congested city core areas. In designing cable systems to be installed in ducts many electromechanical factors should be carefully considered together with civil engineering aspects, such as :

• proper cable size for the required load (larger cables are required for duct installations as compared to directly buried or in air) • maximum pulling tensions required for cable installation • metallic and nonmetallic sheaths for cable protection • maximum induced sheath voltage and allowable sheath currents • clamping of cables and joints in manholes if necessary • sheath permutation and protection schemes • grounding in manholes • size and location of manholes • size and type of ducts

4.3.2.2 Direct Burial 4.3.2.2.1 Description of the Technique This method consists of digging a trench and directly placing the cables in it. This technique is extensively used world-wide for extruded cable as well as for fluid filled cable. Indeed, in the 60 to 170 kV range it comes second only to laying in

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ducts, whereas for the voltages between 200 to 500 kV it ranks just after the laying in tunnels and the laying in ducts. This solution is particularly interesting economically, since apart from digging and backfilling the trench no other heavy works are necessary. This is why the technique is used in urban as well as in rural areas. HV cables are usually installed along the public ways. As far as possible installation in private ground is avoided. An advantage of this method is that the route of the link can easily be deflected to avoid unforeseen obstacles. The depth of the trench (Fig. 4.11) is such that in most cases the cables have an earth cover at least one meter thick (this often is a legal requirement or this can also depend on the short-circuit levels). Cables are usually laid in trefoil formation. Every meter an adequate non-corrodible clad or rope is wrapped around the cables to keep the trefoil formation during the backfilling of the trench. The other type of laying configuration is the flat formation which is used mainly for cables in the 220 to 500 kV range (depending on the carrying capacity). Trench width obviously varies according to the type of formation and the voltage level of the cables : • width 1.0 m (220 to 500 kV) in flat formation (Fig. 4.12). Over the backfilling material cable-protective slabs are placed. Above these slabs the telecommunication cables are usually placed (running mostly in ducts). Fig. 4.11 Direct burial

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Fig. 4.12 400 kV cables directly buried in flat formation with joints

4.3.2.2.2 4.3.2.2.2.1

Limits of the Technique

Civil Work The civil works are identical to those required for duct laying, except that the cables are laid directly in the trench on a bottom layer of materials intended to protect them from any sharp rocks likely to be present in the bottom of the trench. The backfilling materials used to fill the trench are composed, starting with the protective bottom layer referred to above, of sand, special backfill or possibly lean concrete. It is not so frequent that the excavated soil or concrete are used for backfilling. Weak mix may be used instead of the normal backfill to increase the mechanical protection around the cables. In many countries, a special backfill (so-called controlled backfill) is used in order to create a low thermal resistivity environment to dissipate the heat released by the power cables (this greater dissipation allowing an increased power rating of the link). In this respect, the use of fiber-optic cable or of optical fibers in HV cable, although not yet generalized, brings certainly advantages in the future as it will make possible permanent thermal monitoring of the link (giving precise knowledge about the thermal environment of the cables). Civil works include also the excavation of joint pits. The size of these pits is naturally larger than the trench (width and depth) itself, and may vary according to the voltage level, the type of joint and layout (in parallel or longitudinally). The length of the trenches is often defined by the size of the cable drums, drumsize itself being often dependent on the means and possibilities of transport and handling (but the length can also depend on the calculated pulling tensions if they exceed the limits, environmental aspects, . . .). Furthermore, in urban situations,

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especially taking into account of the traffic, opening a trench several hundreds of meters long may give rise to problems. Accordingly, local authorities may restrict the length of open trenches (with increase of joint’s number), restricting the periods of the year or week and sometimes the hours of day during which work may be done. This problem is the more critical, in terms of site planning and organization, when controlled backfill is being used as this material must be very carefully applied (degree of humidity, of compaction) and closely inspected by a laboratory. The length of the trench may be some hundreds of meters, hardly ever exceeding 800 m.

4.3.2.2.2.2

Drying of the Soil Soil drying can occur in the immediate vicinity of cables in service, due to migration of the humidity from the hot zone to the cold zone (so increasing the thermal resistivity of the dry zone). This phenomenon can also be observed when the link runs parallel to certain types of vegetation (trees that have deep roots, . . .). In certain regions the soil may be permanently dry naturally. Various solutions can be considered :

• Use of controlled backfilling material; • Creation of a ‘root-free’ corridor; • A different configuration for the cables (in flat formation instead of trefoil formation) to improve the rate of heat dissipation of each cable. These points can have influence on the type or the width of the trench but don’t really change the manner of working.

4.3.2.2.2.3

Water Drainage Conversely to the soil drying phenomenon, wet soil may seem more favorable to laying of HV cables because it constitutes a natural cooling system. If the water can flow out, there is nevertheless a risk of erosion of the soil and the materials embedding the cables. The execution of trenches in wet soil often calls for installing substantial means of drainage (pumps, etc.) in order to avoid erosion of the trench edges leading to collapse or “flooding”.

4.3.2.2.2.4

Temperature of the Soil/Environment Construction of trenches in a soil that is naturally or artificially (old mining areas) hot does not apparently cause any particular problems. However, it remains obvious that too hot a soil will significantly reduce the power transit capacity of the link.

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4.3.2.2.2.5

Hardness of the Soil Laying of cables in particularly rocky soil, although technically feasible, is not advisable, as excavating the trench will require costly heavy equipment (and entails risk of equipment damage). Work planning has to make due allowance for the difficult conditions, to avoid falling undue delay. 4.3.2.2.2.6

Stability of the Soil Construction of trenches in unstable soil such as in marshlands implies that the trench must be completely shored (with sheet piling if necessary) and that drainage systems must be installed. Considerable cost savings are possible by carrying out a survey of the subsoil along the intended route, so that the costly or difficult route can be avoided by selecting another route for the trench. 4.3.2.2.2.7

Thermal Resistivity of the Soil Soil resistivity considerations have little influence on the choice of the construction method. However, it does have a considerable impact on the power-transit capacity of the link. Accordingly, soil samples have to be taken for analysis well in advance of the start of the works in order to determine the characteristics of the cables (crosssection, material, . . .), their configuration (trefoil or flat formation) and decide whether or not to use controlled backfilling. For a selected backfill to achieve an average resistivity, the size of the trench can also be influenced by the results of the analysis. 4.3.2.2.2.8

Seismicity Cables laid in plain soil incur the stresses generated by soil movements. However, the soil movements do not normally seriously affect the cables as the cable components have a certain elasticity. Nevertheless, it is obvious that a large crack in the soil at right angles to the link could seriously damage the cables. 4.3.2.2.2.9

Frost Frozen soil renders trench digging difficult (or impossible) due to the hardness of the soil. The conditions are also arduous for the workers who build the trenches, as they have to work in subzero temperatures and for longer times at the site as work progress is slower in hard soil. In particularly cold regions there may be prolonged periods of the year where work is not reasonably possible.

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It can also be mentioned that the mix of frost and water during the thaw can swell the soil (with possibly the collapse of the trench). 4.3.2.2.2.10

Archaeology If during route selection for the link it is not possible to avoid a potentially archaeological area, it must be borne in mind that, due to local authorities, any finds made during excavation will make it mandatory to stop the work, at least in the portion where the find has been made. Work at the site is then delayed until the archaeologists have investigated the find. The length of the portion affected and the duration of the stoppage depend on what further discoveries are made. 4.3.2.2.2.11

Presence of Termites In soil infected with termites there are two possible ways of protecting the cables: either

• By placing an anti-termite chemical in the outer covering of the cables, or wrapping an anti-termite cloth ribbon under the outer covering. However, international environmental guidelines increasingly forbid these options. or • By inserting each cable in a steel pipe (these being different techniques from direct burial) or providing a steel covering around all the cables. For other pests it may be effective to lay the cables at a depth where these pests are not usually active (for instance, rodents do not normally stray below a depth of 80 cm). 4.3.2.2.2.12

Laying in National Park Certain local or national authorities may make mandatory a different laying technique in order to preserve the natural environment (for example, directional drilling instead of direct burial). Assuming digging a trench is allowed, a number of particular recommendations or stipulations will have to be complied with restoration of the soil and the vegetation. 4.3.2.2.2.13

Duration of the Work When the duration of the work would otherwise be too long, a different technique may be imposed. This may be the result of the already being other rights of soil occupancy (e.g. utilities, telecom) or of local circumstances (important road

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crossings, residential areas) where the local authorities would impose different techniques (for instance, laying in ducts or directional drilling). 4.3.2.2.2.14

Maintenance and Repairing Process Once the link has been built with the direct burial method, the only points where access remains possible are the extremities where the cables emerge from the soil for connection to terminals, and possibly the cable shields at the joints between cables. These are the only places where direct visual inspection is possible. Nevertheless, the link operator can still perform tests on the outer covering (generally a DC. test). Defect location and repair will always necessitate some excavation work. If the cable defect is a substantial one, the civil works will also be substantial, as the deteriorated length of cable will have to be replaced, and two new joints made. 4.3.2.2.2.15

Cable Removal After Operation Cable removal at the end of his life has been definitively stopped represents a huge amount of work and cost, because the trenches will have to be completely reopened. This is the reason why these days the disused links are usually abandoned in place. However, this may result in environmental concern if the cables are the fluidinsulated type. The fluid should be regularly drained by pumping it from the central channel so as to avoid the risk of fluid leaking into the soil. New developments to remove the cables with a trenchless method are at the present time under investigation. 4.3.2.2.2.16

Adaptation of the Technique to the Cable System Design For a well-defined cable system the choice made concerning the conductor materials has a significant effect on the link construction method and cable laying technique, on account for instance of the difference in weight between copper and aluminum. The lighter cables (aluminum) allow to have drums with longer length of cable (but with a different carrying capacity for the same size in copper), in turn allowing the laying of longer lengths. During laying of lighter cable the drawing strain is applied to the entire cable by using stockings, whereas for the heavier cable the drawing strain is applied to the conductor itself by means of a specially designed pulling grip.

4.3.2.3 Tunnels The Reason for Selecting The Tunnel Instead of Ducts The tunnel is usually used when a lot of cables (Fig 4.14) will be laid out in that particular section, which results in difficulty to ensure the transmission capacity required.

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Shield method Shield is a kind of tunnelling method designed to operate even in poor subsoil. Tunnels are excavated by a tunnel driving machine known as a “shield machine” and tunnel wall is constructed by fixing a pre-fabricated circular pre-cast members called “segments” against each other using bolts. By using the Shield method, circular tunnels with diameters from Ø‘1800 mm up to Ø‘14000 mm could be bored. 4.3.2.3.1 Description of the Technique A tunnel is used for cable accommodation when a lot of circuits must be installed along one particular route, when it is difficult to secure the required transmission capacity using direct burial or ducts. It is also used within urban areas where the logistics of using other techniques at ground level are insurmountable. A tunnel is constructed by open-cut method, shield method, or pipe jacking method. Pipe jacking method is described in Sect. 4.3.3.4. Shield method and pipe jacking method are similar in their shapes. The difference of them is just construction method and only shield method is described here. (a) Open Cut Method (Fig. 4.13) Open cut is a method of constructing a tunnel. First, excavate from the ground surface and then build the tunnel in required location and restore the ground surface by the backfill. The most common method is generally the full face one. (b) Shield Method When Open-cut method cannot be used, the Shield method should be used. It may be applied where the road traffic is too heavy or the tunnel to be constructed too deep to Fig. 4.13 Tunnel built with the open-cut method

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Fig. 4.14 Open cut gallery. Vertical snaking of cable trefoil by suspension (France)

excavate from ground surface because of keeping away from other underground equipment such as telephone cables, gas pipes, water pipes, sewage pipes, subways, etc. Shield method can be used when the subsoil is poor. A shield tunnel is excavated by a tunnel driving machine known as a “shield machine” and tunnel walls are constructed by fixing pre-fabricated circular pre-cast members called “segment” against each other using bolts. Circular tunnels with diameters from Ø 800 mm up to Ø 4000 mm have been constructed in Japan (Figs. 4.15 and 4.16).

Open–cut method

Fig. 4.15 Tunnel boring methods

Shield method

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Body flexing spherical slide mechanisms

Bulk head

Screw conveyer

Copy cutter

Segment

Shield jack Cutter disk

Bending jack Spherical bearing for cutting disk bending Earth Pressure Type Sharp Curve Excavation Shield Machine

Fig. 4.16 Shield machine

Ventilation is generally used in tunnels for human safety. Ventilation also dissipates the heat generated by the cables, thus increasing the transmission capacity compared to direct burial or ducts. When larger transmission capacity is required, cooling system may be applied (Fig. 4.17). Cables in tunnels may be installed in a rigid configuration (normally when there is not much space available) or, more commonly, in a flexible configuration. In the latter case, both vertical and horizontal snaking are used, depending on practical considerations. Unfilled troughs with horizontal snaking may also be adopted.

4.3.2.3.2 4.3.2.3.2.1

Limits of the Technique

Civil Work Since tunnel construction method is much more expensive than construction of ducts by open cut method, it is necessary to carefully evaluate the construction cost. Construction of a tunnel is economically unfavorable when there are only a few circuits to be installed. At the time of constructing shield tunnel, all the route need not be excavated but land for shafts is necessary. Land for ventilating facility is necessary for both open cut tunnel and shield tunnel.

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Oil separator

Oil cooler

Oil pump P

Evaporator

Air cooled condenser

Coolant

Oil

P Circulating pump

P Pump Heat storage tank

Tunnel

Pipe

FRP Trough

Typical Construction of Forced Colling Cable System in Trough

Fig. 4.17 Cooling system in tunnel

4.3.2.3.2.2

Drying of the Soil When the tunnel temperature is low enough for human beings (e.g. 40
C), drying of the soil need not be considered.

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4.3.2.3.2.3

Water Drainage Tunnel is designed as an almost waterproof structure. Seepage water into the tunnel is drained into a pit and pumped to the outside. 4.3.2.3.2.4

Temperature of the Soil / Environment Transmission capacity is decreased if the surrounding soil temperature is high or if the air temperature within the tunnel is high. 4.3.2.3.2.5

Hardness of the Soil Much power is required for excavation in case the soil is hard. But it is not a fatal problem. 4.3.2.3.2.6

Stability of the Soil Stability of the ground is fundamental to the construction of the tunnel since any settlement must not compromise the integrity of the tunnel and shafts. 4.3.2.3.2.7

Thermal Resistivity of the Soil Compared to direct burial or ducts, thermal resistivity of the soil does not have as much influence on the transmission capacity because heat from the cables is mainly transferred to the air within the tunnel. 4.3.2.3.2.8

Seismicity In Japan, a tunnel is designed to have stability against an earthquake with an acceleration of 0.3G and with safety margin for earthquake is more than 2. According to the past experience, it can be said that a tunnel has enough strength against earthquakes. 4.3.2.3.2.9

Frost No need to be considered. 4.3.2.3.2.10

Archaeology (Prehistoric Sites) If prehistoric ruins are found, it should be reported to relevant authority and site investigation should be carried out before the construction. 4.3.2.3.2.11

Presence of Termites Cables should be protected with anti-termite sheath. 4.3.2.3.2.12

Laying in National Park It is necessary to get permission from relevant authorities.

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4.3.2.3.2.13

Duration of the Work Required construction period is as follows. Shaft: Shield Driving:

6–9 months (depth 30 m) 10–15 m/day

Invert concrete, Cable Supporting Material, Lighting: 15–20 m/day 4.3.2.3.2.14

Maintenance and Repairing Process By monitoring for cracks produced in the tunnel wall, erosion rate may be estimated and the most suitable repair method determined. Repairing method varies from simple repair like filling the cracks to large construction projects such as building a steel reinforcement to support the tunnel itself from inside.

4.3.2.3.2.15

Cable Removal After Operation When the flexible installation is applied, it is rather easy to remove the cables.

4.3.2.3.3

Adaptation of the Technique to the Cable System Design

4.3.2.3.3.1

Planning At the time of the planning, various items should be considered such as, number of circuits, supporting material, ventilation, cooling system, working space, road condition, countermeasure for fire, environmental impact since the construction of a tunnel may involve major earth movements, etc. These items affect one another and should be considered systematically.

4.3.2.3.3.2

Basic Design The height of the tunnel needs to be such as to allow adequate space for the installation and maintenance work. Joints are generally positioned within the tunnel with the distance between joints being as long as is possible based on the longest length of cable that can be transported to site and installed. Ventilation is provided by shafts along the route as needed to satisfy the ventilation requirements for personnel access and safety requirements and to ensure the capacity of the link. 4.3.2.3.3.3

Snaking Design It is very important to evaluate the thermal expansion of the cables. To cope with thermal expansion and contraction of single-core cables installed on shelves in tunnels, pits, etc., a snaking installation technique is generally used.

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This technique enables thermal cable expansion and contraction to be absorbed by lateral displacements of the cable initially laid in waves at a certain pitch and width. There are horizontal and vertical snaking installations. Selection between them is made depending on site conditions, available space, economy, etc. Horizontal snaking installations are widely used for fluid-filled cables and both snaking installations are used for XLPE cables.

4.3.2.4 Troughs 4.3.2.4.1 Description of the Technique A trough is a generally prefabricated U-shaped covered housing which is used to protect the installed cable from mechanical damage. The trough can be cast in place as a single element composed of precast sections of approximately one meter long installed end to end or by means of continuous concrete casting process with the top of the sides permitting a structural cover such as concrete or steel or fiber reinforced plastic, to be used to protect the installed cable. The troughs are generally filled with special backfill in the form of selected sand or weak mix mortar to aid heat dissipation. Once the trough path has been assembled, the cables may be installed as in an open trench, either by a pulling or a laying process from joint to joint or from joint to termination. Then covers are placed. 4.3.2.4.2 Existing Installation Techniques There are three types of cable installations in troughs: 1. Direct buried troughs 2. Filled/unfilled surface troughs 3. Unfilled troughs in air (in tunnel)

1. Direct buried troughs Cables are laid in reinforced concrete troughs which are installed in a trench. The troughs are filled by sand and then backfilled completely. Internal dimensions of the trough must be such that enough space exists between cable(s) and internal walls of the trough element (Fig. 4.18): Bottom: ffi 1 cm, Side walls: ffi 1 cm, Cover: ffi 4 cm 2. Filled/unfilled surface troughs Reinforced concrete troughs are installed at the surface of ground as shown in the drawing below and cables are installed in the troughs.

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Fig. 4.18 Cables in trough

Fig. 4.19 Filled and unfilled surface troughs

In the case of filled troughs (sand filling in the troughs), the most likely movement of cable for thermomechanical behavior is in the vertical direction where there is least resistant and lifting of trough lids can occur. Care is therefore necessary to ensure that the trough lids are either heavy enough or sufficiently well fixed to the trough to prevent movement. In the case of unfilled troughs, cables are necessary to be snaked and fixed with cable cleats to cater for thermomechanical behavior same as the unfilled trough in air of class (3) described below. This surface trough type has been used running alongside railways and in substations (Fig. 4.19). 3. Unfilled troughs in air (tunnel) In the case of the reduced transmission efficiency of many cable circuits installation, cables are laid in tunnel and fixed with cleats on hangers. To limit the extension of fire or prevent from external damage, cables could be laid in closed FRP troughs as shown below (Fig. 4.20).

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FRP trough

Cable

Fig. 4.20 Unfilled troughs in air

4.3.2.4.3 Installation Methods Cable installation using troughs is classified with regard to installation method: namely direct buried trough and filled surface trough are of the rigid type, while unfilled surface trough and unfilled trough in air are of the flexible type. 1. Rigid type The bottom of the trough is filled with a layer of thermally suitable sand backfill or weak mix mortar before laying the cable. If the cables are in trefoil, then after laying the bottom cable, the trough is backfilled to the top of the installed cable to eliminate the air remaining in empty spaces and in preparation of the next cable to be installed. After installation of all three cables, the trough is completely filled with sand, then covers are installed, sealed and eventually fixed. For buried troughs, backfilling is achieved in several successive layers carefully compacted. 2. Flexible type When single core extruded cable is installed in the straight line in unfilled surface trough or in unfilled trough in air, irregular thermal cable movement occurs due to longitudinal thermal expansion. So, snaking installation, where cables are laid in waves at a certain pitch and width, is applied to absorb thermal expansion and contraction. The dimension of snake is determined by considering the cable occupied space, axial force at the end of snake section, workability of snaking and so on.

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• Kinds of snake There are two type of snaking, one is horizontal snake and the other is vertical snake. Horizontal snake is applied in cable installation into the trough. • Sheath distortion Sheath distortion of cable with metallic sheath is in most cases sufficiently less than the permissible value, when the above-mentioned parameters are adopted. This is confirmed theoretically and practically. Whenever necessary, precise calculations can be performed according to the design criteria described in Sect. 4.4.1.1. • Other There are some cases that the cables are bound together at regular interval against electrodynamic force at the occurrence of short circuit. 4.3.2.4.4

Limits of the Technique for Buried Troughs

4.3.2.4.4.1

Civil Work For buried troughs, civil work include excavation of a trench and shoring when necessary. After installation of the cable as described before, the trench is backfilled and different layers of the native soil are compacted. Limits are the same as for directly buried cables with an additional limit concerning bending radius which is generally 70 times the cable outside diameter. 4.3.2.4.4.2

Drying of the Soil The buried troughs method is better than direct buried method because of the improved heat flow provided by the use of concrete trough 4.3.2.4.4.3

Hardness of the Soil Same limits as for directly buried technique 4.3.2.4.4.4

Stability of the Soil If the soil is not stable, it is necessary to anchor the troughs on a concrete sole. 4.3.2.4.4.5

Thermal Resistivity of the Soil Troughs material and backfilling inside and outside the troughs can be selected to take account of the thermal resistivity of the soil.

4.3.2.4.5 Limits of the Technique for Surface Troughs The use of this technique is strictly limited to these cases where the right of way is the utility property.

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Description of Innovative Techniques

These techniques have been developed more recently, mainly to reduce cost and to accommodate the increasing demand to transmit more power using high voltage cables. They are categorized as innovative as very few companies have used them to date. Some special applications such as underground hydroelectric power stations required the use of shafts to house high voltage cables. Lately, the horizontal drilling technique was borrowed from the oil and gas industry and used as a trenchless method to lay cables. It is mostly suited for environmentally sensitive locations as well as river crossings. Mechanical cable laying has also been developed to install high voltage cables quickly and economically over long distances. It is expected that more innovative techniques will be developed in the future to meet the increasing demand for underground high voltage cable laying. CIGRE WG B1.48 published in July 2019 the Technical Brochure 770 “Trenchless Technologies” to cover all innovative Trenchless techniques When appropriate, the content of TB 770 has been used to write this section (update of parts of TB 194).

4.3.3.1 Bridges 4.3.3.1.1 Description of the Technique It is common to use existing bridges where the cable route is crossing rivers, railways, road junctions etc. Some bridges have a natural space for placing cables, either inside the bridge or in the sidewalk. Some bridges are dedicated to cables (Fig. 4.21) On concrete bridges the cables are placed in precast troughs in the sidewalk where the cables are directly laid. Single core cables are laid in trefoil to reduce the magnetic field (reduction of the circulating current in the sheath and then of the losses). The trough is filled with cement bound sand which has a low thermal resistivity. The space available is often limited and does not allow making joint pits. On steel profile bridges, the cables can be laid in steel profiles or on cable ladders. In this case additional protection is needed, especially at the piers. The cables can also be directly cleated on the bridge or installed into ducts. Before deciding to use an existing bridge as a crossing, a careful study should be made. The designer has to take into consideration the dynamic mechanical stress caused by its vibrations, elongation and bending at junctions and the environmental stress such as sunlight heat and wind pressure. When constructing new bridges there should always be a design with a space for possible future cables. Cast-in ducts make it easy to pull the cables through the bridge. But again the offset of the cables at the piers is very important. Vibration If cables, that have an extruded metallic sheath, are installed in bridges the vibration generated by automobiles and trains may introduce strain into the

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Fig. 4.21 Dedicated tunnel for cables

sheath, which could lead to fatigue. To reduce this strain to an acceptable value it is necessary to design the cable supporting method and cable supporting intervals with regard to their resonance frequency.

4.3.3.1.2

Limits of the Technique

4.3.3.1.2.1

Civil Work The civil work will normally be to make modifications or extensions of the existing bridge structures. This should be done in close co-operation with the owner of the bridge to avoid reducing the mechanical properties of the bridge. The transition zone at the piers is the most critical points. Here the cable needs to be installed with an offset to compensate the thermal movement of the bridge. It should also be considered if the magnetic field or the increased temperature may affect the lifetime of the bridge. A research made in Norway in 1995 show that the risk is low. The cable racks/ trays and sun shielding should allow the maintenance of the bridge. If the cables are laid in unfilled troughs, a drainage system should be provided.

4.3.3.1.2.2

Temperature of the Soil/Environment The temperature variations have to be considered when calculating the ampacity of the cable. The temperature is significant in assessing the thermal expansion of the bridge and hence the cable offset to cater for this expansion.

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4.3.3.1.2.3

Seismicity In areas with seismic activities, the cables should be laid with a larger offset at the transition zones

4.3.3.1.2.4

Frost If the cables are laid in unfilled troughs, a drainage system should prevent ice in the through.

4.3.3.1.2.5

Presence of Termites The cable designer should take care of the protection against termites. Tin-bronze tapes are widely used together with a PVC protective covering with an anti-termite repellent additive.

4.3.3.1.2.6

Maintenance and Repairing Process The space for repair is often very limited. If a damage occurs, replacement of the cable on the whole length of the bridge may be needed.

4.3.3.1.2.7

Cable Removal After Operation If cables are laid along a bridge it is normally easy to remove the cables if they have to be replaced.

4.3.3.2 Shafts 4.3.3.2.1 Description of the Technique Shafts are generally used in hydraulic generation plants where the power generated from the underground equipment have to be brought up to the beginning of the aerial lines. Shafts may also be part of cable routes in cities where the cables are running in deep tunnels and must be connected to aerial lines or substations (Fig. 4.22). Cables may be fixed with clamps at the shaft walls or to metallic structures. Several circuits may be installed in the same shaft; in this case walls or special structures are used to reduce the possible damages in case of problems of one of the circuits. Joints, if present, are normally installed in horizontal configuration in special chambers to be purposely created. Sometimes the shafts are used as vent of the production plant, and the air temperature during normal operating conditions has to be considered when designing the installation layout.

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Fig. 4.22 Typical Installation in Shaft

4.3.3.2.2 Limits of the Technique In case of extruded cables, attention must be paid to the significant expansion coefficient of the cables, limiting the restraining force that each clamp may transfer to the cable and hence requiring special care while designing the supporting structures. Special clamps will have to be used in this case. The laying operations, require the use of special procedures and tools to be adopted. The design of the installation shall carefully consider the laying aspects in terms of space and sufficient working areas. Laying of the cables is normally carried out from the top of the shaft, and enough space for reel and cable laying equipment handling has to be present. Transportation of the cables inside the terminal station may be also a critical aspect if for example the station is completely underground. In shaft the safety aspects have a significant impact, because short circuits or explosions may lead to the complete failure of the circuits. Special structures or precautions shall be taken to minimize the effect of fire inside the tunnel. Special laying tools and ancillary structures will have to be in place and available during the whole service life to allow the recovery and replacement of a faulty phase.

4.3.3.2.2.1

Civil Work Shafts are often designed as part of the power plant or tunnel structures and the cable installation design shall consider the existing facilities. Sometime calculation has to be made to be sure that the existing facilities can withstand the weight of the cable and the relevant structures. In case of FF cables, not covered in this chapter, following the maximum allowable cable length, joint chambers will have to be built on purpose along the shaft. The size of the chambers shall take into account the size of the joints, the number of cables and the structures to be installed.

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4.3.3.2.2.2

Water Drainage Water may permeate through the shaft walls, and heavy moisture may condense over the cables. Corrosion problems must be carefully considered when selecting the materials for the supporting structures. 4.3.3.2.2.3

Temperature of the Soil/Environment The design of the whole system requires the knowledge of the shaft temperature in operating conditions and the annual excursions to evaluate the thrust developing in the cables. 4.3.3.2.2.4

Thermal Resistivity of the Soil In shafts the cables are installed in air that can circulate from the bottom to the top of the shaft. Generally, no cooling problems are present 4.3.3.2.2.5

Seismicity Accelerations imposed by earthquakes may have to be considered when designing supporting structures. Being the shaft part of the station or tunnels civil works, the civil structures are already designed considering these accelerations. 4.3.3.2.2.6

Duration of the Work As the laying and jointing operations are carried out in substations and in the shaft itself, the operations can be planned quite easily. On the other side, installation works may last more than usual, due to the particular care to be taken for cable clamping. 4.3.3.2.2.7

Maintenance and Repairing Process Maintenance for cable in shaft may consist of a periodical visual inspection on:

• cable sheath • supporting structures and fixing devices • joints In shaft the repair of a faulty phase will involve the recovery of the faulty cable and the lay of a new cable. Repair of an existing cable putting joints in the middle of a cable length is generally not possible. 4.3.3.2.2.8

Cable Removal After Operation Cable removal is possible but with difficulty due to access restrictions caused by access stairways and other features installed after the original cable installation was undertaken. Removal is in the same manner as installation but precautions must be taken to ensure personnel safety and that no damage can occur to the remaining cables in the shaft.

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4.3.3.3 Horizontal Drilling 4.3.3.3.1

Description of the Technique

4.3.3.3.1.1

Introduction Augers, vibratory pipe reamers, micro-tunnellers, directional drilling, pneumatic moles; all of these are devices for installing underground facilities with a minimum of digging required. Many of the techniques and equipment have been around for many decades, however the most interesting and versatile trenchless technique, in use is the Horizontal Directional Drilling (HDD) also called guided horizontal drilling. Horizontal Directional Drilling (HDD), sometimes referred to as guided boring, is a trenchless construction technique used for the installation of services such as water, gas and electricity, under natural or artificial obstacles, such as large services (such as metro lines), roadways, highways, slope drillings, train tracks, rivers, etc. It minimizes the environmental impact and causes less disruption to the surrounding urban and suburban areas.

4.3.3.3.1.2

Principle The normal HDD process consists of drilling a pilot hole in the ground, and then back reaming to open the pilot hole to take a casing pipe. Conduits may then be pulled into the casing pipe and cables may then be pulled into these conduits. HDD may have one conduit per phase or, depending on length and pulling tensions, all three phases may be installed directly in one pipe. HDD casing pipes are normally 600–1000 mm diameter, whereas conduits are usually 200–300 mm diameter, and depending on the geology and cable design lengths up to 3,000 m may be achievable The Horizontal Drilling equipment is composed of the drilling rig, drilling bits, drilling rods, the drill guidance system, drilling fluids, mud pumps, and recycling/ ancillary equipment, all of which will be discussed further in Section 2.2 below. However, large working areas must be planned to include the temporary location of the equipment and pipe fabrication during the drilling works and during the installation of the pipes or cables. A number of construction techniques are possible for a HDD installation and the type selected will depend on a range of characteristics, e.g., the rating required from the cable, the depth of the cable, the size of the cable, etc. as well as geology, geography, logistics, environmental constraints, etc. The four main techniques are as follows:

(i) Drill the hole, enlarge and/or condition the hole and pull the cable/s directly into the hole. (ii) Drill the hole, enlarge and condition the hole, install a casing large pipe into the hole and pull cables directly into the pipe.

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(iii) Drill the hole, enlarge and condition the hole, install a large casing pipe into the hole, pull a bundle of conduits into the casing pipe and pull a cable into each conduit. (iv) Drill the hole, enlarge and condition the hole, pull conduits into the hole without using a large casing pipe and pull the cables into each conduit. Alternatively, it may be possible or necessary to drill individual holes for each phase, one cable (with conduit) per hole. The type of material selected for the casing pipe and conduits will depend on electrical and HDD engineering factors; the most commonly used materials are PVC, HDPE and steel. Technique (i) would typically be used where individual drills are planned for the individual phases of the high voltage cable circuit. This may be specified where the required rating of the cable is such that a large separation distance is required between phases of the cable circuit. Where technique (ii) is used the pipe provides more protection for the cable or cables than technique (i). Thermal grout may be required to completely fill the annular space of the casing pipe surrounding the cables. Technique (iii) gives added protection to the cable, but it also allows for easy retrieval of a single phase if required. Thermal grout is generally required to completely fill the annular space of the casing pipe surrounding the conduits. Technique (iv) may be used where the size of the hole is limited and there is not enough space to accommodate a large pipe, but there is a requirement that individual conduits be installed for each phase. In selecting one of the above techniques, one must also consider the possible impact of cable repair and cable retrieval if needed for example if all three phase share a pipe (without conduits) then, in the event of a fault, it may not be possible to pull out one of the phases without pulling out all three phases. Some of the factors listed below have resulted in an increase in the use of HDD in the last years: Trenching in areas with many existing services can be quite costly, because the work must be done slowly and carefully in order to avoid damaging existing services. Otherwise it may be necessary to relocate the existing services to facilitate trenching Traffic disruptions can be restrictive and authorities may insist on HDD methods being used to avoid road closures Depth of the trench versus cost. If deep trenches are required, they can be costly from an excavation and shoring point of view Environmental aspects; no surface trenching is required when using HDD, so the environmental impact is less Aesthetics; trenchless construction generally leaves no surface trace and regulators are becoming more sensitive to public concerns in this area

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HDD is also commonly used to build land-sea interface connections. HDD technology avoids digging trenches by and through the seashore and offshore areas, where it is much more difficult to work. This avoids working in difficult weather conditions and also avoids working in environmentally sensitive or protected areas. 4.3.3.3.2 Process A feasibility assessment of the project must first be carried out. This will be covered in more detail in the section relating to Geotechnical and Surveys below. Once the feasibility has been established and the launch and exit pit locations have been selected, the construction may proceed as shown in Figs. 4.23, and 4.28. 4.3.3.3.2.1

Pilot Drilling The pilot bore is drilled between entry and exit pits at the planned depth, taking into account the necessary clearances to other services or to the terrain surface, in order to avoid “frack-outs” or drilling fluids bubbling to the surface, to aquifers, to river bottoms, wetlands or to the sea. The main characteristics of any drill are the following:

Its minimum radius is limited by the maximum deflection of the drill rods and the flexibility of the cables or the pipes (if used). The angle of the launch depends on the size/characteristics of the drill rig, the depth and the length of the drill and the size and material properties of the pipes, conduits and cables to be installed. Figure Fig 4.24 shows the pilot bore being drilled. This is the first step in construction and the pilot drill starts at the launch pit, where the drill rig is positioned, and proceeds to the exit point at the other side of the service or obstacle to be crossed. The route of the drilling can be modified, if unforeseen obstacles arise during the drill. A steering system is used to guide the drill bit along the planned route from entry to exit. Depending on the depth of the drill and the surface conditions above the path, the guidance may be accomplished by a relatively simple

Fig. 4.23 High level picture of HDD

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PILOT HOLE DRILLING

NON-MAGNETIC DRILL DRILL COLLAR BIT

ORIENTATION SUB

Fig. 4.24 Pilot drill

“walk-over” tool or a more complex downhole steering tool regularly accompanied by a surface tracking wire. In order to facilitate the drilling “mud”, generally a mixture of water, bentonite clay and polymers is often used. During the pilot drilling drill rods are linked (screwed) together to form a drill string; these assist with advancing the drill bit and pulling back reamers and products such as the pipe, conduits or cable (Fig. 4.24). Cuttings must often be removed and the drilling fluids cleaned and recycled using a combination of devices such as pumps, tanks, shaker screens hydro cyclones and. centrifuges. Excavated pits or holding tanks for capturing the returned drilling fluids are located close to both the entry and exit pits. Any residual material that becomes contaminated or cannot be cleaned and refurbished is removed for disposal in an approved manner.

4.3.3.3.2.2

Back Reaming After the pilot bore is completed, the drill bit is removed and a back reamer as in Fig. 4.25, is attached to the end of the drill rods. The back reamer is used to enlarge the hole to the required dimension. However increasingly larger sized reamers may need to be pulled or pushed through the bore a number of times, if the hole dimension required is significantly larger than the pilot bore. The type of reamer selected must be suitable for the soil or rock type.

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PRE-REAMING

REAMER DRILL PIPE

DRILL PIPE

Fig. 4.25 Back reaming

PIPELINE PULLBACK

REAMER

PULLHEAD

PIPE

SWIVEL

Fig. 4.26 Pipe pullback

On the last back ream a high tensile strength swivel, smaller reamer or barrel reamer and a pulling head will be added. This will pull in the pipe, a bundle of pipes or a bundle of cables, depending on the installation technique selected. Figure 4.30 refer, where the product being pulled in is the pipe/conduits into which cables will be installed at a later stage (Figs. 4.26, 4.27, and 4.28).

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Fig. 4.27 Casing pipe and conduits Casing

Conduit

High Voltage Cable

Fig. 4.28 Section of drill showing casing pipe and conduits

4.3.3.3.3 Cable Rating and Bonding Note in the case of HDD where cables are installed in separate drills, the termination points may actually be the limiting situations with respect to the current rating, because the cables are normally closer together at the terminations. So, this should also be checked when considering the rating of HDD installations. The following factors have also to be considered: 4.3.3.3.3.1

Depth of the Installation As with any buried cable installation, greater depth generally results in lower ratings. This may be mitigated somewhat by lower summer time ambient earth temperatures and possible better earth thermal resistivities at the greater depth. In common with other trenchless installation methods, transient thermal ratings for HDD will be

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different from those for typical trench depths in terms of response and they should be evaluated individually. Burying cables at large depths is becoming more common these days because: Cables are installed in directional drillings at up to 40 m laying depth for crossing rivers, rail tracks, motorways or suburban areas with minimal nuisance for public Cables cannot be installed at the usual depth (typically 1.0–1.5 m) in urban areas as these are already congested with other infrastructure. The current rating of shallow cables is influenced by daily, weekly and even yearly load variations. These effects are not so profound for cables installed at deep depths. These effects are also not considered currently by the IEC standards. Therefore, the standard IEC60287 approach might lead to pessimistic results and another approach for determining the current ratings calculations is needed. The IEC Standard 60287-2-1 contains a statement about very deep installed cables: for cable circuits installed at laying depths of more than 10 m, an alternative approach for calculating the current rating is to determine the continuous current rating for a designated time period (usually 40 years) by applying the formulae given in IEC 60853-2. This subject is under consideration’. Various papers have been published on ratings of cable installed at depth. A good summary and guidelines can be found in IEEE Dorison et al. (2010) Ampacity Calculations for Deeply Installed Cable PAS 2010. This paper provides equations and guidelines for deeply installed cables, taken into account daily, weekly and yearly cycles. Furthermore, this paper introduced the concept of ‘equivalent laying depth’, which makes it possible to use the continuous current rating calculations and avoid the more complex transient approach. For deep directional drillings, the cable circuit may cross through various soil layers, which might have different thermal properties. For this condition, the guidelines in CIGRE Technical Brochure 640 “A guide for rating calculations of insulated cables” shall be followed. IEC guidelines exist for calculating the rating of cables installed in horizontal ducts. No papers or articles exist describing accurate calculation techniques for cables installed in inclined ducts. There is also an important gap in the tooling for calculations, as horizontal directional drillings are often filled with water. In general, for deep cables, IEC 60853-2 and IEEE Dorison et al. (2010) Ampacity Calculations for Deeply Installed Cable PAS 2010 can be used to calculate the rating for daily, weekly and yearly cycles. 4.3.3.3.3.2

Separation between phases Depending on depth and the rating required it may be necessary to increase the separation between the phases in order to permit a greater flow of heat into the surrounding medium. 4.3.3.3.3.3

Bonding In any circuit design, it is necessary to ensure the bonding design is suitable for purpose. Obviously higher ratings can be achieved with single point bonding or balanced cross bonding.

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HDD installations are normally quite long and the phase separations may be high. These conditions may result in very high sheath induced voltages under normal and short circuit operating conditions. In the case of solid bonding and cross bonding, any increase in separation between phases will lead to magnetic imbalance, circulating currents and may lead to a reduced ampacity rating in the circuit. It will be necessary to ensure the outer serving design can tolerate these voltages and also to ensure that national limits for standing voltages, if they exist, are not exceeded. For example, in the UK there is a limit of 65 V for cables with an operating voltage up to 132 kV and a limit of 150 V for higher operating voltages and in France the limit is 400 V. Different national limits may exist. Bespoke serving designs may be required, if limits are to be exceeded. The following current CIGRE references cover bonding designs; Electra 28,128, 283 and 347.WG B1.50 is currently working to produce a Technical Brochure on SVL and bonding systems (design, testing, operation and monitoring).

4.3.3.3.3.4

Pipe material and losses If steel pipe/s are used, they may have magnetic losses that will reduce the rating of cable systems. The degree of derating due to the pipe will depend upon properties of the steel, the cable construction, the sheath bonding method, and the cable/s position within the pipe/s. Close triangular spacing with optimization of separation from pipe wall can reduce the losses. IEC60287-1-1 provides empirically-derived equations for calculating the Joule losses in steel pipes normally associated with pressurized pipetype cables, where the pipe diameter and cable phase separation are relatively small. These equations are based on experimental tests done in the 1950s on a particularly circuit (Morris, 1954) (Katz, 1978) and were derived for the size of pipe, type of steel and typical current loading most commonly used in the USA and select countries worldwide. The equations given are for two common configurations, cradled at the bottom of the pipe when the ratio of pipe inner-diameter to cable skid wire diameter is 1.6 or greater or triangular for when this ratio is smaller than 1.6, of the three cable phases in a pipe-type cable system. The empirical equations were developed from tests on a particular cable pipe with a given permeability. In practice, the permeability of steel line pipe varies both due to variation in the characteristics of the pipe, but also due to handling during installation including welding, heating and bending that occur during installation. The reader should note that installing individual cable cores in ferromagnetic pipe can result in significant hysteresis losses that may exceed the losses of the cable conductor and metallic screen/sheath of the cable. Installing individual cables in carbon steel pipe should be avoided. Pipe-type cable systems minimize this problem by using non-magnetic stainless steel pipes for each phase between the trifurcator and termination. A concrete pipe is preferred as there are no magnetic losses (steel reinforcing bar and the steel collar sometimes used to distribute the pushing forces typically do not result in appreciable derating), and the concrete will typically have a lower thermal resistivity than the native soil material it is displacing. Other non-magnetic pipes

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such as centrifugally cast fiberglass reinforced polymer mortar, and clay, do not contribute to electrical losses and have reasonable thermal resistivities. 4.3.3.3.3.5

Conduit material and losses Most installations use PE or PVC conduit similar to the conduit in open trenched sections (although perhaps with a slightly greater wall thickness for mechanical strength) so the effect on the rating is small. If thick-wall high-density polyethylene conduit is used, as is commonly done for horizontal directional drills, there could be a small reduction in the rating. Spacers can be designed to hold the conduits in the optimum position in the pipe to improve rating. Typically, conduits consist of a layer of solid PE material. This leads to a relatively simple calculation of the thermal resistance of the conduit wall as described in IEC60287. Sometimes conduits are not filled i.e. they only have air inside them. The thermal resistance of such an installation might be high, if heat convection in the air enclosures is prevented. As a worst-case approximation, stationary air with a specific thermal resistivity of 40 Km/W can be used when modelling the behavior of such a conduit, according to TB 640 “A Guide for Rating of Insulated Cables (Dec 2015)”. Outside rock or native soil is found which can be taken into account in the rating calculation. 4.3.3.3.3.6

Pipe/conduit filling. It is important to consider the thermal resistivity of the HDD pipe and conduit filling material. The filling material may be a solid or a solidifying substance such as bentonite or it may be a fluid, such as air or water. In the former situation – a solid – heat transfer from the power cable is governed by conduction. This means that the heat transfer can be modelled with the means, as described in IEC 60287-2-1. In considering the above one must also consider the filling delivery system and filling pumpability and shrinkage properties – particularly for lengthy HDD systems. It is important to consider whether or not any air spaces might exist between the installed conduit and/or pipe and the surrounding ground and if so, what measures are necessary to fill those air spaces If the pipe is filled with a fluid, the situation is more difficult, as detailed below. Horizontal – Water – Closed at both ends A horizontal cable system in a perfect horizontal water filled pipe, closed at both sides, can be considered in the same way as above, though the properties of the fluid are of course significantly different. One should consider the possibility of axial heat transfer in the water-filled conduit in addition to the radial heat transfer through the conduit. Also consider the possibility of air pockets in case of water-filled ducts, which may need to be avoided. If the pipe is not fully closed and it is completely underground and there is water filling, the pipes can lose the water filling to their environment leaving an (unexpected) air gap. Also note height differences between the pipe ends may lead to an air gap, if water is expelled from the conduit. 4.3.3.3.3.7

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• NON HORIZONTAL In non-horizontal arrangements, the situation is significantly more complex, because there will also be axial heat transfer in addition to the radial heat transfer and this can have a significant effect. This means that the warmest locations are expected to be near the higher sides of the pipes. One needs to be careful when defining a current rating of an inclined conduit. The heat transfer may be governed by convection and radiation, which are strongly temperature and geometry dependent. • THERMAL RESISTIVITY (TR) OF GROUND One must also take into account the thermal resistivity of the rock or native soil outside the pipe or conduits. Note that different soil layers with different thermal properties may be crossed during horizontal directional drillings. Geological data may provide some initial guide – this is covered in more detail in Section 2.7 below. The most common approach to handling non-homogeneous thermal properties is the use of the finite element or conformal mapping technique as outlined in CIGRE Technical Brochure 640 prepared by CIGRE WG B1.35, A Guide for Rating Calculations of Insulated Cables. In the case of conduits crossing multiple layers of soil, if there is a fluid inside these conduits (water, bentonite), the possibility of axial heat transfer along the conduit may be considered, refer to CIGRE Technical Brochure 640 Section 7.2.2.2. In addition, a deeper layer of soil with unfavorable thermal properties may have an effect at another (higher) location along the drilling. Conversely a layer of soil with good thermal properties may assist in removing heat in a longitudinal direction and help the cable’s rating. Simply taking the radial heat transfer may not be sufficient to correctly model the installation. Multiple soil layers are discussed in CIGRE Technical Brochure 640 Section 7.2.1.5. 4.3.3.3.3.8

Distributed Temperature Systems Distributed Temperature Systems may offer some more confidence in trenchless technology installations where the cable rating has to be determined. This is covered in greater detail in TB606 Upgrading and Uprating of Existing Cable Systems (WG B1.11) and TB247 Optimization of Power Transmission Capability of Underground Cable Systems using Thermal Monitoring (WG 21.04 ?). See also TB 756 published by WG B1.45 in February 2019. Optic fibers, either integrated within a cable structure or attached to cable servings, are now common features in transmission cable installations for the purpose of distributed temperature sensing (DTS) and to take advantage of other sensing opportunities under development including partial discharge detection (PD) where optic fiber is both the “sensor” and the “data transmitter”. DTS has special significance in trenchless technology (including microtunnel and pipe jacking installations) where soil conditions, including temperature, may be difficult to predict at the circuit planning stage.

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4.3.3.3.3.9

Drying of the soil. The design of the installation shall consider the possibility of drying out of the soil at the external surface of the pipe. This might result in a thermal runaway causing cable insulation failure, if the system is heavily and continuously loaded. Drying out of the soil is not of any importance, if the permanent groundwater level is above the pipe installation. Therefore, the groundwater level must be verified at the geological survey stage before the detailed design of the HDD installation is completed. Additionally, the soil characteristics (thermal resistivity and drying out performance) must also be clarified during the geological survey. Drying out of the soil can be expected to start at a continuous temperature of 50
C depending on the soil characteristics. In sand, the drying out phenomena will most likely start at a lower temperature. Drying out of the soil must be considered in particular for cable systems designed for a continuous load. If the cables are installed at a large depth this might result in a bottleneck for the current capacity of the whole link, since available measures against the possibility of the drying out of the soil at that location are limited. Improving the soil characteristics at depth by substitution of soil with better thermal performance is not possible. Injection of a “specific developed fluid with excellent thermal properties” within the pipe or conduits will only have a minor effect, since the major thermal resistance appears in the soil. The above-mentioned heating problem can be prevented if a cooling arrangement is applied. Natural or forced air circulation in the cable pipe/conduits can remove the heat generated by the cable cores. Alternatively, a water cooling system can be adopted. A cooling system will result in additional installation costs and require supervision and maintenance on a larger scale than the cable system, which in the case of XLPE cables is practically maintenance free. The technical brochure 714 being produced by WG B1-41 considers issues relating to soil thermal characteristics in more detail. 4.3.3.3.3.10

Temperature of the soil/Environment The temperature of the soil/environment plays a key role in the cable ratings. A HDD installation will be performed at a depth more than 5 m in almost every installation. The temperature at the upper surface layers (depths 0.2 – 1.0 m) varies over time depending on the sun’s heat, wind, and air temperature. The amplitude of the fluctuation in the soil temperature reduces with increasing depth and is nearly absent from roughly 7 m in depth (depending on soil thermal properties). At the typical depths HDDs reach (>10 m) any daily, weekly or seasonal variation in the ambient temperature is thus absent, while at the entry and exit points of an HDD, these variations do have their effect on the current rating of a power cable. This is described in more detail in TB 640. Of course, one must also consider the effect of HDD spacing. At deeper depths, if there is to be more than one HDD pipe then the individual pipes must be further apart to help the drilling process. If solid bonding is used this will lead to increased circulating current and sheath losses, but is mitigated by the increased cooling effect due to the greater separation. On the other hand, if it is decided to eliminate the

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circulating currents by using single point bonding this will lead to increased standing voltages on the cable sheaths.

4.3.3.3.4 Mechanical and Cable Installation As discussed above, the four main HDD techniques are as follows: (i) (ii) (iii) (iv)

Pull the cable/s directly into the drilled hole Pull the cable/s into a large casing pipe installed in the drilled hole Pull the cable/s into conduits which are installed directly in the drilled hole. Pull the cables directly into conduits, which are installed in casing pipe, which has been pulled into the drilled hole

Where individual cables are being pulled into short individual bores, the hole may be drilled and the cable could be pulled directly into the hole. Of course, this will also depend on the stability of the soil i.e. it must be clear that hole will not collapse either during or after cable installation as this might damage the cable/s Where individual cables are being pulled into individual pipes, the cable is more easily accessed for the purpose of retrieval at its end of life. If multiple cables were to be pulled into the same pipe there is a high risk of the cables twisting in the pipe. This would pose a problem for asset retrieval at its end of life and it will be difficult to remove just one cable from the bundle. Where multiple conduits are pulled into the same pipe there is some risk of the conduits twisting in the pipe. However, if individual cables are pulled into the individual conduits this would assist with easy asset retrieval at the end of life. When pulling the cable into the HDD drill, if a narrow sloping entry ramp has been installed as part of the construction of an entry pit (to facilitate installation of conduits), the same entry ramp will assist in guiding cables directly into the conduits. The bending radii of the pipe, conduits and the cable/s must be considered during the design of the drill trajectory and positioning of the launch and exit pits. The larger the pipe/conduit diameter the gentler the angle of entry and exit must be. For example, the minimum installation radius for HDPE pipes shall be 40 times the diameter of the tube and for steel pipes it shall be 1000 times the diameter of the pipes. Matters relating to mechanical fatigue in the cable due to its movement (expansion and contraction) over its lifetime and the effect of this on the structure of the cable and, duct deformation effect due to the cable thermal expansion, are not unique to trenchless technologies and are relevant to all conventional ducted cable installations. Working Group B1.34, Mechanical Forces in Large Cross-Section Cable Systems covers this item in more detail. As a general rule, the internal diameter of a duct should be (minimum) 1.5 times the cable outer diameter. A number of factors must be taken into consideration when installing the cable/s, such as;

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• Compliance with cable manufacturer’s cable technical parameter for permissible pulling tensions • Length and profile of entire cable section • Type of transition at entry and exit pits • Friction factor between cable type and duct – with particularly relevance to the cable outermost serving material (and arrangement of optic fiber if attached externally to one or more phases) and material and type of duct, e.g., HDPE or PVC. • Whether the pipe is filled with water and if buoyancy applies • Most common arrangements involve a combination of cable puller (complete with pulling tension monitor); cable drum with motorized cable dispensing mechanism and, intermediate caterpillars where required – with all devices synchronized. • Are the conduits to be filled after the cables are installed and how is this to be accomplished? HDD pulling tensions are of considerable importance in the process of cable installation. The maximum pulling tensions and minimum bending radii are provided by cable manufacturers for particular cable types. It is essential that the cable pulling calculations are carried out for the installation being considered, as it may be that a particular design of cable is required to meet the values calculated. The overall duration of the construction of a HDD and installation of the cable system is dependent on a number of parameters, the most important of which are: • • • • • • • • • •

Geological conditions of the underground environment Size and depth of launch and exit pits and size of the working area. Diameter and length of drill Progress by drill Mud recycling process Requirements for dumping of spoil Permitted working hours Installing of cables inside pipes/conduits Laying and connecting of cables inside the launch and exit pits Filling of pipes/conduits, if required

Reinstatement of the pits and the working area In addition, because of very long lengths or because of the soil type, a greater separation may also be required in order for the drill head to be steered successfully for the installation of multiple pipes or conduits.

4.3.3.3.5 Maintenance and Removal/Repair The preferred practice for installing cable in HDD is in a conduit. In the event of a fault on a cable in a conduit the normal practice is to pull the cable out and pull a new cable in.

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Advantages and Limits of the HDD Technique

4.3.3.3.6.1

Advantages The following are the perceived advantages of HDD installations: -

1. Safety: Opening trenches can endanger pedestrians and traffic and can also lead to cave-ins, trench debris, and failed or improperly installed cover plates. HDD avoids these pitfalls. 2. Convenience: With HDD, businesses, homes, and commuters are less inconvenienced by traffic backups, dust and uneven pavements, when compared with trenching. 3. Productivity. With HDD, installation progress can exceed open trenching by as much as 5 times on a daily basis. However, in many countries where it is possible to work with direct burial, HDD is only used to cross obstacles. This is mainly based on cost and the length limitations for HDD as well as the fact that cables are accessible for repairing by excavation. 4. Conflict Reduction. Increasingly congested utility corridors and easements make it very difficult to place cable or conduit by open trenching. Directional drilling can be a solution to this dilemma, also reducing the risk for damage during excavation from third parties. 5. Route Selection. Drilling may allow for different or shorter routes. In addition, in many cities, there are moratoriums on opening recently paved or refurbished road surfaces; in such cases many local governments/authorities prefer the use of HDD instead of open trenching. 6. Reduced Environmental Issues. With HDD water run-off from job-site excavation is minimized as is also the risk of excavating and disposing of soils that may be contaminated. In addition, the impact of the regulatory restrictions related to excavations in wetlands and other sensitive areas is considerably reduced when compared with trenching – the only excavation required is for the launch and exit pits 7. Cost Savings. HDD may provide significant savings due to faster installation time, less backfill materials used, traffic control issues, pavement removal, separation from other services, reduced spoil handling and trucking costs, especially in urban environment. 8. The HDD drilling process performs well in a range of ground conditions including silt, sand, clay and many solid rock formations. HDD has excellent steering capabilities. 4.3.3.3.6.2

Limits Although the use of HDD can be a faster and more efficient means of installing cables, there are cases where technical limitations outweigh the potential benefits. In those situations, hybrid installation practices could be considered, i.e. open trenching and drilling used in the appropriate locations.

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The following limit the effectiveness of HDD or cause problems during the installation: 1. The necessary hole diameter exceeds the capability of the available equipment. 2. The depth of installation doesn’t allow enough cover to prevent the drilling fluids from percolating to the surface i.e. possible frack-out 3. Long segment/section lengths between pit locations may mean deeper HDDs and bigger cables, this may lead to a less cost-effective solution. 4. The HDD length required on the route cannot be achieved due to the limitations imposed by length, geology, drilling rig capacity, space for site set-up, etc. 5. Maximum allowable pulling tension on the cable may be exceeded, depending on the length of the HDD section. To overcome this a special and more expensive cable may be required 6. The standing voltage limit, if there is one, is exceeded due to the excessive length of the installation and/or (for separate drillings) high axial spacing between phases 7. The underground environment contains flowing sands with high water table or contains a rocky environment not conducive for the proper directional controls needed. 8. The drill head gets stuck because of ground geology and the drilling fails. 9. Where numerous drills are required, for example if multiple cables are required per phase, the required size of the launch and exit pits may be a limiting factor depending on the local topography. The necessary separation to permit successful drilling of each drill hole and its impact on the working site and on the current rating must also be borne in mind 10. HDD is limited by the maximum reaming of a pipe with an internal diameter of 1.8 m. 11. HDD does not perform well in locations with gravel soils, boulders, and compact stone layers. The changing ground formations and mixed soils create difficulty in controlling the drill direction (e.g. Sandy soil or limestone layers), due to voids within the soil mixture. There is also the possibility of loss of drilling fluid pressure. 12. Coarse-grained soils, or soils that contain boulders or cobbles, encountered during the HDD process, can result in an increase in the overall project duration and cost. 13. Where the ground contains voids or sinkholes it may be very difficult to successfully steer the drilling head and there is also the possibility of the HDD installation process causing subsidence and damage to buildings or other services.

4.3.3.4 Pipe Jacking/Microtunnelling 4.3.3.4.1 Description of the Technique Pipe jacking is generally referred to as microtunnelling below 1.2 m diameter. The term microtunnelling is also used for fully automated pipe jacks in larger diameters.

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Fig. 4.29 General layout of pipe jacking with cutting head

Pipe jacking is a method of installing pipes by using a thrust system at the entry position, which is usually located in a shaft. A small tunnel boring machine or mechanized shield is used to excavate the route for the pipe, refer Fig. 4.29. Hydraulic cylinders/jacks normally power the thrust system. These hydraulic jacks are used to push specially designed casing pipes through the ground behind a mechanized shield and at the same time as excavation is taking place within the shield. This method provides a flexible, structural, watertight, finished casing pipe, as the tunnel is being excavated. Casing pipes may consist of the following material types; concrete, steel, mortarfilled glass fiber reinforced plastic, clay, or polymer concrete. The cables may be installed directly in the casing or installed in conduits which have been pulled into the casing. Pipe jacks can range between 150 mm and 3000 mm in diameter to accommodate transmission power cables. Mainly due to safety considerations, access by personnel may be limited in smaller microtunnels. Pipe jacking can be used in most ground conditions, including rock, water bearing, and mixed face conditions. Where the ground is unstable the appropriate selection of machine is used to control the face, or alternatively geotechnical processes can be used to stabilize the ground. When used in urban areas, pipe jacking is generally used at depths which will avoid conflicts with existing services. This installation method is usually selected when ploughing in is not a viable option and where HDD may pose a risk of conflict with existing services or where ground conditions are unsuitable for HDD. Microtunnelling/pipe jacking is generally used for the installation of cables and conduits where a strong structural lining is required e.g. in heavily trafficked urban areas or under strategic roads, motorways, railways, rivers and canals (Fig. 4.29). Six inter-dependent components are incorporated into a pipe jacking system. They are as follows:

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(a) Jacking System including thrust wall, jacking rig, guide rail, and thrust rings (b) Shield/cutter head (c) Spoil Removal System (d) Laser Guidance and Remote-Control System (e) Pipe Lubrication System (f) Pipe jacking pipes Additionally, electrical supply and distribution and general construction equipment may be required, as with most civil engineering applications. 4.3.3.4.1.1

Construction Process In order to install a casing pipe using this technique, it is first necessary to construct thrust and reception pits. The dimensions and construction of thrust pits vary according to the specific requirements of the drive, with economics being a factor. Pit sizes will vary according to the excavation methods employed, although these can be reduced, if required by special circumstances. A thrust wall is constructed to provide a reaction against which to jack. In poor ground, piling or other special arrangements may have to be employed to increase the reaction capability of the thrust wall. Where there is insufficient depth to construct a normal thrust wall, e.g. through embankments, the jacking reaction has to be resisted by means of a structural framework having adequate restraint provided by means of piles, ground anchors or other such methods for transferring horizontal loads. To ensure that the jacking forces are distributed around the circumference of a casing pipe being jacked, a thrust ring is used to transfer the loads. The jacks are interconnected hydraulically to ensure that the thrust from each is the same. The number of jacks used may vary because of the pipe size, the strength of the jacking pipes, the length to be installed and the anticipated frictional resistance. A reception pit of sufficient size for removal of the tunnelling machine is normally required at the remote end. The initial alignment of the pipe jack is obtained by accurately positioning guide rails and/or the jacking frame within the thrust pit. It is essential that the alignment is accurate, as otherwise it will be very difficult to achieve a successful installation. When the pipe jack or microtunnel is constructed below the water table it is usual to incorporate a headwall and seal assembly within each thrust and reception pit. The use of these items prevents ingress of ground water and associated ground loss, and retains annular lubricant. Consideration must be given to ground stability around the pipe jack entry and exit eyes in shafts. This can be achieved by a number of methods, for example, the use of gland assemblies, pressure grouting or localized dewatering. Entry and exit shafts can readily be converted into permanent access facilities. 4.3.3.4.1.2

Jacking Lengths The length over which a pipe jack can be installed is dependent upon many interrelated and variable factors; the stability and friction characteristics of the

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geology to be tunneled through, the self-weight and strength of the pipes, the diameter of pipe, the type of excavation method and the available jacking reaction. The major constraint will be the nature of the ground and the ground water characteristics. In small diameters (up to a meter) jacking lengths of up to several hundred meters, in a straight line or on a radius, are achievable. In larger diameters, lengths in excess of 1 km are possible, depending on ground conditions and excavation methods. 4.3.3.4.1.3

Intermediate Jacking Stations In order to reduce the total required jacking force on the full pipe length, intermediate jacking stations are frequently used between the launch pit jacking rig and the tunnelling machine. The interjack itself consists of a steel cylinder which matches the outside diameter of the jacking pipe and is fitted, either as a tolerance fit to the leading pipe on site or in some cases comes factory fitted from the pipe manufacturer. It must be designed to cater for ground, hydrostatic and thrust load conditions. A trailing interjack pipe recessed to slide into the interjack shield is positioned behind hydraulic jacks. These are used to move the forward train of pipes independently of the trailing pipes using the friction resistance of the trailing pipes to reduce the load on the thrust wall. On completion of the stroke of the interjacks the main jacks in the thrust pit advancing the rear pipeline to its original position relative to the leading pipeline and thereby closing the intermediate jacks. The sequence is then repeated for the duration of the pipe-jack and on completion the jacks and fittings are removed and the inter jack closed up. Inter jack stations are not only used to increase the jacking lengths achievable, but also to reduce the loads that are transmitted to the shaft structure. This is useful where ground conditions at the drive shaft are poor or of low inherent strength. 4.3.3.4.1.4

Lubrication The pipe jack shields are designed to produce a small overcut in comparison with the external diameter of the pipe. By injecting a lubricant into this annulus, the pipe can, in theory, be jacked freely through a fluid medium. In practice, however, fluid losses may occur into the surrounding ground. Providing these can be controlled, the technique results in considerable reductions in jacking forces and therefore longer jacking lengths. 4.3.3.4.1.5

Jacking Loads In addition to the effect of any lubricant used, the loads required to jack the pipe forward are mainly a function of frictional forces built up around the pipe. These forces depend on the type of ground – cohesive, non-cohesive, rock and, in particular, the potential for differential settlement around the pipe (arching characteristics), the shear stress of the ground (friction angle), the depth of overburden, the depth of the ground water, any surcharge load, the length and diameter of the pipe being jacked and the time taken for the operation. These variables should be assessed by an experienced geotechnical engineer.

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Whilst it is difficult to accurately assess these forces using soil mechanics theory, pipe jacking contractors have, after years of experience, derived empirical values. As a guide, frictional forces are generally between 0.5 and 2.5 Tonnes/m2 of external circumferential area. The use of sophisticated lubricant injection techniques can reduce frictional forces to as little as 0.1 Tonnes/m2. Frictional forces on the pipe may be reduced by applying a suitable lubricant with a nominal pressure above that of the ground water pressure present. If high frictional resistance is anticipated, it is recommended that intermediate jacking stations are placed at regular intervals in the pipe route. Jacking loads must be resisted by a jacking reaction built up within the thrust shaft. The construction of a thrust wall normally achieves this, as discussed above. 4.3.3.4.1.6

Jacking Tolerances In stable, self-supporting, homogenous ground, a route tolerance of 50 mm in line and level is attainable. However, in some ground conditions, particularly unstable ground or where obstructions are present, these tolerances may not be readily attainable. In such circumstances, where this tolerance or a better one must be achieved, larger pipe sizes can be considered. Adjustments to line and level should be gradual to ensure that the pipe manufacturer’s stated permitted angular deflection is not exceeded at any individual joint. Jacking tolerances should adhere to National standards, if applicable. 4.3.3.4.1.7

Spoil Removal For microtunnelling systems below 1.2 m diameter the spoil removal mechanism is inbuilt into the system, either a screw auger, which transports the spoil to the shaft or via a slurry that is piped to a surface separation plant. This also applies to slurry systems in the larger diameters. For all other systems spoil removal is generally by auger or belt conveyer to wheeled skips, or direct to skips that are transported to the shaft for removal.

4.3.3.4.2 Cable Rating and Bonding In addition to the items discussed in “Cable Rating and Bonding” section of ▶ Chap. 2 above, the following points should be kept in mind for pipe jacking / microtunnelling; In the case of pipe jacking / microtunnelling particular attention should be given to the presence or not of forced ventilation. Cable bonding systems may have to be adjusted where, in an overall cross bonding system, optimum placement of sheath interruption falls within the confines of a pipe jacking / microtunneling installation. In addition, due to the length of a pipe jacking / microtunneling installation, the standing sheath voltage may exceed the acceptable value. The relevant national practice for maximum standing sheath voltages should be applied or a particular derogation may be applied, if approved

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by the utility; this may result in a thicker serving than normal to withstand the induced voltages. 4.3.3.4.3 Mechanical and Cable Installation In addition to the items discussed in “Mechanical and Cable Installation” section of ▶ Chap. 2 above, the following points should be kept in mind for pipe jacking / microtunneling; These installations generally form only minor parts of individual cable sections between joints (as opposed to occupying an entire cable section on their own, as may be the case with a long HDD installation). Consequently, cable installation techniques relevant to pipe jacking / microtunneling installations generally form part of the overall technique applicable to the entire related cable section. Judicial use of caterpillars (push-pull machines) may be necessary at entry and exit pits to limit pulling tensions. The bending radii should also be monitored and not exceeded. In addition, for deep entry and exit shafts transitions may be necessary at the entry point into the casing/conduits from cables fixed to the side walls of the shafts. The overall duration of the construction of a pipe jacking / microtunnel is similar to that of a HDD in many ways. The most important parameters are: Geological conditions of the underground environment Size and depth of launch and exit shafts and size of the working area. Diameter and length of microtunnel Average progress rate by thrust is about 10 m/day; It can vary from 30 m/day in very soft soils (chalk) to 4 to 5 m/day for harder soils (clay, hard marl) Installing of cables inside tunnel including, if required, slurry to fill the interstices Laying and connecting of cables outside the microtunnel Reinstatement of the shafts and the working area 4.3.3.4.3.1

Use of Cementitious Grouts to Fill Space Between Cable and Pipe/ Conduit

This practice has been largely discarded in pipe jacking / microtunnelling installations on account that its use has been determined to have minimal advantage in increasing cable rating. One must also consider the difficulty in ensuring that the filling material penetrates along the entire conduit length and that no voids are left in the pipe/conduit. In addition, it is difficulty to remove/replace cable/s in filled conduits/pipes. 4.3.3.4.3.2

Shafts Effects Where entry and exit shafts (rather than shallow pits) are employed, the cable in the shafts is generally installed as a “Rigid System” in accordance with the provisions of CIGRE Technical Brochure 194 “Construction, laying and installation techniques for extruded and self-contained fluid filled cable systems”.

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Maintenance and Removal/Repair of Asset

4.3.3.4.4.1

Maintenance and Repairing Process Once the microtunnel and the cable installation is completed it is anticipated no maintenance will be required. 4.3.3.4.4.2

Repair of Cables Installed Without Conduits Where a number of cables are installed in the pipe jack / microtunnel casing, it may prove difficult to pull out one individual cable in the event of a fault. This could be due to cable jamming/twisting in the casing. In this event it may be necessary to pull out all cables. In addition, because the pits/shafts were filled in on completion of the original installation, these pits/shafts will have to be re-opened to permit access. 4.3.3.4.4.3

Repair of Cables Installed with Conduits See Sect. 4.3.2.1.2 above. 4.3.3.4.4.4

Cable Removal After Operation See 4.3.2.1.2 above.

4.3.3.4.5

Advantages and Limits of Pipe Jacking/Microtunnelling

4.3.3.4.5.1

Advantages 1. Microtunnelling is a versatile technique that can achieve a very high degree of alignment accuracy (usually with a deviation of less than 20 mm over 100 m). 2. Many microtunnelling methods have been designed that are able to deal with a variety of ground conditions. The boring heads can be designed to crush boulders with a diameter of up to 20 % of the machine diameter and for tunnelling through hard rock. 3. Microtunnelling is often a relatively quick process compared to open trench, thereby reducing associated labor costs and personnel risks. Unlike standard trenching methods, a large increase in depth typically only results in small increases in relative cost. 4. Microtunnelling requires less cover to sensitive structures than HDD due to its slurry pressure 5. control. 6. Microtunnelling shafts can be placed closer to the edge of the item to be passed under, thus reducing the length of the tunnel significantly compared to a HDD installation. HDD installations by their nature require entry and exit pits positioned in locations that allow gradual approach of the HDD under the “item to be passed”. 4.3.3.4.5.2

Limits of the Technique 1. Higher initial capital cost than HDD, as the equipment is more complicated 2. Microtunnelling can have difficulties in soils containing boulders with sizes greater than 30 % of machine diameter due to the inability to crush them. 3. Microtunnelling is unable to make rapid changes in alignment or level.

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Fig. 4.30 Humping/Fracking

4. Auger type microtunnelling machines are usually limited to tunnelling less than 3 m below ground water levels. 5. During thrust boring, if the cutting head becomes damaged, and if its diameter is larger than the casing pipe, it may be impossible to withdraw it, resulting in costly and time consuming rectification works. 6. The greater risk is frack-out of the lubricant injected along the jacked pipe. This tends to happen when extreme pressures are used particularly when frictional forces have increased to the point that the jacking might be stopped It is possible to heave/hump the surface with a TBM but this is an extremely rare event (Fig. 4.30). 7. Pipe jacking below the water table in unstable ground can and often does lead to catastrophic ground loss and damage to the structures above. In a sink hole area, it may be possible to use slurry microtunneling in lieu of pipe jacking with dewatering that may not be so effective in preventing further subsidence. 8. With microtunneling in extremely soft soils it is difficult to control alignment and grade without soil improvement. The TBM cannot develop enough side force using its articulation steering system to deflect the TBM in the correct direction. In larger TBMs (>1.5 m), their weight is so great that they tend to sink 50–100 mm in spite of best efforts to steer them. 9. Rock microtunneling is limited normally to the rock hardness being less than 200 MPa due to the small size of the cutting tools used on the cutter head. 10. Microtunnel boring machines must be 1.5 m or larger O.D. to have “face” access to the back of the cutter head in order to change the cutting tools. This is critical when microtunneling in granitic rock where disk cutters can fail or wear out in as little as 10 m of tunnelling. These type conditions require a face access TBM or run the risk of failure to complete the drive and require rescue shafts or tunnels or retraction of the TBM.

4.3.3.5 Mechanical Laying (Fig. 4.31) 4.3.3.5.1 Description of the Technique This technique, coming from the traditional trench technique is suitable for buried cables and consists of opening the excavation and simultaneously laying the three

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Fig. 4.31 Mechanical laying

phases, and possibly earthing cable and telecommunication cable as well as their backfilling. When combined with the use of weak-mix mortar it offers: • • • • •

Good cable protection from external damage Good control of the direct heat environment of the cable Good protection of the environment in case of short-circuit Reduction of the size of the trench compared with conventional technique Reduction of work duration

4.3.3.5.1.1

Laying Principle (HV Cable Systems) Cable laying conditions The cables are laid in a trefoil or flat position. The depth is 1.30 m to the bottom of the excavation, which on the one hand enables any effects of a zero phase-sequence short circuit to be controlled, and on the other hand, it protects cables from third party damage. The thickness of the mortar around the cables and in particular under the cables (raft) must be at least 50 mm. For trefoil laying, fastening must be used if the cable guides cannot maintain the trefoil position until the covering is in place. A telecommunication cable may be laid if necessary, in a separate duct above the power cables (on the weak mix mortar) and directly laid in the soil. A warning plastic netting is laid on top. Then the trench is backfilled and the soil is compacted. The width of the trench which takes into account the diameter of the cables is between 300 and 400 mm for trefoil cables and 450 and 500 mm for cables laid in a flat position (HV Cables).

Cable laying: The cables can be laid using two different methods:

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Cables Câbles

Mortor (*4) Toupie

hopper de mortier

Tremie

(*1) Dérouleuse porte - tourets Cable drum carrier

Protection

(*2) Trancheuse Tranchdigger

(*3) Caisson de pose Cubicle fray

(*5) Remblais Backfill

Fig. 4.32 Mechanical laying

• simultaneously : the cables are laid with the help of cable laying machines or a cable drum carrier (Fig. 4.32, •1) which is a few meters in front of the trench digger, • beforehand: the three phases are laid beside each other along the future route. The cables must not come into direct contact with the ground. They can be laid on rollers or on a polyane sheet. Joints: Depending on the voltage and the accessory technology, joints might not be laid by machine. Indeed, their preparation and completion time might not be compatible with the works progress. In this case, they are placed in special excavations (joint chambers) that are then filled once the joints have been made. Trench digger (Fig. 4.32, •2): The trench digger has to dig the trenches at the dimensions indicated previously and must be equipped with a cable guiding system to maintain the cables above the trench digger. Different kind of trenching machines can be found with sawing wheel or sawing chain. This cable guiding system is necessary to obtain the correct positioning of the cables at the entrance to the cubicle tray. If the cable guides are not able to maintain the cables in a trefoil position until the covering is in place, a fastening system becomes necessary. Cubicle Tray (Fig. 4.32, • 3): The cubicle tray which follow the digger must carry out the following tasks : Positioning the cables in the excavation Vibrating the weak mix mortar as necessary Covering the cables with weak mix mortar Compacting the covering The equipment must allow a permissible route curve radius of approximately 12 to 15 m and must be capable of being dismantled when necessary.

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Mortar hoppers (Fig. 4.32, • 4): Although they are not specific to this technique, the mortar hoppers carry out the following tasks : - Carrying to the works site the weak mortar mix necessary for the covering of the cables. One cubic meter of mix allows a trench length of about 10 m, - Pouring the mortar into the cubicle tray while operating the trench digger. Backfill (Fig. 4.32, •5): The backfill is identical to that used for conventional methods. In order to reduce the works time, its synchronization is made with the progress of trenching. Equipment: All the above equipment is part of a laying “train” about 50 m long, an example of which can be seen in Fig. 4.32. Examples of utilization of this method Since August 1993 many sites have used this technique in Europe. Thus, we can consider that this technique has moved from the experimental to the industrial stage in the HV cables range 4.3.3.5.2

Limits of the Technique

4.3.3.5.2.1

Civil Work This technique imposes the use of dedicated equipment which are expensive and heavy. The transportation of the equipment from one site to another one must be carefully considered (cost, duration). The ground occupied by the works site is larger than for a conventional site for several reasons:

The width must include excavated earth Digging equipment Pathway for the mortar hoppers Consequently, an access strip of about 7 m is necessary. Nevertheless, a local complement of backfilling is still possible. On the other hand, advantages of this technique compared to conventional open trench are: Important reduction of time (time duration divided by 2 or 3) Less cable handling and consequently reduction of the risk of damaging the cables For good achievement a few points have to be carefully taken in consideration: – Management of the supply of weak mortar mix which is conditioned by three parameters: – Distance,

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– Climatic – Progress – Management of the quality of the weak mortar mix. A few conditions are necessary to envisage the use of this technique: – – – –

Rural type lands or along roads provided only a few obstacles are present Route more than a few hundred meters long Slopes with less than 25 % Drying of the soil

As the heat is first dissipated through the weak-mortar mix, thermal resistivity of the soil as well as drying of the soil are not so critical. The use of specially formulated weak-mix mortar can be a solution for local problems. 4.3.3.5.2.2

Temperature of the Soil/Environment As for any laying operation, special care should be given to cable temperature during laying.( minimum as well as maximum temperature, sun beams protection )

4.3.3.5.2.3

Hardness of the Soil This technique is available for a rocky soil, but the time is increased consequently, tractors with caterpillar tracks should be used in marshy areas for better carrying performance.

4.3.3.5.2.4

Seismicity The use of weak-mortar mix seems to be a good improvement in case of seismicity.

4.3.3.5.2.5

Archaeology The technique is not suitable for archaeological sites.

4.3.3.5.2.6

Presence of Termites The technique is similar to other buried techniques.

4.3.3.5.2.7

Laying in National Park This technique could be interesting in some cases(re-use of native soil, duration of the work)

4.3.3.5.2.8

Duration of the Work A speed of 50 m/day (rocky soil) to 300 m/day can be expected.

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4.3.3.6 Embedding 4.3.3.6.1 Description of the Technique This technique consists of excavating a riverbed from a barge or with an amphibious machine, burying a tube or cables and filling up the trench. Burying of cables presents the effective, definitive protection against mechanical damage. 4.3.3.6.2

Limits of the Technique

4.3.3.6.2.1

Civil Work The methods that can be used to bury cables in riverbeds vary widely; the choice depends on such factors as river-bed conditions, operating depth, route obstructions, depth of burial desired or required, total length to be installed, cable size, and tools available. Trenching can be performed by:

(a) Dredging (b) Blasting (c) Jetting operated by divers Usually, the use of these methods is limited to rather shallow waters, practically up to depths of about 20 m, which is usually enough for river crossings. As the technical brochure 194 is limited to land cables, the equipment dedicated for submarine cables, such as submersible equipment which can operate down to a water depth of 1000 m and even more is not described in TB 194 but information can be found in ▶ Chaps. 3 and ▶ 5 of this book (▶ Fig. 5.11) and (Fig. 4.33). 4.3.3.6.2.2

Method of Operation Pre-trenching Post-embedding Simultaneous laying and embedding Plugging or cutting of cable trenches before laying the cables requires precision laying of the cable and is usually limited to a depth where divers can work for some time and where the river is comparatively calm. 4.3.3.6.2.3

Method of Excavation (a) Static plough (b) Static plough water jets (injectors) (c) Water jets (fluidizers) (d) Suction-pumps (e) Cutting-chain (f) Cutting-wheel

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Fig. 4.33 Embedding

(g) Mechanical disintegrators (h) Various combinations of the above Methods a), b), c), and d) may only be used where the riverbed is soft, i.e., sand, shingle or clay. 4.3.3.6.2.4

Propulsion (a) Towed from the surface (b) Self-propelled: 4.3.3.6.2.5

Operators (a) Operated from the surface assisted by divers not assisted by divers (b) Operated by divers at bottom pressure at atmospheric pressure

It is to be pointed out that if the riverbed changes its morphology along the route, different types of equipment might be needed. 4.3.3.6.2.6

Hardness of the Soil Depending of the type of soil vehicles can accommodate three distinct cabletrenching tools:

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A rock wheel cutter which require a cable route over the top of the vehicle will create a trench 1.2 meters deep in any riverbed up to quite strong rock. This is a robust device, but the work rate can be low with wear rate and consequently is time consuming. A chain cutter can provide trenches more than 2 meters deep in quite hard material, but is subject to significant wear, with low work-rates in difficult conditions. A powerful jet tool creating trench up to 2 meters. It can provide high work-rates in sandy riverbeds.

4.3.3.6.2.7

Maintenance and Repairing Process Due to the recent technological progress in the field of embedding machines and other ancillary equipment (remote operated vehicles (ROV), etc.), cable burial is presently possible, with various methods, up to a considerable depth and practically in every kind of riverbed. However in many cases the cost of the embedment is very high therefore the right way to proceed is to limit it to the sections where the risk of a cable damage is so high that it offsets the embedment cost. In case of limited risk, and where the power availability of the link is high, the possibility of a cable repair has to be considered as preferable, its cost will be paid only if, and when, the cable will be damaged. Of course, the cost of a repair, weighed with its probability, has to be compared with the cost of protection. The result of this approach could be different case by case: for example, in a short connection where extensive human activities (shipping, with anchoring) are present. A total embedding may be preferable, whilst in a long connection with limited local activity, an exposed cable (except limited portions with special protection) may be much more economic, even taking into account the cost of a possible repair (Fig. 4.34). Fig. 4.34 ROV machine

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4.3.3.6.2.8

Environment When crossing navigable waterways, this method implies that river traffic be stopped or deviated during the excavation and laying operations.

4.3.3.7 Use of Existing Structures 4.3.3.7.1 Description of the Technique Finding new layouts for high tension lines is more and more difficult, especially in urban or conservation areas. The use of existing structures is very attractive to solve integration problems in the landscape and may lead to drastic reductions in cost and start-up delays. The cohabitation of energy lines with railway and road constructions is considered in previous items (tunnels and bridges). This section is dedicated to existing pipes, including an application to pipe-type cables retrofitting. Pipe-type cables are the most commonly used in the United States to transmit power at high voltages. Three phase conductors are insulated with layers of fluidimpregnated paper and housed in a coated steel pipe. The free area in the pipe is pressurized with a dielectric fluid (oil or gas filled) to increase the dielectric strength of the system, to suppress ionization in the insulation, and to defer moisture ingress in the event of a leak in the pipe. This mode of installation offers several advantages: the pipe itself is very tough and can be installed with short and narrow roadway openings, minimizing traffic disturbances. When the pipe sections are welded together, the cables may be pulled at a later date, and the maintenance requirements are low compared with selfcontained fluid-filled cables. The first pipe-type cable system was installed as far back as 1932. Retrofitting of systems is planned, and steel pipes are very suitable for the replacement of old cables or to increase the cable size. Existing pipes can stay on site, only the cables have to be changed by pulling. By adopting another technology, utilities reduce their environmental exposure to fluid leaks. An idea is to replace the old fluid-impregnated paper tapes cables by cables with extruded dielectric insulation such as polyethylene. Due to electrical stress design considerations, the outer diameter of extruded cables may be larger than for the previous fluid-impregnated cables. Therefore, the substitution is not always feasible because of the minimum clearance between the top of the upper cable and the pipe. With extruded cables designed with a moisture barrier as a thin metallic sheath, no pressurized dielectric fluid is required. The technological change affects cable ratings because insulation and the free area in the pipe are modified. 4.3.3.7.2 4.3.3.7.2.1

Limits of the Technique

Civil Work The use of existing structures offers the advantage of reduced civil work operations, without trench opening or disturbance. Nevertheless, it may be important to empty

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the pressurized dielectric fluid in addition to removing the existing cables, if it is to be feared a risk of chemical incompatibility between the remaining fluid and the replacing cables. If a grout is injected after the pulling of the new cables, some vents have to be placed along the link. 4.3.3.7.2.2

Drying of the Soil The air gap issued from the lack of pressurized fluid is prejudicial to the efficient heat flow dissipation from conductors towards the surrounding soil. Special injection grouts, with low well-characterized thermal resistivity, can decrease the risk of overheating and thermal instability due to moisture migration. 4.3.3.7.2.3

Duration of the Work Since no civil work is involved, the use of existing structures is very favorable to shorten the site duration. Retrofitting operations can be anticipated and planned to optimize installation. 4.3.3.7.2.4

Cable Removal After Operation Any operation to have access to cables after laying is similar to ducts configuration.

4.3.3.7.3 Adaptation of the Technique to the Cable System Design The electrical stress design is the first element to design extruded cables to be pulled in place of existing insulated conductors in steel pipes. A second design point of view concerns ampacities and is of great interest. It rules the performance and the final acceptance of the proposed new solution. Fluid-filled cables have been designed for the voltage stress at lightning impulse. The main insulation is the fluid which fully impregnates the cable. Its breakdown strength in the butt gaps between the paper tapes determines the insulation thickness. The critical design parameter for extruded insulation cables is generally not the lightning impulse voltage but the maximum stress at the alternating current operating voltage to achieve an expected nominal lifetime of more than 30 years. Historically, the ageing parameters were not accurately established. Low insulation design stress levels resulted in high insulation thickness and large cable diameters. Today, the improvements of design, materials and manufacturing techniques led to cables with synthetic extruded insulation for higher voltages up to 500 kV. The insulation thickness has been reduced for high performance materials, and the maximum continuous operating temperature of 90
C of XLPE permits to be competitive with fluid filled paper cables, and with polypropylene paper laminate cables to a certain extent. Improved ampacities are not the only consequence of the external cable diameter reduction. Longer shipping lengths are achieved, and the overall system cost may be positively affected.

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Cable Clearance: A critical parameter for pipe-type cable design is the clearance between the cables and pipe to ensure that the cables can be pulled through the conduit. A minimum clearance of about 0.5 in. (12.7 mm) is recommended by most utilities for straight pulls. For three single-core touching cables in trefoil formation:

C¼

p 1 D  1 þ 3 De þ 2 d

Dd ðDd  2De Þ

where : De ¼ external diameter of cable (mm), Dd ¼ internal diameter of duct or pipe (mm), C ¼ clearance between the cables and the pipe (mm). The value of the external cable diameter De can be increased by a few per cent to allow for variations in cable and pipe dimensions or ovality at bends. Reciprocally, the maximum external cable diameter for a given clearance value is (Fig. 4.35):

De ¼

1 p 2 2þ 3

Dd 4 1 þ

p p p 3 C þ 3Dd  2 1 þ 3 C þ 3Dd

Jam ratio: When the ratio of the internal diameter of the duct or pipe to the cable external diameter is higher than 3.0, one of the cables in a group of three or four may slip between two other cables, causing the cables to jam in the conduit. The limit on

140 12"

120

De (mm)

Fig. 4.35 Maximum external cable diameter in terms of internal pipe diameter and clearance

10"

100 80

8"

60 40 20

6" 5" 4" 100 120 140 160 180 200 220 240 260 280 300 320 internal diameter of pipe Dd (mm) C=1/4 in.

C=1/2 in.

C=1 in.

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jam ratio should be modified to take into account variations in cable or conduit diameter and ovality in conduit diameter at bends.

4.4

Cable Installation Design and Laying Techniques

4.4.1

Cable Installation Design

4.4.1.1 Installation Design in Air Basically two types of cable installation must be considered. In the first type, the cable is rigidly supported and restrained from any movement due to thermal expansion or contraction. This is the type of support provided by closely spaced cleats in air. This type of installation is described in Sect. 4.4.1.1.1. The second type of support includes all systems in which the cable is free to move as a result of its thermal expansion or contraction. The cable may be supported in cleats with a spacing wide enough to allow it to deflect vertically or horizontally as it expands or contracts. The cleats are usually supported from below, but can also be suspended from above, (Fig. 4.14) depending on the local situations. This type of installation is described in Sect. 4.4.1.1.2 or 4.4.1.1.3. There is another situation where the cables are in air, being installed in pipes not filled with solid material. From the thermo-mechanical point of view the cable may be rigid or flexible, depending on the specific installation design, as described in Sect. 4.4.1.1.4. The different types of support give rise to very different mechanical stresses and strains within the components of the cable and the design procedures are therefore quite different. In general, it is preferable that any given cable system should be designed throughout its length on the basis of either rigid support or flexible support. If for any reason it becomes essential to mix the two types of support within a single cable route, special precautions must be taken at the interface between the different systems, as described in 4.4.1.3. 4.4.1.1.1 Rigid Systems When a length of cable is subjected to a temperature change, each component attempts to expand or contract by an amount corresponding to its temperature change and its coefficient of expansion. When the cable is installed in a rigidly restrained environment, no longitudinal expansion or contraction can occur and the cable therefore develops a thrust when heated and its components are subjected to a corresponding compressive strain. The conductor and sheath need be considered in practice when calculating this thrust, if the sheath is not present only the conductor must be considered. Experiments show that the value of the thrust developed on heating depends on the cable size and design, the temperature rise and the rate of temperature rise, the slower the rate the more the cable elements will relax and reduce the actual thrust.

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It is generally assumed that at the time of installation the cable is in a stress free condition so that if the cable is laid at a ground temperature (or ambient temperature for cables in air) below the maximum design ambient temperature on which rating calculations are based it will develop a thrust when the ambient temperature increases to the design value. This temperature increase is likely to be very slow however and hence allows a greater relaxation to occur. The rate of temperature increase from the design ambient temperature to the maximum operating temperature depends upon the cable environment and the rate of load increase. A buried cable cannot increase in temperature rapidly because of the thermal capacity of its surrounding. A cable in air can rise in temperature more rapidly but it is most unusual to require a newly installed cable to carry full load immediately, load growth is usually gradual and cyclic so that some opportunity for relaxation occurs. To allow for these effects it is necessary to include relaxation factors in the calculation of total cable thrust (Fig. 4.36).

4.4.1.1.1.1

Calculation of Cable Thrust The evaluation of the cable thrust is essential when dealing with rigidly installed cables, or at the interface points where flexible and rigid systems meet. Generally speaking the total thrust of a cable can be calculated as:

C ¼ C1þ C2þ C3þ C4 ðkg Þ where: C1 ¼ conductor thrust due to load C2 ¼ conductor thrust due to ambient change C3 ¼ sheath thrust due to load C4 ¼ sheath thrust due to ambient change Fig. 4.36 Typical rigid installation in air under a termination

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C1 is given by: C1 ¼ K 1 : αc : ΔT c1 : Ec : Ac

ðkg Þ

where α is the coefficient of thermal expansion of the conductor metal αc¼ 17.106 for copper (1/K ) αc¼ 24.106 for aluminum (1/K ) Δ Tc1 ¼ conductor temperature rise from the maximum ambient temperature to the maximum conductor temperature (K ) Ac ¼ conductor cross section (total cross section for three-core cables)(mm2) K1 is the relaxation coefficient, which is of the order of 0.75 for load temperature variations, depending on cable constructions Ec is the equivalent Young’s modulus for the conductor which depends upon its construction and materials and on the constraint provided by the insulation surrounding the conductor. Experimental measurements are necessary to obtain accurate results. C2 is given by: C2 ¼ K 2 : αc : ΔT c2 : Ec : Ac

ðkg Þ

where the symbols have the same values as above, but K2 (the relaxation factor) is of the order of 0.45 for ambient, temperature variations, depending on cable construction. ΔTc2 is the conductor temperature rise from the laying temperature to the maximum design ambient temperature (since the laying temperature is not usually known at the design stage the minimum ambient temperature may be assumed). (K ) For the metallic sheath the thrust is given by: C3 ¼ K 3 : αg : ΔT g1 : Eg : Ag

ðkg Þ

where αg is the coefficient of thermal expansion of the sheath metal αg ¼ 28.106 for lead sheaths (1/K ) αg ¼ 24.106 for aluminum sheaths (1/K ) ΔTg1 is the sheath temperature rise from the maximum ambient temperature to the maximum sheath operating temperature (K ) Ag ¼ sheath cross section (mm2) K3 is of the order of 0.30 for lead sheaths and of 0.65 for aluminum sheaths Eg is the equivalent Young’s modulus for the sheath in compression and must be found experimentally for reasons similar to those given for the value of Ec (kg/mm2)

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C4 ¼ K 4  αg  ΔT g2  Eg  Ag ðkg Þ where the symbols have the same value as above, but K4 may be taken as 0.1 for lead sheaths and 0.45 for aluminum sheaths, again depending on cable constructions ΔTg2 is the sheath temperature rise from the laying temperature to the maximum design ambient temperature (K )

4.4.1.1.1.2

Spacing and Cleating For rigidly restrained system the spacing and cleating evaluations must be done considering several parameters:

– At curves the restraining elements must be capable of withstanding the radial force given by F ¼ C=R

ðkg=mÞ

where C is the cable thrust and R the curve radius – The radial pressure at bends due to maximum conductor thrust must be compatible with the insulation material – Cleat spacing must be calculated considering that the cable thrust must be less than the critical load for instability (Ccr) For cables with thick aluminum sheath the critical load may be calculated as follows: Ccr ¼

π2  E  J l2

while for cables with lead or thin aluminum sheath: Ccr ¼

2  π2  E  J l2

This difference of behavior, which is shown in experimental tests, may be explained by the fact that the more rigid aluminum sheathed cables behaves as though the cleat acts as a hinge, while for the less rigid cables the restraint normally appears as midway between a hinge and a rigidly fixed beam. – Sheath strain must be checked if daily temperature changes are significant (> 35
) – At bends the cleat spacing is reduced by half compared with the straight sections. – Short circuit forces in rigidly restrained cables

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Short circuit forces may be significant in the case of rigidly restrained cables cleated in air. In this case the cable between cleats will already be in compression due to its temperature rise under normal load and the electrodynamic effect of the short circuit will result in the addition of a uniformly distributed side loading to the original compression load which, assuming a phase/phase short circuit, is given by: F¼

μ0  I 2 ðkg=mÞ 2  π  S  9:81

where: μo ¼ magnetic permeability of air, 1256.10-6 I ¼ short circuit current, rms (A) S ¼ cable spacing (m)

(H/m)

These forces result in a bending moment in the sheath which is a maximum adjacent to the cleat and has a value: M¼

F  l2 ðkg:mÞ 12

where: l ¼ cleat spacing (m) This equation is valid for the normal case where the thrust C existing in the cable prior to the short circuit is less than 10% of Ccr the critical thrust causing deflection, where: C er ¼

4  π 2 ðEJ Þ ðkg Þ l2

(EJ)* is the flexural rigidity of the cable based on the short term properties of the sheath. If the thrust existing in the cable before the short circuit exceeds 0.1. for a lead sheath cable or if the sheath is of aluminum, a more elaborate calculation must be used. Having calculated the bending moment M, the sheath strain ε is given by: e¼

M  Ds  103 2  ðEJ Þ

where: Ds ¼ outside diameter of cable sheath (mm) To avoid noticeable permanent deformation of the cable the maximum sheath strain ε should be limited to an acceptably low level.

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4.4.1.1.2 Flexible Systems (Western Approach) Flexible types of cable support are those systems which allow the cable to expand in length and to deflect laterally to accommodate this expansion when the cable is heated and to return to the original formation on cooling. In order to control the movement of the cable within pre-determined limits it is usually installed initially in an approximately sinusoidal formation with cleats at appropriate intervals so that expansion takes place by an increase in the amplitude of the sine wave. Because the flexible system allows cable expansion to take place it is not characterized by the high values of thrust which occur in the rigidly restrained system.

4.4.1.1.2.1

Cables Cleated with Movement in a Vertical Plane The cable is held in widely spaced cleats with an initial sag between cleats which increases with temperature rise. Figure 4.37 illustrates a system of this type and Fig. 4.38 is an example of typical installation. The spacing of the cleats is not critical and within the limits given below can be chosen to suit the fixings available.

Fig. 4.37 Cable cleated with movement in a vertical plan

Fig. 4.38 Typical flexible installation with movement in a vertical plan

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The weight of the cable is supported by the cleat and if the cleat spacing is too large the side pressure on the cable at the cleat will become excessive and there will be a tendency to concentrate bending at the edge of the cleat. On the assumption that the cleat length is approximately equal to the cable diameter and has suitably rounded edges the following practical rule is suggested l

De2 ðmÞ 65  W

where: l ¼ cleat spacing (m) W ¼ cable weight (kg/m) De ¼ cable outside diameter

(mm)

Similarly, to avoid concentrated bending at the edge of the cleat the cable deflection δ due to its own weight should be at least five time less than the initial sag between cleats fo required to ensure satisfactory expansion and contraction movement. It is therefore necessary to make an initial estimate of cleat spacing. The following criteria for δ and fo may be followed δ¼

f W  l4  o ðmÞ 5 384  ðEJ Þ

where: δ ¼ cable deflection due to its own weight (m) (EJ) ¼ flexural rigidity of the cable (kg.m2) fo ¼ initial sag (m) W ¼ cable weight (kg/m) l ¼ cleat spacing (m) Having determined the cleat spacing it is necessary to fix the value of fo, the initial sag between cleats. This sag should not normally be less than 2 De but it may be necessary to increase it beyond this value in order to ensure that the change of strain in the sheath due to thermal movements does not exceed the maximum imposed by the fatigue properties of the sheath. To simplify the calculation of the sheath strain it is assumed that the longitudinal expansion of the complete cable follows the expansion of the conductor. The total sheath strain is then the sum of the absolute values of the strain due to the movement of the cable together with the strain due to the differential expansion of the conductor and the sheath. On this basis it can be shown that the maximum sheath strain change Δεmax will not be exceeded provided:

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f0

279

2  αc  ΔT c  Ds  103 ðmÞ jΔemax j  αc  ΔT c  αg  ΔT g

where: αc¼ coefficient of thermal expansion of the conductor (l/K) ΔTc¼ daily temperature rise of the conductor (K) αg¼ coefficient of the thermal expansion of the sheath (l/K) ΔTg¼ daily temperature rise of the sheath (K) Ds¼ outside diameter of the metal sheath (or average outside diameter for a corrugated sheath) (mm) Δεmax¼ maximum allowable sheath strain change due to daily load cycles. For a typical system designed for a life of 30, 40 years the standard values of 0.1% for lead and 0.25% for aluminum sheathed cables are normally adopted. Taking into account the excellent experience during many years, however, slightly less conservative values such as 0.12% for lead and 0.35% for aluminum can also be considered, particularly for extruded cables. The system described above is suitable for straight or gently curved cable routes. If it becomes necessary to install the cable around a small radius bend in the route it should be supported on a horizontal plane within the bend and with suitable means of minimizing friction as the cable moves due to thermal changes. 4.4.1.1.2.2

Flexible System with Cable Movement in a Horizontal Plan In this type of installation the cables are arranged in a sinusoidal formation in a horizontal plane with cleats fixed at the points of flexure of these sinusoids, as shown in Figs. 4.39 and 4.40. Swiveling cleats may be used, capable of rotating on a vertical axis as the cable moves, but it is preferred to use fixed cleats with a length approximately equal to the cable diameter and with a rubber lining of 3 to 5 mm thickness. These cleats must be installed at an appropriate angle. The movement of the cable due to thermal cycles will be largely influenced by the friction between the outside surface of the cable and the support between cleats. It is essential that the cable should be supported so that it moves only in the horizontal plane using a low friction support and allowing adequate air movement around the cable to avoid de-rating.

Fig. 4.39 Plan view of cables installed with movement in a horizontal plan

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Fig. 4.40 Typical flexible installation with movement in a horizontal plan

As a practical rule the cleat spacing should be: l¼

De ðm Þ 20

where: De ¼ outside diameter of the cable (mm) The initial deflection of the cable fo should be fixed following the same rules as given in paragraph for cable moving in a vertical plane. • Calculation of cable thrust As already mentioned the cable thermal expansion in a flexible configuration give rise to small axial thrust, while the initial sag is increased. Simple formulae can be used to calculate these parameters, assuming that the initial configuration is a sinusoid. The sag is given by the formula: f ¼

f 20 þ

4  αc  ΔT c  l2 π2

Where the symbols are the same used as before. The axial thrust is given by the formula: C¼

4  π2  E  J f  f 0  f l2

It may be easily verified that the axial thrust in a flexible system is much lower than in a rigid system and may be practically neglected in most applications.

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4.4.1.1.2.3

Short Circuit Forces in Flexible Type Cable Installation Short circuit forces are of much greater significance in cable installations of the flexible type because of the wider cleat spacing used compared with rigidly restrained cables. It is normally necessary to provide straps around the three cables at intervals between the cleats to hold the cables together during a short circuit. It therefore becomes necessary to consider the spacing of these straps and the strength of the strap necessary to withstand the forces involved. As in the case of rigidly restrained cables, the length of cable between restraints will be subjected to a uniformly distributed side loading and assuming a phase/phase short circuit this is given by:

F¼

μo  l2 2  π  S  9:81

ðkg=mÞ

where: μo ¼ magnetic permeability of air ¼ 1256.106 (H/m) I ¼ short circuit current (rms) (A) S ¼ cable spacing (m) This force results in a bending moment in the sheath adjacent to the restraint of: M¼

F  l1 2 ðkg:mÞ 12

where: l1 ¼ distance between restraints (m) Since it is usually necessary to fit at least one restraining clamp around the cables between the cleats, l1 corresponds to the distance between these clamps or between a cleat and a clamp. Hence, as before, the maximum sheath strain is given by: e¼

M  Ds  103 2  ðEJ Þ

where the symbols have the same meaning as before and to avoid noticeable permanent deformation of the cable the value of the sheath strain ε must be limited to an acceptably low level. The strength of the strap can be calculated from the equation for F above but since this ignores the instantaneous value of current, which may substantially exceed the

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rms value and also ignores resonance effects which may occur, a factor of safety of two should be allowed so that the minimum strength of the strap is given by: 2:F:l1

ðkg Þ

Using these equations the number of strap within a span of cable between cleats may be calculated. The same equations are valid for both types of flexible installation with movement in the vertical or horizontal planes. 4.4.1.1.3 Flexible Systems (Japanese Approach) Generally, there are uniform basics for the snaking design, as described below.

4.4.1.1.3.1

Horizontal Snaking Installation (Fig. 4.41) 1. Initial snaking width: 1 De or more 2. Pitch (2 L): 6-9 m 3. Occupied width (W): W ¼ D + B + n + σ

Where D ¼ Cable occupied width (2De[De ¼ outside diameter of the cable]when trefoil installation) B ¼ Initial snake width n ¼ Lateral snake displacement σ ¼ Tolerance

Fa B

Fa

θ0

g

R L

L 2 μ WR θ 0

Fa

Fa

n 2

n 2

Fig. 4.41 Horizontal snaking

2 μ WR θ 0

2 μ WR θ 0 Horizontal snaking

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Table 4.1 Horizontal snaking calculations Metal sheath With metal sheath Without metal sheath

Low temperature

High temperature

μ:w:L² 2B

μ:w:L 8:E:I α:t  8:E:I : α:t 2  ðBþnÞ² : 2  2ðBþnÞ 0:8 B² ²

0:8

μ:w:L : α:t  8:E:I 2 þ 2:B 0:8 B² ²

8:E:I α:t  ðBþn :  2μ:w:L ðBþnÞ 0:8 Þ² 2 ²

Formulas for Calculating Axial Snaking Tensions Generated (Horizontal Snake) Note: +: tension & : compression EI¼ Cable bending rigidity W ¼ Unit cable weight μ ¼ Coefficient of friction between cable and installation surface

4. Lateral displacement (n): n ¼

B² þ 2 L:m x 0:8  B

Where: m ¼ Cable expansion ¼ α.t.L α ¼ Coefficient of linear cable expansion t ¼ Temperature rise 5. Formulas for axial tensions generated (Fa): Depending on types with or without metal sheaths, the formulas in Table 4.1 are used. 6. End section of snaking installation The necessary number (N ) of fastening cleats is generally determined as follows: N ¼ Fa/F + 1 (or Fa/F Sf) Where: F ¼ Restraining force of terminal fastening cleats Sf ¼ Safety factor 7. Middle section of snaking installation The snake formation is fastened at inflection points with intermediate cleats at every or several pitches. 4.4.1.1.3.2

Vertical Snaking Installation (Fig. 4.42) Initial snake width (B): 1 De or more Pitch (2 L) : snake pitch Bending distortion : 1.5% or less Radial surface pressure: 3.33 kg/cm2 or less Lateral displacement (n): n ¼ B² þ 2 L:m x 0:8 – B Formulas for axial tensions generated (Fa):

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Fig. 4.42 Vertical snaking

Fa B

Fa

g

θ0

R L

L

Fa

η

Fa

4WR θ 0

4WR θ 0

Vertical snaking

Table 4.2 Vertical snaking calculations Metal sheath With metal sheath Without metal sheath

Low temperature

High temperature

w:L² 2:B

8:E:I  8:E:I : α:t 2  ðBþnÞ² B²

0:8

w:L  8:E:I : α:t 2 þ 2:B 0:8 B² ²

α:t 2

 2ðw:L BþnÞ 0:8 ²

8:E:I α:t  ðBþn :  2ðw:L BþnÞ 0:8 Þ² 2 ²

Formulas for Calculating Axial Snake Tensions Generated (Vertical Snake)

From the same viewpoint as for horizontal snaking installations, the formulas in Table 4.2 are used with or without metal sheaths. End section of snaking installation The necessary number (N ) of terminal fastening cleats is generally determined as follows: N ¼ Fa/F þ 1 (or Fa/F Sf) Where: F ¼ Restraining force of terminal fastening cleats Sf ¼ Safety factor Middle section of snaking installation The cable is supported by direct cable rests at crests of the vertical snaking. In some installations, restraining cleats are used at every several pitches.

4.4.1.1.3.3

Vertical Installation Design XLPE cables are easy to install upward on a tower. Vertical installations used on towers, in vertical tunnels, etc. can generally be classified as follows (Table 4.3):

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Table 4.3 Vertical cable installation at shafts Item Triplex cable Single-core cable Shaft height 6–10 m or less Shaft height 6–10 m or more Shafts where cleats cannot be used

Method - Straight installation - Fastened with cleats at several m intervals - Straight installation - Fastened with cleats at several m intervals - Snaking installation (6–8 m pitch) - Fastened with cleats at snake inflection points - (For some sizes, movable cleat supports are also used at snake crests.) - One-point fastening using tension member cable - - Steadying cleats are used (in special installations case).

4.4.1.1.4 Cable in Ducts The ducts may be filled with solid material such as Bentonite or not filled. The first solution is often preferred for relatively short ducts (normally less than 100 m) used to cross roads, railways or other obstacles, inserted in sections where the cable is directly buried. Any movement of thermal origin is completely prevented and the cable behaves as if it were directly buried. In other situations according to different practices or due to other constraints, the ducts are not filled and three different design concepts may be adopted. a) Large diameter duct, cable blocked at the extremities. If the inner diameter of the duct is significantly larger than that of the cable (typically 1.5 to 2 times), the thermal elongation results in cable snaking. The geometrical configuration is similar to a sinusoid or a helix with a certain pitch and amplitude, depending on duct and cable diameters, weight, axial rigidity, flexural rigidity of the cable, friction coefficient between cable and duct, temperature variation. Thanks to the snaking effect, the axial thrust is drastically reduced with respect to the thrust developed by a rigidly restrained cable. As a consequence of the thermal cycling, the amplitude of the deformation varies cyclically and the resistance of the cable to fatigue phenomena must be considered. b) Small diameter duct, cable blocked at the extremities. If the diameter of the duct is only slightly larger than the cable (minimum clearance to allow the cable pulling), the very limited snaking is not sufficient to reduce the axial thrust and the thermal movements are negligible. In practice this case may be considered a rigid installation. c) Small diameter duct, cable free to move at the extremities. In this type of installation there is a certain movement of the cable from the duct towards the manholes as a consequence of the thermal expansion. In the manholes

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the cable is installed in a snaking configuration properly designed in order to maintain the cyclic bending of the cable within acceptable limits. This situation is dealt with as a transition in Sect. 4.4.1.3.

4.4.1.2 Installation Design for Buried Cables 4.4.1.2.1 Backfill To improve heat dissipation, only sand or special backfill shall be used around cables or ducts. 4.4.1.2.1.1

Sand There are specifications available how to select sand for cable trenches. During performance of the work the constructor shall take random samples for clay tests and sieve tests. The thermal resistivity characteristics of the sand shall also be verified by testing. During installation of the cable the excavated trench shall be kept in dry condition by dewatering until cable laying and backfilling are completed. Backfill material shall be placed in uniform layers and compacted. Moisture content of backfill material shall be adjusted as required to obtain the specified density. To protect the cable shall be covered by concrete tiles or plastic sheets. On top of the tiles native backfill may be used. 4.4.1.2.1.2

Special Backfill The thermal resistivity of a carefully selected Cement Bound Sand (CBS) for electrical cables has several advantages as a good thermal backfill material. It will eliminate the risk of voids due to water erosion or movement caused by thermal expansion. CBS will also keep the thermal resistance of the backfill surrounding the cable at a very stable level. The thermal resistivity of a good backfill for electrical cables when hardened is 0.35 K.m/W or less in moist condition and 1 K.m/W in its totally dried out condition. Testing of the thermal resistivity and compressive strength has to be performed to be sure it reaches the specified values. The thermal backfill shall be composed of fine and coarse aggregates, cement and fluidizing agent. The fluidizing agent consists normally of fly ash and water. The thermal backfill should be installed by pouring it into the trench or by use of grout pumps. Natural backfill should not be placed in the trench until one day after pouring and inspection.

4.4.1.2.2 Cooling Systems To increase the capacity of a cable circuit forced cooling can be used for the direct buried cables and cables in duct banks. There are two main systems that have been used. External cooling, where cooling water runs in four pipes separated from the three single core cables and laid parallel to them. The other system is surface cooling where water is in direct contact with the outside surface of the cable. Each cable and its cooling water being contained in a pipe. Cooling stations are normally placed at the ends of the cable route. The cooling station consists of water pumps, water

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storage and expansion tank, and a heat exchanger for cooling the water circulated round the cable route. The cooling stations can be operational from either local or remote positions. To increase the load capacity of cables installed in tunnels and shafts, forced ventilation can be used. Temperature sensors are monitoring the surface temperature of the cables in various places along the route. The ventilation fans start at preset levels to cool the cables during the high load periods. A range of articles describing design and calculation of forced cooling of cable installations are available in Electra and IEEE.

4.4.1.3 Transition Between Different Installation Types Along the route of an underground link, different installation techniques may be used. If all the techniques are all rigid or all flexible, the behavior of the link seems to be homogeneous, but even in this case, problems may appear around the jointing areas. If they are different, i.e. unfilled duct and direct burial or filled trough and manhole, damages can happen on the link if transitions between flexible and rigid installations and of course around the jointing are not treated or badly treated.

4.4.1.3.1 Transition Between Ducts and Manholes (Open Air) Cable thermal expansion of the span appears in the manhole by duct method. Therefore the “Offset” part is made, and it must absorb thermal expansion so that the thermal expansion does not have a bad influence on the cable and joint part. Offset design of the XLPE cable in the manhole uses a geometrical analytic technique so that the cable bend radius do not to become less than allowable radius when the cable come out from duct face. And, the consideration is necessary about the amount of occurrence sheath distortion in the case of the cable that has a metal sheath. So, allowable amplitude distortion has only to find amplitude condition by the day data, from the S-N curve (amplitude Strain – Number of times to the destruction), because the thermal expansion number of times of the year is smaller than the thermal expansion number of times of the day. 1) Design of straight offset The experiment was done about movement of jointbox offset form that absorbed thermal expansion of one core XLPE cable, based on the technique of SCFF cable experiment in the beginning. The cable spiral deformation occurred, and the inclination of the jointbox and direction movement in the core occurred as a result of this examination. Therefore, it confirmed that the rigid of the jointbox was necessary, because the deformation is concentrated on one bend part and an allowable radius cannot secure it. Such an experiment is continued, and an examination is done on the jointbox fixed condition, and the design technique of the following 3 forms is applicable at present :

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a) Equal arcs range offset type b) Long offset type c) Three equal arcs with pendency type Each calculation technique is shown in Table 4.4. a) Calculation technique of “Equal arcs range offset type” This form is the way of designing that supposed to absorb thermal expansion by two circular arcs without change the turning point. The attention is needed with this form that the cable contact to the other cables and the other jointbox because of spiral deformation offset by thermal expansion. b) Calculation technique of “Long offset type” This form has straight line part in the offset section. It is the way of designing that supposed to absorb thermal expansion by forms three circular arcs by straight line part’s being curved. c) Calculation technique of “Three equal arcs with pendency type” Large conductor size cable hangs down greatly between support points at the time of the thermal expansion, the part where a cable in the neighborhood of the bottom hung down point cannot satisfy the allowable radius. So, this form takes that problem into consideration. This form does not contain a straight line in the offset section in the same way as “Equal arcs range offset type”. It is the way of designing that supposes to absorb thermal expansion by three circular arcs three-dimensionally. d) Method of supporting cable in the manhole The cable guide is set up at duct face and joint side to avoid bad influence for cable against thermal expansion in the all forms. Support method for the cable that can be put between the cable guide varies in the kind of the each form. In the case of “Equal arcs range offset type”, It is supported with the cable guide in the duct face and the jointbox side, and the cable between that is not supported. In the case of “Long offset type”, It is supported the middle point for the prevention of hang down the cable, because the offset length sometimes becomes long by the existence of the straight line part at the time of thermal expansion. And, In the case of “Three equal arcs with pendency type,” It is supported with the suitable support hardware to keep the cable allowable radius in the pendent part at the time of the thermal expansion.

sin

θ

θ 2

Where, R: Bend radius at the thermal expansion length of the annual maximum (mm) L: Offset length (mm) F: Offset width (mm) θ : Centre angle at the time of thermal expansion (rad)

F2 þL2=2

F2 þ L 2 F tan 1 F L ¼ p

Bend radius R is approximated by three arcs. 1 F2 þ L2 2LF þ‘ sin 1 2 R¼ 2F 2θ F þ L2 θ sin ðL þ ‘  mÞ2 þ F2 2 ¼ θ F2 þ L2 2LF þ ‘ sin 1 2 2F F þ L2 Where, R: Bend radius at the thermal expansion length of the annual maximum (mm) L: Offset length of arc part (mm) □ : Offset length of straight part F: Offset width (mm) θ : Centre angle at the time of thermal expansion (rad)

Bend radius R at the time of thermal expansion 1 F2 þ L 2 F R¼ tan 1 mþ F 2θ L

mþ

Long offset type

Equal arcs range offset type

Table 4.4 Offset calculations

Where, R1:Radius decided more than the interior radius rate of both ends support hardware R2:Bend radius at the thermal expansion length of the annual maximum d: The amount of pendent a1,a2:The position to the bottom point As for the details, it is omitted.

Three equal arcs with pendency type

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Fig. 4.43 Shape of bend part

R = R0 −

m 2 tan(θ / 2) − θ

Straight part

On the other hand, the Triplex XLPE cable of the horizontal part, is supported with the pillows manufactured by the porcelain material, and so on in the interval of about 1–1.5 m. 2) Offset design of the bend part This form is the way of designing that supposes to so that the degree of radius might become a constant, as shown in the bottom figure. The bend radius changes in “R” from “R0” by thermal expansion quantity “m”, then the straight line part which is equal on both sides of the bend part is established (Fig. 4.43).

4.4.1.3.2 Transition Between Flexible and Rigid Systems (Open Air) As already stated it is desirable that any given cable installation should be designed as a wholly rigid or wholly flexible system. It may sometimes be necessary, however, to mix the two above designs within a single cable route and special consideration must be given to the interface between the two systems. Rigidly restrained cable systems are characterized by the presence of a substantial mechanical thrust in the conductor when the cable is heated, whilst flexible systems have a low value of conductor thrust. At the interface between these systems the conductor will tend to move from the rigidly restrained section into the flexible section. The amount of the movement depends on the cable characteristics and particularly on internal friction between the conductor and the other cable components. The movement may extend over a few meters on both sides of the transition section and may cause damage or disturbance to the insulation and unacceptable sheath strains, if appropriate precautions are not taken. In order to reduce the movement and its effect on cable integrity, it is good practice to install the cable in a series of rigidly fixed curves at the extremity of the buried section, in order to provide a high frictional resistance to the movement of the conductor within the cable. If a joint is installed at the transition section, the behavior of the joint itself must be carefully considered in relation with the above-mentioned phenomena of movement and axial thrust of the conductor.

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In the most common joint design, there is no mechanical restriction to the conductor movements, whereas in other designs a mechanical block of the conductor is provided. It should be verified that the movements or the mechanical thrust do not exceed acceptable limits. 4.4.1.3.3 Transition Between Flexible and Rigid Systems (Buried) This case can be found where cables are partly laid in ducts and partly directly buried or laid in filled troughs. As already stated before, at the interface between rigid and flexible systems, the conductor will tend to move from the rigidly restrained section into the flexible section. Ducts of appropriate size are then required in order to allow a kind of snaking inside the conduit. One must be aware that the movement of the whole cable inside the duct may extend on both sides of the duct section. If a joint is installed at the transition section, the behavior of the joint must be carefully considered in relation with the abovementioned phenomena of possible movement and axial thrust of the cable. Even when the joint is buried, additional fixing of the joint is required, for example by the use of weak mix or by appropriate cleating.

4.4.2

Cable Laying and Installation Techniques

4.4.2.1 Cable Pulling Calculations The basic calculations relevant to cable pulling are reported hereunder. 4.4.2.1.1 Clearance in Ducts Cables pulling in ducts or pipes requires that the duct or the pipe have an internal diameter in excess of the cable diameter to allow for a safe operation. The free space between the cable and the duct inner size is called clearance. The clearance to be considered is not the result of the implementation of precise formulae, but the result of the practical experiences. For single core cable the inner size of the ducts should be normally at least 1.5 times the cable size, particularly with long ducts with some bends along the route. For three cables pulling in the same duct, the duct size should not have a ratio with the cable size of less than 2.8 to 3, because jamming may take place at bends. According to a different industrial practice a standard clearance of 30 mm is adopted. Even smaller clearance may be adopted for straight pulls. 4.4.2.1.2 Pulling Tension The main parameter to be evaluated when assessing the cable laying aspects is the cable pulling tension.

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The knowledge of the pulling tension is not only essential to plan the actual lay, but also to assess the suitability of cable design/route design/laying methodologies. The following equations are applicable to single cables, nose pulled into trenches or into long ducts or pipes. The route should be first divided into specific sections of straight, curved, uphill slope and downhill slope. The pulling tension required for each section is then calculated, starting at the drum and taking the exit tension for each section as the entry tension for the next. The formulae are as follows: Straight Pull T2 ¼ T1 þ W  K  L

ðkg Þ

where: T2 ¼ exit tension (kg) T1 ¼ entry tension (kg) W ¼ cable weight (kg/m) L ¼ length of section (m) K ¼ coefficient of friction for that section

(m)

Horizontal Bend (Fig. 4.44) T 2 ¼ T 1 cosh Kθ þ sinh Kθ

T 1 2 þ ð W  RÞ 2

ðkg Þ

where: θ ¼ angle subtended by the bend R ¼ bend radius (m)

(radians)

T2

Fig. 4.44 Horizontal bend

R T1 ϑ

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Vertical Bend Pulling up the bend (Fig. 4.45) T 2 ¼ T 1  eK:θ 

T 3 ¼ T 2  eK:θ þ

WR 2  K  sin θ  1  K 2 eK:θ  cos θ 1 þ K2

ðkg Þ

WR 2  K  eKθ þ 1  K 2 1  eK:ϑ  cos θ 1 þ K2

ðkg Þ

Pulling down the bend (Fig. 4.46) T 2 ¼ T 1 eKθ þ

T 3 ¼ T 2 eK:θ 

WR 2  K  sin θ  1  K 2 eK:θ  cos θ 1 þ K2

ðkg Þ

WR 2  K  eKθ  sin θ þ 1  K 2 1  eKθ  cos θ 1 þ K2

ðkg Þ

T3

Fig. 4.45 Vertical bend (pulling up)

ϑ

R T2

R

ϑ

T1

Fig. 4.46 Vertical bend (pulling down)

T1

ϑ

R ϑ

T2

R

T3

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Upward Slope (Fig. 4.47) T 2 ¼ T 1 þ W  Lð sin θ þ K  cos θÞ

ðkg Þ

Downward Slope (Fig. 4.48) T 2 ¼ T 1  W  Lð sin θ  K  cos θÞ

ðkg Þ

In the formulae given above the value of K, the coefficient of friction, for the part of the route in question will depend on the material of the cable outer sheath and the surface with which it is in contact. It is essential to have good reference values for the friction coefficient to have reliable values, while simplified formulae can be used to calculate the pulling tension. Having established the pulling tension required it must be checked that this tension is within the acceptable limits for the cable. To avoid relative movement between conductor and sheath with possible disturbance of the insulation it is essential to fit a cable pulling grip which is anchored to the conductor or conductors and to the sheath at the leading end of the cable. A pulling grip is also fitted at the trailing end of aluminum sheath cables. However it is assumed that the tension is withstood by the conductor. Fig. 4.47 Upward slope T2

L

ϑ T1

Fig. 4.48 Downward slope

T1 ϑ

L

T2

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As reference the following values could be considered: single core cables single core cables 3 core cables 3 core cables

– – – –

copper conductors aluminum conductors copper conductors aluminum conductors

6 kg/mm2 3 kg/mm2 5 kg/mm2 3 kg/mm2

but alternative values could be considered. For example, France considers – for aluminum single core cables, 5 kg/ mm2, – for all single core cables, a limitation on the pulling tension of 4000 kg. In any case, the maximum permitted levels of conductor tension have to be checked with the cable supplier. 4.4.2.1.3 Side Wall Pressure Having established the pulling tension required it must be checked that this tension is within the acceptable limit for the cable and that the side pressure on the cable at bends is also acceptable. At bends in the route the compression force between the roller and the cable is given by: F¼

Td R

ðkg Þ

where: F ¼ compression force on roller (kg) T ¼ tension in cable (kg) R ¼ bend radius (m) d ¼ distance between rollers (m) If iron skid plates are used at the bend, the compression force between cable and skid plate is given by T F¼ ðkg=mÞ R The maximum permissible values of F are different and dependent on the type of sheath and insulation. These values have to be checked with the cable manufacturers.

4.4.2.2 Installation Methods 4.4.2.2.1 Introduction The following five techniques are now used: Nose pulling by winch, synchronized power drive rollers, caterpillars, mechanical laying and bond pulling and the most

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Fig. 4.49 Cable pulling in duct

common is nose pulling followed by power rollers, caterpillars, bond pulling and finally mechanical laying (Fig. 4.49). A brief description of each of the five techniques is given below: 4.4.2.2.2 Nose Pulling With this technique the cable is installed by using winch with a pulling hawser directly connected to the cable end, or “nose”. In this case the tension required to install the cable is taken by the cable itself and hence it is important that the pulling tensions are calculated beforehand to ensure the design limits are not exceeded. 4.4.2.2.3 Synchronized Power Drive Rollers This technique relies on the use of multiple powered rollers positioned at regular intervals along the cable route to install the cable. The frequency of the rollers is dependent upon the cable construction and the route itself. Since each roller has to provide an equal force they require to be synchronized to operate effectively and to avoid any damage to the cable due to compressive forces. Normally a winch and hawser are used to supplement the rollers by nose pulling but the tension on the cable end is very low due to the effects of the powered rollers. 4.4.2.2.4 Caterpillar or Hauling Machine Caterpillars apply a pushing force directly onto the cable outer sheath and can be used to install the cable directly or in conjunction with power rollers or winches. 4.4.2.2.5 Bond Pulling With this technique the pulling tension applied by the winch is taken by a wire bond to which the cable is tied at regular intervals.

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At bends the bond is passed through a snatch block and the ties attaching the cable are removed before the bend and reapplied after the bend in a continuous operation. The tension required to install the cable is therefore distributed along its full length and sidewall pressure at bends is reduced to a minimum. 4.4.2.2.6 Mechanical Laying There are three ways of organizing the mechanical laying site: – mechanically excavated narrow trench, and separate laying of the cables: laying and backfilling is done by traditional methods after the trench has been mechanically excavated; – trench excavation and cable laying both mechanical : trench excavation, cable laying and sometimes the backfilling are performed by a machine; – trench excavation, cable laying, backfilling all continuous and mechanized : with this method, trench excavation, cable laying and sometimes trench backfilling can all be done simultaneously in a continuous process over the full length of a homogeneous portion of the link (the joints have to be prepared beforehand). This technique is only used for voltages under 170 kV. The cables are usually buried directly in trefoil formation with a minimum cover of one meter. 4.4.2.2.7 Other Installation Methods in Tunnel • By magnetic belts When laying a cable in a tunnel, many electric powered caterpillars are placed in the tunnel. Caterpillars are operated synchronously to pull the cable in the tunnel. Recently, in order to shorten the construction period and lower the cost by decreasing the number of joints, the cable span becomes longer and longer. For quick and steady cable drawing of such long cables, a cable transfer system with magnetic belts may be used (Figs. 4.50, 4.51, and 4.52). Fig. 4.50 Cable installation in tunnel

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Cable Guide

Cable pulling Caterpiller

2m Cable Cable Guide Rollers Manhole

Overview of cable installation in tunnels

Fig. 4.51 Cable installation in tunnel Cable

Guide roller

Situatin Position of the setting machine in the tunnel

Rail

Driving gear (Magnetic belt)

Fig. 4.52 Magnetic belt pulling machine

• By locomotive and trolley system An innovative technique is being developed for the installation of high voltage cables in a 3 m diameter 10 km long tunnel beneath Auckland (New Zealand). The

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Fig. 4.53 Cable laying locomotive undergoing trials

cables in 1350 m long sections are to be located on racks at varying height on either side of the tunnel. The tunnel has a 710 mm gauge conventional light rail track on the floor. The installation is to be achieved by lowering 30 tonne drums into the cable shafts where an hydraulic Caterpillar Cable Pusher feeds the cable onto 700 custom-made trolleys attached to a wire rope. The trolleys are guided by one of the rails and support and tow the cable along the tunnel into position. The empty trolleys are parked on one rail and travel around to a turntable near the Caterpillar where they accept the cable from the drum. A diesel hydraulic locomotive (tow-shoe unit), driving on solid rubber tyres and guided by the light rail track tows the cable and trolleys from the turntable along the floor into position. The locomotive uncouples from the trolleys and reverses over them while simultaneously lifting from the trolleys up to the cable brackets. The cable is snaked before being lowered onto the wall brackets. The Locomotive has a maximum draw bar pulling capacity of 30 kN and can lay cable at 2 km/h, with a top travelling speed when not working of 4 km/h. The maximum tensile load imposed on the cable during handling is only about 1 kN allowing for lightweight cable brackets to be utilized (Fig. 4.53). The photo shows the Locomotive with trolleys in left foreground. The simulated tunnel and brackets are to the right.

4.4.2.3 Installation Process 4.4.2.3.1 Transportation of Cable to Site Cables are traditionally transported to site on cylindrical drums. The size of these drums being determined by the length of cable to be delivered, the minimum internal diameter of the drum required to satisfy the cable minimum bending radius, the maximum size and weights allowed under existing transport legislation, handling

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Fig. 4.54 Cable reel

limitations in the cable makers facilities and specific loading and size limitations relevant to the particular project for which the cable is supplied. For HV and EHV cables this normally limits the maximum lengths of cables that can be delivered on drums and by road to between 1500 m for HV and 1000 m for EHV cables. Where access to the installation site is possible by sea then the cable can be delivered on turntables or very large drums. In these circumstances, the cable length is only limited by the cable makers’ factory facilities or by the cable system design (Fig. 4.54). 4.4.2.3.2 Cable Bending Radius The bending radius of the cable both on the dispatch drum and especially during the installation and final positioning has to be controlled to avoid damage to the cable during transport and installation to ensure the long-term reliability of the cable circuit. The minimum bend radius of the cable is normally specified by the cable manufacturer and varies in a site environment dependent upon whether the cable is bent in a controlled manner or not. The minimum bend radius when the cable is bent around a former or by using a formed support is generally significantly smaller than when the bend is formed naturally by applying lateral force to the cable. During the installation phase the minimum bend radius is also dependent upon the need to limit the cable sidewall bearing pressures to within acceptable limits as discussed previously and the cable installation design needs to take all these aspects into consideration. 4.4.2.3.3 Cable Temperature The range of acceptable temperature for cable installation is generally defined by the properties of the material used for the cable outer sheath.

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This range is more restricted when PVC is used for the cable outer sheath than when PE is used. Although not normally a significant issue the scheduling of installation activities and selection of the installation techniques used need to take this into account in countries where temperature extremes are experienced. 4.4.2.3.4 Pulling Length The maximum pulling length that can be achieved when using nose pulling is fundamentally a function of the allowable pulling tension and the maximum sidewall pressure (see Sect. 4.4.2.1.3) that the cable can withstand. For other pulling techniques the maximum pulling length is more often determined by either transport or handling difficulties, than the maximum size or weight of the cable drum, or the system design – section lengths for special bonded circuits for example. 4.4.2.3.5 Route Profile The route profile is significant as it effects the magnitude of the forces needed to install the cable. It is important that a full route survey is available to the installation system designer at the early stages of the project to enable the profile to be taken into account since this could affect the maximum allowable pulling lengths of the cable sections being installed. 4.4.2.3.6 Obstacles In most situations the cable route selected will encounter obstacles of one kind or another along the route. Various installation techniques have been developed to allow all eventualities to be overcome in a controlled manner. It is normal therefore to find a number of installation techniques used along a given cable route. Again, it is important that all obstacles along the proposed route are identified and known at the early stages of the design phase since they may affect both the cable design and the selection of the installation and pulling techniques 4.4.2.3.7 Setting Up To ensure the successful implementation of the installation activities the logistics and facilities required need to be carefully considered. Adequate provisions need to be made for the storage and handling of cable drums generally weighing between 15 tonnes and 30 tonnes. Access to the site by heavy transporters, availability of lifting equipment and suitable hard standing for storage and during cable installation needs to be carefully considered and the decision on pulling direction and method must take all these issues into consideration. Prior to actually installing the cable the necessary installation equipment needs to be set up along the cable route.

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The actual equipment needed is dependent upon the installation technique used but must in all cases be positioned to satisfy the installation design criteria and must be supported and fixed in a manner that can withstand the mechanical forces generated during the installation activity. 4.4.2.3.8 Installation of Cable The cable drum is moved into position and mounted on a purpose made stand that allows the drum to rotate. This stand is often motorized to overcome the forces required to turn the drum, hence minimizing the “backtension” on the cable, and also to allow controlled braking of the drum. A braking facility must always be available to ensure the drum only rotates at the required speed. The cable is then installed along the route in accordance with the selected method under close supervision at all times to guarantee that the process runs smoothly and that the design criteria are not exceeded. Upon completion of this stage of the installation and where the cable is accessible, such as in troughs, trenches and tunnels the cable is carefully positioned into its final position in the trench or trough or on its support systems, as determined during the system design phase. For flexible systems the cable is offset either manually or by use of jigs at this stage. On successful installation of the first cable the equipment is moved as necessary for the next cable and the process is repeated until all cables are successfully installed. 4.4.2.3.9 Final Installation Stages On completion of the installation process for all cables the final stages of the installation are carried out. For open trench and trough type installation this requires the installation of stabilized thermal backfill around and above the cables, the application of protective mechanical barriers and warning tapes and finally the reinstatement of the upper layers of the excavation in accordance with local requirements. For other types of installations this requires the installation of mechanical restraints such as cleats and short circuit straps, filling and sealing of ducts etc. 4.4.2.3.10 Site Quality Assurance The quality of the materials used in manufacturing the cable and accessories and the quality of the manufacturing process itself can be closely monitored and is assured by rigorous type and routine testing of the product prior to delivery to site. Long term reliability of the cable circuit can only be guaranteed if the same attention to quality is transferred into the installation phase. It is therefore essential that the installation design and the laying and installation techniques are engineered correctly such that the laid down criteria are complied with. During the actual installation phase, it is important that these criteria are complied with. This requires the correct use and positioning of all equipment,

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appropriate site controls and monitoring throughout the process to record and check that the design standards are complied with. 4.4.2.3.11 After Laying Tests Before the cable circuit is connected to the power transmission system it is normal to carry out a series of tests to confirm the integrity of the cable system including the cable and accessories. The tests vary across the industry but generally include HV tests on the cable outer protection (outersheath) and on the primary insulation. Further tests are carried out such as conductor resistance, bonding and earthing tests. Historically the HV tests have been DC tests and whilst DC testing is still used for SCFF cables and for the outersheath tests it has been recognized that DC testing is not suitable for extruded cables being both unable to consistently detect defects in the system and potentially causing damage to the cable under test. With the availability of mobile on-site AC test sets, of the resonant frequency type, there is a general move to testing extruded cable on site by AC only. Further developments in partial discharge testing have shown that the combination of a PD test with a high voltage AC test is the most reliable means of confirming the integrity of extruded cables prior to connection to the power transmission system.

4.4.2.4 Adaptation of the Cable System Design to the Technique/ Environment 4.4.2.4.1

Adaptation of the Cable System Design to the Technique

4.4.2.4.1.1

Ducts Factors that need to be considered for the cable system design and cable design:

1. Flexible or Rigid System With the cable installed in ducts the system design depends upon whether the ducts are filled or unfilled. If the ducts are filled, usually with bentonite, the cable is effectively restrained and the system design is considered as a rigid system. If the ducts are unfilled then the cable can move to an extent, dependent upon the relative proportions of the cable and the duct. The system is therefore generally described as a flexible system however where the movement of the cable is limited by the size of the duct then it is important to be aware that the cable will develop thrust due to thermomechanical stress. 2. Pulling Tension Since the only practical method of installing cables through a fully ducted system is by “nose” pulling it is essential that the necessary design studies are completed to calculate the pulling tensions that will be required to install the cable and to check that

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the cable limits are not exceeded. If necessary, the route and system will have to be modified to ensure the pulling tensions are within the cable design limits. 3. Thrust in Manholes It must be recognized that cables installed in ducted systems will develop thrust. In manholes the system design needs to take this into consideration to avoid problems with the accessories. 4. Cross-bonding Transposing of cables in a ducted system is more difficult to execute than for other laying techniques and the system design needs to provide for this. 5. Conductor Cross Sectional Area Due to the poorer thermal performance of the unfilled duct the cable rating will be lower and therefore it may be necessary to increase the cross-sectional area of the cable conductor to carry the required current. 6. Metallic Sheath With the cable unrestrained the sheath fatigue performance over the life of the cable needs to be carefully considered and the cable system design and cable design need to be reviewed to ensure the integrity of the metallic sheath. 7. Cable Oversheath It is essential that the installation method avoids damage to the cable oversheath and as an added precaution it is normal for a more robust material to be used such as MDPE rather than PVC. Dependent upon the cable route and type of ducts it may be necessary to increase the thickness of the cable oversheath to provide greater protection during the installation phase.

4.4.2.4.1.2

Direct Burial Direct burial is the most commonly used cable laying technique and since the cable is restrained throughout the route the system is always a rigid system. Factors that need to be considered for the cable system design and cable design: -

1. Route details Careful planning of the route is required to ensure that the rating and long-term performance of the cable circuit can be assured. Details of any obstacles along the route need to be provided to allow the system to be designed to avoid these.

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The route details will allow an assessment to be made of the positioning of joint bays and location of installation equipment, drums, etc. to allow the optimum solution to be engineered. 2. Environment Knowledge of the environment through which the route is passing is essential. The thermal resistivity and make-up of the indigenous soil should be understood to allow the cable cross section, cable spacing, depth of laying, backfill requirements and bonding arrangements to be defined to achieve the required rating. 3. Cable Oversheath The cable oversheath acts as a corrosion barrier for the cable metallic sheath. Depending upon the location and environment additional precautions may be necessary to provide an oversheath that is resistant to local ground contaminants or lifeforms such as termites and rodents that could damage the normal oversheath materials. 4. Duration of the works Trench have to stay open between two joints up to the cable pulling. This can lead local authorities to ban this technique in urban areas to avoid having trenches open too long.

4.4.2.4.1.3

Tunnels By their nature, tunnels allow the cable system and cable design to be optimized and enables the designer to adopt the most cost-effective form of design for the support systems and the use of long cable lengths to minimize the number of joints within the system. In all cases it is essential that the long-term performance of the system is not compromised and the risks associated with each stage of the process must be fully assessed and understood. Factors that need to be taken into consideration for the system and cable designs:

1. Flexible or rigid Tunnel installations are normally installed as flexible systems although in some circumstances the systems may be installed in troughing or cement bound sand surround making a rigid system. 2. 3. 4. 5.

Support System Cable Lengths Sheath Voltages Bonding

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6. Metallic Sheath 7. Oversheath It is common for cables installed within tunnels to be required to have enhanced fire performance capability. This can be provided by low flame type materials or by the addition of addition flame retardant coatings applied after installation. 8. Fire Performance of the system The possibility of fire within a tunnel is extremely serious and the system design and components of the system need to be assessed to minimize risk to personnel and assets in the event of a breakdown within the cable system. This is a significant issue for SCFF cables installed within a tunnel and often such cables are surrounded by cement bound sand to reduce the risk of damage which could lead to cable failure. 4.4.2.4.1.4

Troughs This installation technique is fundamentally identical to that of direct burial and as such the system and cable designs are the same as for the direct burial technique. 4.4.2.4.1.5

Bridges Factors that need to be taken into consideration for the system and cable designs :

1. Flexible or Rigid Cables installed in or on bridges may be installed as flexible or rigid systems in general the system design is dependent upon the particular requirements of the route. 2. Transition Design Careful consideration has to be given to the design and installation of facilities within the route to cater for the movement of the bridge structure due to thermal expansion or other possible movement. There is generally a need to design a transition area between the fixed portion of the route and the route on the bridge to allow for the inevitable movement between the two systems. 3. Oversheath 4. Fire Performance of the system 4.4.2.4.1.6

Shafts Installation of cables in shafts introduces the problem of potential differential movement between the cable core and metallic sheath. The severity of the problem being directly related to the depth of the shaft.

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Cable can be installed in either flexible or rigid systems although generally the cables are rigidly fixed at the top and bottom of the shaft. In either case particular attention needs to be paid to ensuring the clamping system is designed to prevent any slippage of the core within the cable sheath. Factors that need to be taken into consideration for the system and cable designs : 1. 2. 3. 4.

Flexible or Rigid Cleating Metallic Sheath Oversheath

4.4.2.4.1.7

Horizontal Drilling For this technique the cables are usually installed within ducts that are installed during the drilling process. In this instance the system design and cable design adaptations are as described for the ducted installation technique (see above). 4.4.2.4.1.8

Pipe Jacking The installation technique adopted is dependent upon the diameter of the pipe jack and can be any of a number of alternative techniques. For example, the cable may be installed in ducts pulled through the pipe jack after completion of the pipe jacking operation, alternatively the cables may be installed in air on steelwork installed after the pipe jacking process is complete. The system design chosen may therefore be flexible or rigid with the decision being based upon the installation technique selected for the particular application. 4.4.2.4.1.9

Microtunnels Microtunnels can be treated in the same manner as pipejacks except that generally the diameter does not allow personnel access into the microtunnel and therefore the installation of support steelwork is not possible. The installation technique adopted is therefore generally that of ducts pulled into the microtunnel after completion of the tunnelling process 4.4.2.4.1.10

Mechanical Laying For this technique the cable is installed in a direct buried environment and therefore the system is a rigid system. This technique is best suited to light cables which allow longer lengths to be installed. While it is possible to surround the cable with cement bound sand the process is not as controllable as other techniques, such as direct burial and therefore the cable design needs to take this into account. This may affect the sizing of the conductor due to a degree of uncertainty regarding the thermal resistivity of the backfill material.

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In addition the metallic sheath and cable oversheath design may be adapted to provide a light cable design which will allow longer cable lengths to be transported and installed but which will be robust enough to withstand the rigors of this installation technique without effecting the performance of the system in the long term. Factors that need to be taken into consideration for system and cable design : 1. 2. 3. 4.

Lightweight construction Oversheath Rating Bonding/sheath voltages.

4.4.2.4.1.11

Embedding For this technique the cables are usually installed in ducts which are embedded into the ground during the embedding process. Generally therefore the system design and cable design are as for the ducted technique.

4.4.2.4.1.12

Use of Existing Structures Factors that need to be taken into consideration for system and cable design :

1. 2. 3. 4. 5. 6. 7. 8.

Flexible or Rigid Thrust at transitions and joint positions Duct Sealing Cleaning and Assessment of asset Pulling Tensions Overall dimensions Lengths Oversheath

4.4.2.4.2 4.4.2.4.2.1

Adaptation of the Cable System Design to the Environment

Drying of Soil For highly loaded cables drying of the surrounding soil is a strong possibility and the cable rating calculations need to take this into account with the conductor cross sectional area being selected on this basis. The difference between a fully dry backfill and the same material with even a very small moisture content is dramatic. For example, research has shown that a 2% moisture content reduces the thermal resistivity of normal backfill such as sand or cement bound sand by 50%.

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Failure to recognize this possibility will result in the cable exceeding its design temperature limits due to the dramatic increase in the thermal resistivity of the surrounding material. This will lead to eventual failure of the cable. Factors that need to be taken into consideration for system and cable design : 1. Depth of laying and separation of cables 2. Special backfill requirements

4.4.2.4.2.2

Water Drainage Water drainage may have a number of effects upon the cable system. It is possible that over time water draining into the cable route could wash away the cable system backfill material compromising the cable rating. Inadequate drainage could lead to the cable and accessories being immersed continuously in water and special precautions need to be taken to ensure that adequate sealing is provided to prevent moisture ingress into the cable and accessories such as joints and link boxes. Factors that need to be taken into consideration for system and cable design :

1. Special backfill requirements 2. Sealing for joints and other accessories

4.4.2.4.2.3

Temperature of the Soil/Environment The temperature of the medium surrounding the cable circuit is a fundamental factor in determining the rating of the cable system. It is essential therefore that the temperature profile is known throughout the route. Under extreme conditions of either high or more normally low temperature installation of the cable may not be possible and work may have to be planned at a time when the ambient environment temperatures are within acceptable limits. Factors that need to be taken into consideration for the cable system design:

1. 2. 3. 4.

Cable cross section and spacings Depth of laying Special backfill Oversheath material

4.4.2.4.2.4

Hardness of the Soil The hardness of the soil in the main effects the construction of the route and may influence the route plan and selection of installation technique.

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4.4.2.4.2.5

Stability of the Soil Where unstable soil conditions are expected then the installation design needs to allow for this. This can take the form of the use of civil construction techniques to stabilize the soil in the vicinity of the cable circuit. Where settlement of the route is expected to take place then the installation system design can make provision for this along the route. This is especially important at points of known discontinuity where there is the potential for shear stress to be imposed on the cable system. 4.4.2.4.2.6

Thermal Resistivity of the Soil The thermal resistivity of the soil surrounding the cable circuit has a direct effect upon the rating of the cable circuit. It is therefore important that this information is available to allow the system design to proceed. Where the surrounding soil is found to have a high thermal resistivity then it may be necessary to excavate beyond the normal area required to install the cable and replace with material with a more suitable thermal resistivity. Factors that need to be taken into consideration for the cable system design:

1. 2. 3. 4.

Cable cross section Depth of laying Cable separation Special backfill

4.4.2.4.2.7

Seismicity Where seismic activity is expected, it is possible to accommodate possible ground movement by adopting the same techniques as would be used for unstable ground conditions. 4.4.2.4.2.8

Frost In general, high voltage cables are installed at depths which are not normally affected by frost. During operation frost will have little effect on the cable circuit although frosts occurring during period of de-energization could lead to cracking and disturbance of the backfill surrounding the cable. This could lead to voids being generated which would affect the thermal performance of the cable surround in a direct buried situation. Frost during installation may mean that the ambient temperature is below the minimum installation temperature. In which case installation of the cable will have to be delayed until a temperature increase occurs. Factors that need to be taken into consideration for the cable system design:

1. Depth of laying 2. Backfill 3. Oversheath material

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4.4.2.4.2.9

Archaeology Evidence of archaeological remains along a planned cable route would not influence the cable design but would influence the technique used for constructing the route. This could in turn effect the cable design in line with comments previously made depending upon the installation technique selected.

4.4.2.4.2.10

Presence of Termites Termites will attack the outer sheath covering and compromise the corrosion protection system for the metallic sheath. The outer sheath material needs to be impervious to termite attack or provided with suitable chemical deterrents if possible. Otherwise alternative installation techniques, such as ducted techniques will be required.

4.4.2.4.2.11

Laying in National Park The cable system design is influenced by the installation technique used to overcome any restrictions placed as a prerequisite to approval of a cable route through the National Park. The factors that need to be taken into consideration are dependent upon the technique selected as indicated before.

4.4.2.4.2.12

Duration of the Work The duration of work has no influence upon the cable system design but may influence the choice of installation technique. SCFF cables require longer to install since the hydraulic procedures are an additional complexity when compared with extruded cables. However, selection of the type of cable to be used is not normally influenced by this factor. The factors that need to be taken into consideration are dependent upon the technique selected as indicated before.

4.4.2.4.2.13

Maintenance and Repairing Process Cable systems are designed for 40 years operation and are generally very reliable. Maintenance procedures for extruded cable systems are generally limited to inspection of the cable and associated equipment and periodic checking of the integrity of the cable oversheath and bonding systems. The introduction of partial discharge monitoring techniques should allow the condition of the cable system to be assessed over time. Maintenance for SCFF cable systems is more complex due to the periodic checks required on the hydraulic system and components. Routine sampling of the dielectric fluid and analysis of the dissolved gases within the fluid allow a degree of condition assessment to be undertaken and comparisons made over time.

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Considerations need to be made at the design stage as to how the system will be maintained and to ensure access and provisions are made such that the maintenance regime can be carried out. Although cable systems are very reliable the need for repair cannot be discounted and again this needs to be considered at the design stage. Whilst not directly effecting the cable design or installation system design the need to cater for a future repair will influence the choice of installation technique with the resulting effect on the cable system design as mentioned earlier. 4.4.2.4.2.14

Cable Removal After Operation The factors associated with removal are very similar to the issue of cable repair noted above.

4.5

External Aspects

4.5.1

Location (Urban vs. Rural)

The high-voltage cable installation methods are obviously adapted depending on the location of the laying site so as to take into account the local and environmental limitations and constraints. Therefore, not surprisingly, in urban areas the installation in ducts is the most frequent method, followed, in this order by: • conventional installation in open trench; • visually unobtrusive methods (tunnels, microtunnels and, to a lesser extent, pipe jacking and horizontal drilling); See TB 770 on trenchless technologies. • utilization of existing structures, e.g., bridges. In rural areas, however, the constraints regarding time-limits on disruption due to execution of the works, and with respect to available space, are much less important than in urban areas. Therefore, in rural areas the more traditional laying methods are most frequently applied, such as ducts and direct burial (of which costs are lower than those used in urban areas). At special crossings, placing on bridges and directional drilling methods may be applied, though special laying methods are not the general philosophy for cable laying in rural areas. As regards laying depth there is not much difference between cable laying in urban or in rural areas, since a minimum depth is usually set by regulations, as we will see later (4.5.5).

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313

Right of Way

The rights of way are usually settled by joint agreement between the utility and a private owner or the utility and one or several public authorities (Roads, Railways, Bridges, . . .). When using a public authority property, the construction techniques used are generally agreed with the partners, before beginning the works. Then, it has to be decided under whose responsibility the works have to be done, the utility or the public authority.

4.5.3

Magnetic Fields

Reference: “Magnetic field in HV cable systems: systems without ferromagnetic component” – Electra CIGRE – Technical Brochure n
104 – Joint Task Force 36.01/ 21 – June 1996. Refer to TB 373, TB 559 and TB C3.B1.B2 Although the delicate question of magnetic fields is usually discussed regarding overhead power lines, increasingly attention is being paid to magnetic fields when selecting the configuration of the cables and the routes of buried links. Indeed, in more and more countries now exist recommendations, limits and possibly even standards as to the level of magnetic fields. These concerns may eventually dictate changes in planned routes, but, above all, they may increase the burial depth or implicate some precaution disposition. We shall bear in mind that buried cables (contrary to overhead lines) do not generate electric fields outside their metallic screen. As such sheaths are earthed, an electric field only exists between the conductor and the sheath. Several three-phase single core cable configurations can be considered. A lot of factors have an influence on the magnetic field, e.g., phase spacing, burial depth, load current amplitude, phase arrangement in systems of several three-phase circuits, distance between them and induced currents in the sheaths (which are strongly affected by a lot of factors).

4.5.3.1 Flat Arrangement A system of three single core cables in flat formation is first considered. It is characterized by geometrical parameters which are phase spacing (s) and burial depth (d). Height considered for calculations above ground (h) is also defined (Fig. 4.55). The currents in cables are assumed to be balanced, i.e. IA ¼ I < 0
, IB ¼ I < 120
, IC ¼ I < 240
, and the frequency is 50 Hz. The current will be fixed to a reference value of I ¼ 1000 A.

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Fig. 4.55 Flat arrangement, 1 circuit

Line Z

Line X

h

d

A

B

C –

S

S

The two diagrams below represent the magnetic flux density along a horizontal line at 1 m above the ground surface, considering various burial-depths and spacings of the phases (Figs. 4.56 and 4.57). The highest magnetic field value immediately occurs above the cables. The distance from the cables (h þ d) as well as the phase spacing appear to have

Magnetic flux density (Brms) [10-6 T/kA]

h = 1 m. d = Burial depth, s = Phase spacing

40

s = 0.08 m. d = 0.5 m s = 0.12 m. d = 0.5 m s = 0.20 m. d = 0.5 m

30

s = 0.30 m. d = 0.5 m s = 0.08 m. d = 1.5 m

20

s = 0.12 m. d = 1.5 m s = 0.20 m. d = 1.5 m

10

0 -10

s = 0.30 m. d = 1.5 m

-5

0 Distance from center line (x) [ m ]

Fig. 4.56 Brms profiles with various s

5

10

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Magnetic flux density (Brms) [10-6 T/kA]

h = 1 m. s = Phase spacing, d = Burial depth

40 d = 0.5 m. s = 0.08 m d = 1.0 m. s = 0.08 m

30

d = 1.5 m. s = 0.08 m d = 0.5 m. s = 0.30 m

20 d = 1.0 m. s = 0.30 m d = 1.5 m. s = 0.30 m

10

0 -10

-5

0 Distance from center line (x) [ m ]

5

10

Fig. 4.57 Brms profiles with various d

an important influence on the flux density whose values are higher for low burial depths and high phase spacings. Moreover, it particularly appears that, for a fixed phase spacing, burial depth has no effect on the flux density at horizontal distances from the system center line that are greater than several times this depth. Further, the reduction of magnetic field away from the center line is higher for a low burial depth. Two systems of three single core cables in flat formation can also be considered, assuming the same current of 1000 A in both circuits. Their geometrical parameters are phase spacing (s), burial depth (h) and distance between systems (g). Height above ground (h) is also defined (Fig. 4.58).

Fig. 4.58 Flat arrangement, 2 circuits

Line Z Line X h d

A

B – s

C

s

A’

g

B’

s

C’

s

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Magnetic flux density (Brms) [10-6 T/kA]

120 s = 0.30 m. g = 0.70 m. d = 0.5 m

110

h = 0.5 m. ABC ABC

100

h = 0.5 m. ABC CBA

90 h = 1.0 m. ABC ABC

80 70

h = 1.0 m. ABC CBA

60

h = 1.5 m. ABC ABC

50

h = 1.5 m. ABC CBA

40 30 20 10 0 -5

-4

-3

-1 -2 0 1 2 Distance from center line (x) [ m ]

3

4

5

Fig. 4.59 Brms profiles for two cable system configurations with various h

The hypotheses are identical to those referred to above. Furthermore, two configurations have been retained : ABC-ABC (same order of phases) and ABC-CBA (inverted order of phases). The figure below illustrates the evolution of the magnetic flux field considering various heights above the ground, at the set parameters g, d and s. (Fig. 4.59) The ABC-ABC configuration appears to give a lower magnetic flux density near the cables than the ABC-CBA configuration. However this last configuration gives the lowest magnetic flux density from a certain distance from the cables (breakpoint for h ¼ 1 m). Such a breakpoint distance depends on g and s. The next figure shows profiles of magnetic flux density along a horizontal line one meter above ground for both configurations and for several system spacings (Fig. 4.60). It can be seen that increasing system spacing respectively decreases or increases the magnetic field for ABC-ABC and ABC-CBA configurations. We must also mention that the magnetic field is often higher at locations where junctions are made, i.e. where connections are made between power cable screens and the ground wires (if any), especially if these connections are made in an aboveground junction box (for paralleling of the screens). Judicious connection of the screens and ground wires (connection between portions of the buried link made underground instead of in an aboveground junction box) or connection made in a buried junction box can significantly reduce the value of the magnetic field.

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70 g = 0.3 m. ABC ABC

Magnetic flux density (Brms) [10-6 T/kA]

s = 0.30 m. h = 1.0 m. d = 0.5 m 60

g = 0.3 m. ABC CBA g = 0.5 m. ABC ABC

50

g = 0.5 m. ABC CBA

40

g = 0.7 m. ABC ABC g = 0.7 m. ABC CBA

30 20 10 0 -5

-4

-3

-2 -1 0 1 2 Distance from center line (x) [ m ]

3

4

5

Fig. 4.60 Brms profiles for two cable system configurations with various g

4.5.3.2 Trefoil Arrangement A system of three single core cables in trefoil formation is now considered. Its geometrical parameters are phase spacing (s) and burial depth (d). Height above ground (h) is also defined (Fig. 4.61). In fact, usually, the three cables touch each other and variations of phase spacing allow to consider cables of several outer diameters. Fig. 4.61 Trefoil arrangement, 1 circuit

Line Z

Line X

h

d S

B

S

–

A

C S

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The first of the two next figures compares the magnetic flux density profiles along a horizontal line one meter above ground with a burial depth of one meter for both flat and trefoil formations with several phase spacings. The second one compares the magnetic flux density profiles along a horizontal line one meter above ground for several burial depths and a fixed phase spacing for both formations (Figs. 4.62 and 4.63).

Magnetic flux density (Brms) [10-6 T/kA]

25 h = 1 m. d = 1 m s = Phase spacing (flat) st = Phase spacing (trefoil)

s = 0.08 m s = 0.12 m

20 s = 0.20 m s = 0.30 m 15 st = 0.08 m st = 0.10 m 10 st = 0.12 m 5

0 -10

-5

0 Distance from center line (x) [ m ]

5

10

Fig. 4.62 Brms profiles for both flat and trefoil formations with various s.t and strefoil

Magnetic flux density (Brms) [10-6 T/kA]

h = 1 m. d = Burial depth d = 0.5 m. s = 0.08 m

10

s = Phase spacing (flat) st= Phase spacing (trefail)

d = 1.0 m. s = 0.08 m d = 1.5 m. s = 0.08 m d = 0.5 m. st = 0.08 m d = 1.0 m. st = 0.08 m

5

0 -10

d = 1.5 m. st = 0.08 m

-5

0 Distance from center line (x) [ m ]

Fig. 4.63 Brms profiles with various d for both flat and trefoil formations

5

10

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The trefoil formation gives clearly the lowest magnetic field which is more than 30 % lower than the one of the flat formation whatever phase spacing is. Two systems of three single core cables in trefoil formation are also considered (Fig. 4.64). The hypothesis are the same as those made in paragraph 4.5.3.1. The next figure shows again the profiles of the magnetic fields for the configurations ABC-ABC and ABC-CBA considering various heights above the cables, at the set parameters g, d and s (Fig. 4.65).

Fig. 4.64 Trefoil arrangement, 2 circuits

Line Z Line X h d

S

B

A

B’

S

S A’

C S

S

C’

g

S

Magnetic flux density (Brms) [10-6 T/kA]

s = 0.12 m. g = 0.70 m. d = 0.5 m 30

h = 0.5 m. ABC ABC h = 0.5 m. ABC CBA h = 1.0 m. ABC ABC

20

h = 1.0 m. ABC CBA h = 1.5 m. ABC ABC h = 1.5 m. ABC CBA

10

0 -5

-4

-3

-2 -1 0 1 2 Distance from center line (x) [ m ]

Fig. 4.65 Brms profiles for two cable system configurations with various h

3

4

5

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Magnetic flux density (Brms) [10-6 T/kA]

s = 0.12 m. h = 1.0 m. d = 0.5 m

g = 0.3 m. ABC ABC

20 g = 0.3 m. ABC CBA g = 0.5 m. ABC ABC g = 0.5 m. ABC CBA g = 0.7 m. ABC ABC

10

g = 0.7 m. ABC CBA

0 -5

-4

-3

-2 -1 0 1 2 Distance from center line (x) [ m ]

3

4

5

Fig. 4.66 Brms profiles for two cable system configurations with various g

The ABC-CBA configuration appears to give a lower magnetic flux density than the ABC-ABC configuration. Figure 4.66 shows again the profiles of the magnetic fields along a horizontal line 1 m above ground level, for the two configurations and with various spacings (Fig. 4.66). Unlike in the horizontal arrangement, here we can see that the increase of spacing between the two systems results in a lower magnetic field in the two configurations ABC-ABC and ABC-CBA.

4.5.3.3 Vertical Arrangement A system of three single core cables in vertical formation can also be considered. Its geometrical parameters are phase spacing (s) and burial depth (d). Height above ground is also defined (h) (Fig. 4.67): This configuration is in fact an artifice considered for the purpose of enabling to compare the magnetic field values of this configuration with those of the two configurations discussed above (trefoil, flat). In reality a vertical configuration is only adopted in tunnels, bridges or other structures, practically never for buried links.

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Fig. 4.67 Vertical arrangement, 1 circuit

Sv

Sv

d

h

Line X

h=1m; d=1m s=Phase spacing (flat) st=Phase spacing (trefoil) sv=Phase spacing (vertical)

Magnetic flux density (Brms) [10e-6T/kA]

30 25

st=0.08m

20

st=0.12m s=0.12m

15

s=0.3m

10

sv=0.12m sv=0.3m

5 0 -10

-5

0

5

10

Distance from center line (x) [m]

Fig. 4.68 Brms profiles for flat, trefoil and vertical formations with various sflat, strefoil, and svertical

Figure 4.68 shows the magnetic flux density profiles along a horizontal line 1 m above ground, with a burial depth of 1 m for flat, trefoil and vertical configurations and several phase spacings (Fig. 4.68). The values of magnetic field for the vertical configuration are lower but close to the flat configuration. They rapidly match when departing from the vertical axis. It results that the trefoil formation clearly remains the most advantageous option with respect to magnetic field.

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Two systems of three single-core cables in vertical formation are also considered (Fig. 4.69). The hypotheses are identical to those made in paragraph 4.5.3.1. The last figure below shows the magnetic field profiles for the ABC-ABC and ABC-CBA configurations for vertical, trefoil and flat formations (Fig. 4.70). It appears that in the ABC-ABC assumption the magnetic field of the vertical formation is higher in the middle of the 2 systems that it is with the flat formation.

Fig. 4.69: Vertical arrangement, 2 circuits

Sv

Sv

d

h

Line X

g

Magnetic flux density (brms) [10e-6T/kA]

h=1m; d=0.5m;g=0.7m s=Phase spacing (flat) st=Phase spacing (trefoil) sv=Phase spacing (vertical)

70 60 50 40 30 20 10 0

ABC ABC ; st=0.3m ABC CBA ; st=0.3m ABC ABC ; s=0.3m ABC CBA ; s=0.3m ABC ABC ; sv=0.3m

-5

-4

-3

-2

-1

0

1

2

3

4

5

ABC CBA ; sv=0.3m

Distance from center line (x) [m]

Fig. 4.70 Brms profiles for two cable system configurations with fixed h, d, g and s ¼ st ¼ sv ¼ 0.3 m

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Conversely, for the ABC-CBA configuration, the magnetic field is clearly less in vertical formation than in flat and trefoil formations. At higher distances of the center line, it appears that the decreasing of the values of magnetic field for the trefoil configuration is slower.

4.5.3.4 Comparison Between Overhead Lines and Buried Links Reference: “Magnetic field in HV cable systems: systems with ferromagnetic component” – Electra CIGRE – Technical Brochure n
104 – Joint Task Force 36.01/21 -June 1996. In addition, it is important to remind that an electric field is present around overhead lines, whereas in cables, the electric field is completely confined inside the electric screen. The assumptions regarding the types of cable are the same as in the previous paragraphs, and we have considered three configurations : trefoil, flat and vertical. As regards the overhead line we considered a line composed of one circuit and an earth wire. The magnetic field calculations were performed for a distance of 10 m between ground level and the conductor and with a base current of I ¼ 1000 A. In order to establish a parallel between the buried links and the overhead lines we imagined the three overhead line conductors to be in vertical and flat formations (Fig. 4.71). The graph clearly indicates that the magnetic field of overhead line and buried link are of the same order on the axis, the difference being that the magnetic field of

h=1m; d=1m h overhead line=10m s=Phase spacing (flat) st=Phase spacing (trefoil) sv=Phase spacing (vertical)

Magnetic flux density (Brms) [10e-6T/kA]

30 25

st=0.12m sv=0.12m

20

s=0.12m

15

s=0.3m line v-config

10

line h-config

5 0 -10

-5

0

5

10

Distance from center line (x) [m]

Fig. 4.71 Brms profiles for flat, trefoil and vertical formations (buried links), Brms profiles for flat and vertical formations (overhead lines)

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the overhead line diminishes much more slowly than that of the buried link. With the buried link the magnetic field becomes very low at only a few meters apart from the link axis. It also appears that for a given formation the magnetic field values of a buried link may be higher in a buried link compared to an overhead line. However, the information supplied by the graph cannot be considered totally reliable, because magnetic fields are known to be sensitive to many parameters (order of the phases, number of circuits, current in the screens or ground wire(s), configuration of the cables, . . .) which may significantly affect the values. For example, if the value of h decreases, the value of the magnetic field will be increase for underground cables and decrease for overhead lines.

4.5.3.5 Conclusion As a conclusion it must be said that, whatever the cables formation, the magnetic fields induced by buried links are lower than those specified in the national or international recommendations generally accepted. Also, there are now several ways in which the magnetic fields of buried links can be further reduced, for instance by placing steel or aluminum sheets around the cables in the trench, or by placing the cables in steel pipes. Another measure could be to place passive loops when the Electro-magnetic field is too high as that can be the case close to the joints. (See Figs. 4.72 and 4.73) In this respect, we can mention the work done by the Joint Task Force 36-01/21 “Magnetic field calculation in underground cable systems with ferromagnetic components” (Electra n
174, October 1994), the WG C4.204(TB 373) and the WG B1.23 (TB 559).

Fig. 4.72 Passive loop above a joint bay

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Fig. 4.73 Passive loop in a joint chamber, installation in air

4.5.4

Existing Services

The proximity of buried power lines to other services in ducts, sewers, cables and other utilities’ networks is these days practically unavoidable, particularly in urban areas. Generally, power cables are laid as much as possible at sufficient distance from other services in order to prevent the damage of existing installations during the laying of HV cables. In urban areas this becomes increasingly difficult. The effects of a short-circuit of a phase on its environment (gas, telecommunications, . . .) are discussed in paragraph 4.5.6. • Gas The clearances to be observed between gas pipes and HV cables, and to a lesser extent the laying techniques, are generally imposed by the gas utility. The gas utility’s stipulations naturally differ depending on the type of gas transmitted, the pipe diameter and the gas pressure in the pipe. Using ducts in which later the cables should be laid, is strongly advised against in the vicinity of gas pipes, because the former ducts may be a source of accumulation of gas in the event of a gas pipe leak (hence a risk of explosion). Problem of parallelism of a gas pipe to HV cables: see • Telecommunications • Electrical cables The proximity of various electrical links can have both an electric impact (in case of defects) and a thermal impact. They contribute to soil heating and, in this way, they reduce the carrying capacity of the electrical links. A deeper investigation of these situations is highly recommended prior to laying the cables.

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• District heating Like in the above case, the thermal impact of the steam pipes on the carrying capacity of the buried power line must be investigated. • Telecommunications Telecommunication cables (like gas pipes) are a typical and frequent example of a system affected by the HV cables that run parallel to them. Indeed, any electric current transiting in a conductor generates a magnetic field around that conductor. If the current is the alternating type this magnetic field will in turn induce a potential rise between the extremities of an open circuit surrounding the conductor, or the circulation of an induced current in a closed circuit surrounding the conductor. However, we shall bear in mind that the most critical situation arises in the event of a fault. If the conditions are acceptable during a fault situation, they are obviously acceptable during a normal situation. When installing a buried HV link, this impact can be first reduced by the presence of the cables’ metal screens which are earthed at either ends (circulation of a screen current) and also by placing ground wires connected to the earthing network of the line, so facilitating the returning of a fault current to the source, this reducing the magnetic field perceived by the world outside the cables. World-wide, protection of telecommunication infrastructure is one of the main concerns of electrical utilities. • Water Water pipes do not present a particular risk, except when leaks are sprung. However, even if the protective screen of the HV cables is damaged, most modern cables have sufficient radial and longitudinal leak-tightness to protect them (but the cable has even so to be repaired if damaged). In turn, the erosion of the backfill following an accidental leak of water presents a certain risk (particularly if it is a special backfill that is being washed away by the leak). • Sewers Sewers do not present a specific risk except possibly in relation to mechanical damage during work at or around sewers on cables that have been laid too close to the sewers. It is worthwhile to mention also that especially main (large diameter) sewers may release quite some heat, which may negatively affect the carrying capacity of the cables. • Trees Trees and cables may have an impact on each other. If cables have to be laid very close to threes, excavation must be extremely careful (at extra cost and time) so as not to damage the root systems of the trees, and, later

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when the buried power link is in service, the drying of the soil may affect the growth of the trees (and possibly eventually kill the trees); the drying of the soil may also negatively affect the carrying capacity of the cables. Also, the root systems of the tree may get entwined around the cables, making difficult later intervention on the line. Accordingly, it is recommended (or imposed by local authorities) that sufficient distance be adopted (at least 2.5 m) between the link and the trees, or that the cables be placed in ducts. • Railways The phenomenon most feared in the vicinity of railway or tramway substations is that of corrosion of the metal screens around the buried power line (which corrosion may be incurred even at considerable distance from these substations). Corrosion develops when a direct current strays from the screen and flows through the soil to a direct-current source. In order to protect a metal screen like a gas pipe against this type of corrosion, the utilities install cathodic protection stations to bring the ducts to a sufficiently negative potential compared to the soil, so that no current can escape from it. The direct connection of a steel structure to a cathodic protection station protects this structure against any electrochemical corrosion. Although in the past the metal screens of HV lines have been connected to such cathodic protection stations but the method has the disadvantage that the electrical utilities can depend on other companies’ installations. Moreover, a very simple passive protection method of the metal screens exists, which consists of make use of the normally existing plastic outer sheath (medium or high-density polyethylene). This sheath thanks to its high electric resistivity impedes the leakage of any currents to the soil. However, it will be able to provide this protection only as long as the sheath is not damaged. Indeed, if a defect appears, the density of DC current through the outer sheath defect could reach very high values and causes very rapidly important damage to the metallic sheath. This implies regular inspection (at least annually) of the dielectric strength of this sheath.

4.5.5

Legal Aspects

Among the great choice of laying techniques, there are none that are systematically forbidden by the local authorities. The two techniques that cause the most controversy, are the laying in trenches, which naturally causes quite some local disturbance, and the placing of cables on bridges (which may be historic or architectural monuments, bridges that require constant maintenance work, . . .).

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It can be observed that national authorities or the utilities hardly ever forbid one or the other method, unless there are very particular reasons. It must be borne in mind that in certain countries the law is such that the owner of the land also owns the subsoil under that land. During link construction requiring for instance tunnel jacking or horizontal drilling, it is in those cases absolutely necessary to secure the authorization from the person that owns the land under which the link construction will take place. An alternative option may be to build the link under the public roadway, in which case only authorization by the public authorities is necessary (but this may entail a longer route for the link). Also, as said before, magnetic field calculations more and more dictate, through guidelines, or even through standards, the choice of the route and, above all, the depth at which the cables will have to be buried. The usually regulatory-imposed minimum depth is 1 m. In turn, there are hardly ever any legal stipulations regarding the width of the trench. Finally, it should also be borne in mind that, world-wide, there are more and more legal restrictions regarding the duration of opening of the trench, this resulting in the necessity to adopt shorter lengths, and restrictions concerning the periods of the year or day during which civil works and cable-laying work can be done.

4.5.6

Safety Aspects

Safety aspects must be taken into account as soon as at the early stages of link design. A risk analysis becomes increasingly necessary that clearly identifies the potential risks. A first step in this analysis consists of collecting all information about the various utility networks in the vicinity of the link, and evaluating them with respect to possible risks. Safety implies that precautions be taken in order to protect: • • • •

The HV link The other links or networks in the vicinity; The workers working near the HV links or other networks. The public

The safety aspects relating to terminations are considered by CIGRE Working Group B1-19 and WG B1.29 (TB 560)

4.5.6.1 Protection of the Link from External Damage Apart from being at a depth that gives them some protection, the HV cables are usually protected all along their route by a cover of durable and mechanically resistant materials that protect them against damage from excavation tools. This cover extends above the cables and may consist of concrete or polyethylene or other slabs.

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Furthermore, the cables are often signaled by non-corrodable markers placed above the line. This may consist of colored plastic strip showing the voltage level and the name of the utility, sufficiently resistant not to be ripped by a mechanical excavator. It is clear that in particular cases additional safety devices may be installed like, for instance: • placing of steel plates above the protection slabs when the minimum regulatory depth is impossible to comply with; • placing of warning panels above ground level on a bridge or on the river banks (embedding, pipe jacking, . . .); • simply placing the cables in strong ducts or troughs. Lateral protections are rarely used because the depth of the cables is considered to be (nearly) enough large to avoid aggressions due to works carried by the most other Utilities. Joint pits when in plain soil are protected similarly to the cables, but their protection extends at least over the entire surface of the joints. When joints are made for instance in prefabricated pits or in tunnels, these joints are naturally protected by these structures that house them. Only the access to these structures needs to be designed against intrusion by unauthorized persons. Also, in certain cases, particularly safety measures may be required (such as lining) in order to protect a link situated in a tunnel from other cables or pipes running in that tunnel. It is clear that placing slabs or markers is not possible when using trenchless laying techniques. Moreover, it is not easy to give the exact route in the x, y, z axis. Nevertheless, it has to be noticed that with these techniques, cables are usually laid at great depth and so are protected from usual external damage.

4.5.6.2 Protection of the Environment from a System Fault In the event of a short-circuit in a cable the best protections against an explosion remain the adequate depth at which the cables are buried and the presence of protection slabs. Moreover, in the case of a phase-to-earth fault (e.g. in the event the cable is punctured by a mechanical excavator), the surrounding soil and the installations of third parties situated in the close vicinity of the HV line will incur a rise in potential. Most often the installations of third parties are grounded or connected to a cathodic protection system. Accordingly, it is the external protection cover of the installation, i.e. the layer that insulates the metal part (screen or pipe) from the soil that will have to sustain the fault voltage. Generally, these protections are not particularly designed to have high dielectric strength, as they are primarily designed for protection against electrochemical

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corrosion by the soil. Accordingly, the possible local rise in potential has to be reduced to an acceptable value. The only component on which it is possible to act in this respect is the linear resistance of the screen, as it can be demonstrated that the maximum value of the fault voltage is as follows: Vf ¼

LR If 4

where R ¼ linear resistance of the screen L ¼ length of the link If ¼ fault current This being, the value of R can be reduced by two methods, which may both be applied simultaneously: • paralleling of the HV cable screens between each other, • paralleling of all the HV cable screens with the ground wire. Such paralleling may be done in aboveground or in buried joint boxes.

4.5.6.3 Protection of the Workers Workers are particularly exposed to mechanical hazards (deep trenches, . . .) and electrical hazards (voltage step, . . .). During work in plain soil, the depth of the trench (for instance > 1.5 m) can be such that it needs stabilizing (lining). Furthermore, the workers must wear their individual protective equipment (hard hats, gloves, . . .). For other laying techniques such as in tunnel, bridge or shaft, various philosophies may be envisaged: • bar access and install fixed or mobile CCTV cameras inside, in order to verify the proper condition of the cables. Once the link installed, human interventions will be few and far between (only in case of repair or other). • authorize access, either after putting the HV link(s) out of service or if the links are left live, restricting the access to authorized persons only. In this case, particular systems have to be installed in the tunnel (ventilation, emergency hatches or exits,). In the event where there are other users of the tunnel, bridge, shaft who installed cables or pipelines in it, other collective protection equipment may be necessary depending on the type of cables and products involved. For example, steel sheets may be placed around the cables in order to protect them from external aggression

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(piercing by screwdrivers, . . .) or the cables may be placed inside ducts or concrete troughs in order to limit the impact of a defect on personnel or the installations of other utilities. Also, the case of prefabricated joint pits deep in the ground is similar to that in tunnels, except that the space is less. Therefore, particular measures for venting and extraction of possible toxic gases may be necessary, as well as provision of an extra exit hatch as a backup. The electrical risks must be considered also. We can mention the case of laying of pipe or another underground power link parallel to buried power links without any particular protective measures. When the cables of a portion of link are placed on insulating supports prior to backfilling the trench, there may appear a considerable voltage on the pipe which is dangerous to individuals working on the pipe or the new link. Local grounding during the work on the pipe is effective for protecting the workers from that type of impact. It should be also noted the accessible parts of pipes of third parties (valve control stations, cathodic protection stations, measurement stations, . . .) situated near HV links must be earthed in order to limit the induced voltages and so protect their personnel. Interventions in joints boxes must also be carefully considered on account of the considerable currents that may flow in these.

4.5.6.4 Protection of the Public As already mentioned, the cables are usually buried at such depth that a defect arising in them is not noticeable at the ground surface, except perhaps for a slight noise. At the joint boxes, an adequate and possibly strengthened grounding circuit enables to eliminate any electrical risk (step voltage, . . .) to the public. Although the joint boxes limit the mechanical impact of a defect on the outside, there remains the fact that a short-circuit may provoke an explosion generating such a pressure that no aboveground or buried boxes can resist. It may therefore be highly advisable that joint boxes be placed in a concrete or steel containment. 4.5.6.5 Safety of the Different Laying Techniques Among the 12 laying techniques described in this brochure, some are safer than others depending on which aspect the designer looks at. Globally, techniques where cables and joints are laid at a sufficient depth in the soil and completely protected (i.e. cable in duct, joints in jointbays) are the best ones. As soon as cables or joints are in open air, (i.e. cables laid in tunnel without protection, joints in manholes), the security of the public or the workers is at a lower level. More details are given in the previous chapters.

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Environment

Installation of power cables entails environmental impacts which depend on which installation method is applied. For instance, the results of techniques such as horizontal drilling or tunnel thrust jacking are practically ‘invisible’ to the outside world. Conversely, when trenches are dug (direct burial, ducts, tunnels built with the open cut method, etc.) the natural environment may be substantially altered. It is important not to underestimate the environmental impact during the construction itself, and therefore it is wise to consider it already at the preliminary study stage, before it becomes the main visible point for the population. The ultimate objective is to restore an environment identical to what it was before the installation of the HV link. In order to analyze the environmental effects arising from the construction and operation of a power link, a distinction is made, following the usual practice in this kind of studies, between the physical medium (soil, water, air), the biological medium (flora, fauna), the social medium (population, economic sectors, . . .) and the landscape. The potential alterations which may be attributed to the construction and operation of a power link, classified according to the element of the impacted, are as follows : • Soil • direct damage due to the excavations • deposition in the water (embedding) and/or land medium of the materials excavated from the trench • movements of plant and machinery on the banks of a river, for example for embedding and horizontal drilling • possible contamination of the soil (Fluid Filled cables) • Water • alteration of the water quality by materials or products during the construction work (embedding) • alteration of the water quality by pollutants (embedding, bentonite injected during horizontal drilling) • Air • release of pollutants to atmosphere during the construction work • noise generated by plant and machinery during the work • vibrations generated by plant and machinery during the work (tunnel, . . .) • generation of magnetic fields • Flora • direct destruction of the vegetation cover • indirect destruction of the nearby plant communities • damage to unique or interesting species • Fauna (embedding) • direct disturbances to benthic communities • indirect damage arising from changes to the water ecosystem

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• Socio-economic aspects • difficulties caused to parking and access to shops etc. during the work (direct burial, . . .) • temporary effects on tourism trade during the construction work • rights of way affected during the construction work • effects on fisheries (embedding) • Landscape • Alteration of the landscape during the construction phase. It clearly appears that most of the disturbances can be prevented or mitigated at the outset, i.e. during the studies. The use of particular installation techniques can also harm to the environment by propagation of polluted materials (for example, horizontal drilling going through a gas or oil pipe) but the major impact arises most of the time during the construction phase and can be mitigated by using, for instance, less disturbing plant and equipment (low noise, low vibration equipment or measures during digging of shafts) and by informing and consulting with the local authorities and population. However, it should be borne in mind that using SCFF cables may under certain accidental circumstances (leaks) cause some impact to the environment by the fluid leaking into the subsoil. Finally, it is worth noting that more and more international or local guidelines stipulate that the cables be removed at the end of their service life and that the materials be recycled.

4.6

Design of A Link

When an engineer is at the beginning of a new project, the problem is always : how could it be managed in order to be the most effective on the technical and economical points of view. The following chart will help the inexperienced engineer in the management of his project. If you are in an organization accustomed with the underground cable system project management, it is clear that some stages have to be jumped over. It can be seen that the exercise is very much an integrated process with the impact of the various stages being considered and steps taken to modify previous and subsequent stages of the process to achieve an optimized end result.

4.6.1

Methodology

(Figs. 4.74, 4.75, 4.76, 4.77, and 4.78)

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STAGE 1 : Preliminary design of the cable system

Operation voltage Ampacity (normal operation, emergency) Load curve Cable aim temperature during operation Short circuit level and duration Impulse levels Touch voltage Cost of kWh, cost of losses Estimated length of the link

Type of soil Soil temperature Maximum allowed temperature at soil-cable contact Soil resistivity Frost depth Environmental hazards (earthquake, flood,...)

Cable selection among existing cables Accessories selection among existing accessories Preliminary design of cable cross-section Design of earthing (grounding) method Determination of number of cables per phase

Need of a cooling system ?

Yes

New cable design

No

Stage 2

Fig. 4.74: Stage 1

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STAGE 2 : Preliminary cable route design In the global studied area Identification of obstacles to cross : Roads, railways,rivers, National parks, archeological sites, Thermal proximities (steam,...) Electrical proximities Services Trees

Division of the global studied area in sections

Local and national regulations

In each section

Allowed civil work techniques Allowed time of trench opening Location Right of way

Available civil work techniques in the country

Choice of options Route section / Possible techniques

Soil stability Soil hardness Soil resistivity Soil seismicity

Stage 3

Fig. 4.75 Stage 2

Identification of the possible civil work techniques in each section

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Stage 3 : Checking of the cable design

Stage 1

Stage 2

Identification of the sizing point (thermally speaking)

Modification of cable cross section Modification of earthing method Modification of cable architecture

Checking of the cable design

Is the ampacity still good ?

Yes

Stage 4

Fig. 4.76: Stage 3

No

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Stage 4 : Choice of options Route section / Civil work technique

Site "prejudice" Site duration Site working time (24 h/24 h possible) Magnetic field Laying depth Maintenance and repair process Cable removal

Construction cost Site prejudice cost Maintenance and repair cost Operation cost Link non availibility cost Repair cost

Choice of a technique for each section with cost and technique aspects

Stage 5

Fig. 4.77: Stage 4

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Stage 5 : Cable installation Stage 1 Laying technique Installation technique : rigid or flexible Pulling method Pulling tension Sidewall pressure Drum transportation

modification of the design Cable system performance Thermomechanical performance

Good

Choice of the cable Choice of the accessories Choice of the length on each drum

Final design of the cable Final design of the civil works Final design of the installation

Writing of link specifications

Administrative authorizations

Works

Final ampacity, according to works

Commissioning

Fig. 4.78 Stage 5

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339

Study cases

(Fig. 4.79) Let us assume that we have a new project to design: Join substation A to substation B. We will go through the flow chart to optimize the project. Stage 1 Preliminary Design of the Cable System Electrical Data Collection: Operation voltage: 225 kV, Ampacity: Normal: 800 A in winter and in summer, Emergency: 1000 A during 6 hours in winter and in summer, Cable aim temperature during • normal operation: 90
C, • emergency operation: 100
C, Short circuit level: 50 kA, 0.3 second, Impulse level: 1050 kVc, Estimated length of the link: 6 km, Allowed sheath voltage: 400 V. This information is only useful to determine how the link will be earthed: solid, single point or cross bonding. Civil Work Data Collection: Soil: mainly sandy clay, Soil resistivity: native soil: 1.2 K.m/W in winter, 1.6 K.m/W in summer, Available special backfill: 0.7 K.m/W in winter, 1.0 K.m/W in summer Soil temperature: 15
C in winter, 25
C in summer, Maximum allowed temperature at soil-cable contact: 55
C, Maximum allowed air temperature in bridge or in tunnel: 20
C in winter, 30
C in summer, Frost depth: 0.8 m, Environmental hazards: flood along the river, Cable Selection: From the cable temperatures, we have to choose an extruded cable and premolded joints. Preliminary design of cross-section cable: 1600 mm2 Al, 1 cable per phase with special backfill or 1600 mm2 Cu, 1 cable per phase, with native soil. No need of a cooling system Earthing method: cross bonding, coming from the allowed sheath voltage. Stage 2: Preliminary Cable Route Design Three main routes were found by the design team.

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Fig. 4.79 Possible routes

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They will be called Left (L), Central (C), Right (R) in all the study. Identification of obstacles to cross: Left: Private land, a river, 50 m wide and an area liable to flooding, 150 m wide, a national park, Central: Private streets, Narrow streets with low traffic, electrical cables in a street, crossing of a 225 kV existing link laid at 1.8 m deep, cross bonded, 1000 mm2 Cu, which ampacity is 900 A in winter, 770 A in summer, a bridge, a sloping hill, Public rural road, Right: Public streets, but with heavy traffic, numerous services in the urban streets but not in the rural road, a bridge, Public rural road, Available civil works techniques in the country where the link has to be built: all, Trench opening: 300 m at the same time in the city (urban streets), Working hours: not allowed at night in the city (urban streets). Civil Work Techniques Selection: From the collected data, some techniques are of no interest: Troughs and direct burial in urban areas, where the maximum allowed length to be opened is 300 m. The length between two joints is then too short to be costefficient. Division of the Route in Sections: The different routes can be divided in seven sections: urban streets, river, national park, hill, bridge, land, rural road. The following table identifies the possible civil work techniques in each section: Duct Direct burial Tunnel Trough Bridge Shaft

Street Y N Y N N Y

River N N Y N Y Y

National park Y Y Y Y N Y

Hill Y Y Y N N Y

Bridge Y N N Y Y N

Land Y Y Y N N Y

Road Y Y Y Y N Y

(continued)

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Horizontal drilling Pipe jacking Microtunnel Mechanical laying Embedding Use of existing structures

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Street Y Y Y N N Y

River Y Y N N Y N

National park Y Y Y Y N Y

Hill Y Y Y Y N Y

Bridge N N N N N Y

Land Y Y Y Y N Y

Road Y Y Y Y N Y

Stage 3: Checking of the Cable Design At this stage of the study, it is necessary to identify the sizing point. According to the collected data, the sizing point is the native soil with the bad resistivity. The cross section necessary to meet the ampacity requirement is 1600 mm2 Cu. This cable being of current manufacturing, nothing has to be changed in the cable architecture or in the type of soil to be used for the backfill. If it was decided to change the native soil by a special backfill, the sizing point will also change and become the two 225 kV links crossing. Stage 4: Choice of Options Route Section / Civil Work Technique The laying technique to adopt in each section depends on the cost structure in the country where the link has to be laid. Nevertheless, we propose an a priori choice without knowing in which country we are. • Private streets on route C: Duct filled with air, laid in special backfill at 2 m deep (bottom of the trench). It will be necessary to have a reinforced block to cross the 225 kV link, as the depth is less than the normally allowed one. • Public streets on route L: Tunnel. It was not allowed by the local authority to open trench in these streets, due to heavy traffic, • River: Horizontal drilling with native soil and water inside the duct. Max depth: 7 m under the river bed, • National park: Mechanical laying with native soil. Trench bottom at 1.7 m deep, • Hill: Direct burial with native soil. Trench bottom at 1.50 m deep, • Bridge: Ducts filled with air, • Land: duct laid in special backfill at 2 m deep as in the streets. • Rural road: Direct burial with special backfill. Trench bottom at 1.50 m deep. It must be noted that in case of native soil surrounding, the very vicinity of the cable is made of sand or special backfill to avoid direct contact with stones or other materials that could hurt the cable. The cables are systematically laid in trefoil formation, one cable per duct when any, except at the 225 kV link crossing where cables are in flat formation, to improve the heat diffusion, taking into account the mutual heating of the two links. Comments: In the sloping hill, direct burial could be preferable to duct as the installation will be considered as rigid and so, the creeping problem can be avoided.

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The width of the area liable to flooding is 150 m large. Microtunnel is not the best technique in this case as the maximum length is considered by experts to be around 100 m on the present site. The land section, in accordance with the private land owners, will be done with ducts. In private streets, the same technique will be applied (ducts), the only difference will be in the final layer, good soil for land and asphalt for streets. In the public streets, the tunnel has been chosen after discussions between utility and local authorities in order to limit traffic problems. In the national park, an important environmental impact study was realized by independent specialists and it concluded that it was possible to cross it. According to the type of soil, land, animals, flowers found in this park, the best solution was to use mechanical laying at a precise period (Fall for example). The main criteria that convinced the specialists were: speed of the works, narrow width, no big soil movements. With the different laying techniques encountered along the routes, transitions between rigid and flexible installation have to be designed. In particular, it could be reasonable in the bridge to fill the ducts with bentonite to avoid to change the installation technique from rigid, as the contiguous sections are envisaged with direct burial, to flexible with the unfilled ducts and so to keep the rigid one on three sections. Cable Checking:

Cable

Street or land 1600 Al

River 1600 Cu

National park 1600 Cu

Hill 1600 Cu

Bridge 800 Al

Tunnel 800 Al

Road 1600 Al

It is important to state that, along the route, we can have changes in the cable cross section, and so optimize the cable section, but it is not easy to joint two cable sections if the difference between cross sections is too important. As the length of our project is rather short, we decide to homogenize the cross section all along the route, with 1600 mm2 Cu. This approach would make the impact of the cables an invariant, but in real projects it could be a way to reduce the cost of links. A full optimization can give a reduction that could be up to 10 %. Time and Period to Complete the Site Another important aspect of the project is the time required to complete it. Of course, the administrative and design items need time but do not affect the inhabitants living along the routes. On the contrary, the required time to complete the civil works, the jointing and the period during when the works will be realized is of first importance for them. Some local authorities have strong demand on this specific point, so strong that it could determine the route or the laying technique that will be finally chosen by the project manager.

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On the left route, the specialists propose to cross the national park during the Fall season. We can also imagine that works on the central route can only be done during the Summer season when most of the inhabitants are on holidays, that is to say away from their houses, to be sure that the noise coming from the works will not hurt their ears. Cost of the Project, Comparison of the Different Routes: After the cable checking, you have to choose the final route among the three identified ones which respective lengths are 6 km for left route, 5 km for central route and 7 km for right route and then review the installation of the cable. For a better understanding, lengths of the different routes could be identical, but it is rarely the case in an actual project. As soon as you know the costs of the different items, you can calculate the overall cost and choose the best route. All the discussions with the local authorities are not recorded here, but they are necessary to officially finalize the route. It is necessary at this stage of the project to check the completion time. A line is dedicated to this specific point in the table so that the right decision could be taken before writing the tender. Each one can fill up Table 4.5 with the real costs of his/her country. With this example, we can see that it is not easy to say which route is the best one, according to the different criteria that can be used to establish the ranking. An analysis was done with French costs. Regarding these criteria, the left and the central routes are at the same price, slightly in favor of the central one, and the right one not far from twice. If we add the criteria the site completion time, the most favorable route becomes the left one. This analysis is only valid for France. It is of evidence that limitations due to administrative regulations, unknown in this study, can upset the technical and economical ranking shown here. To optimize the project, it is obvious that we won’t change the cable section at each new route section. One or two changes are possible but not more. Depending on the route that will be chosen, an optimization is then necessary, the place of the manholes being for example one of the problems. As a conclusion, we have to underline that: • It is necessary to follow up the different stages of the process as described in the flow chart, (see Sect. 4.6.1), • It is important to be open minded at the beginning of a new project to study all possible solutions. It is clear that some will fall as soon as the designer gets new constraints. • The shortest route is not always the cheapest route and that savings can be done by using other routes or innovative laying techniques.

Length (m) 450 400 150 5 000

800 2 500 100 400 200 1 000

1 200 200 600 5 000

L1-L2 L4-L5 L2-L3 L3-L4

C1-C2 C5-C6 C3-C4 C2-C3 C4-C5 C6-C7

R1-R2 R3-R4 R2-R3 R–R5

Site duration (Months) Total length (m) Total route cost

Section Land Land River National Park Left route cost Private street Hill Bridge Road Road Road Central route cost Public Street Bridge Road Road Right route cost

Table 4.5 Route cost

6 000

5 000

7 000

Right

Duct Direct burial Duct Direct burial Direct burial Direct burial

Laying technique Type Linear cost Duct Duct Horiz.Drilling Mecha.Laying

Route

Central

Section cost

Tunnel Duct Direct burial Direct burial Left

Linear cost

1 600 Cu 1 600 Cu 1 600 Cu 1 600 Cu

1 600 Cu 1 600 Cu 1 600 Cu 1 600 Cu 1 600 Cu 1 600 Cu

Cable Type 1 600 Cu 1 600 Cu 1 600 Cu 1 600 Cu Section cost

Total cost

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Glossary

Throughout this chapter, the terms have to be considered as follows: The term “construction techniques” is considered as relating to the techniques used to create the cable route, mainly covering the civil works such as trenching. Likewise, the term “installation techniques” is considered to relate to the cable system design and cable installation methods. Cable design issues associated with the laying and installation techniques have also been considered under the general subject of “Installation Techniques”. The cable installation was then the rest: the pulling and backfilling, the fixing when laid in open air. • Pipe Jacking: This technique consists in pushing into the soil prefabricated tubes having the exact diameter of the final tube. The tubes are pushed from a work shaft. As the pipe jacking progresses the earth works are done, either manually or mechanically, according to the requested diameter. The first tube is equipped with a steel drum curb which bites into the subsoil while protecting the site workers clearing the earth. This technique concerns diameters between 1000 and 3200 mm. • Microtunnel: This technique consists in pushing in the subsoil prefabricated tubes having the exact diameter of the final tube. They are pushed from a work shaft. The earth works are systematically mechanized: a microtunneller is put in front of the tubes. This remote controlled machine can dig small diameter pipe jacking horizontally. By using the microtunneller tubes of a diameter between 300 mm and 1200 mm can be put in place. • Shaft: Vertical circular or rectangular excavation from which the tubes are pushed. Shafts are also vertical excavations from a generator to a substation in hydroelectric plant. • Horizontal Drilling: Directly issued from oil drilling techniques, horizontal drilling is carried under rivers beds, railway tracks, motorways,..., and is composed of four phases : drilling of the pilot hole from the bank for rivers or from one side for motorways or railways tracks, casing the pilot hole, boring and pulling and laying of the final tubes. Direct drilling is another word that is used in some countries to design the same technique.

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• Embedding: This technique consists of excavating a riverbed, from a barge or with an amphibious machine, burying a tube or cables and filling up the trench. • Use of Existing Structures: Sometimes, it is possible to use some existing structures, like water, gas or old fluid-fluid tubes, to put High Voltage extruded cables inside of them. • Bridges: The cables can be put in rail or road infrastructures. They can be placed in or outside bridges structures. This avoids other techniques which remain costly and can be difficult to accomplish. • Mechanical Laying: This technique, entirely mechanical, consists in excavating a trench, and burying the cables simultaneously in a continuous progression. • Trench Excavation in which the cables are buried. Trench

Backfill

Cable or duct

Bedding material

• Bedding Material: Material which can be put at the bottom of the trench under the cables, the troughs or the ducts.

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• Backfill: Material used to fill up the trench. • Duct: Tube in PVC, PE, concrete, steel, etc.. in which high voltage cables are pulled. • Pipe: Tube used for some laying techniques, i.e. pipe jacking, microtunnelling,. . .to open a hole in the soil for the underground link. Cables are not pulled directly in the pipes ; Usually, ducts are pulled in the pipes, and cables pulled in the ducts. • Trough: Prefabricated concrete element, placed at the bottom of the trench, in which high voltage cables are laid. • Cable Removal: Action of removing the cables at the end of their operation. • Right of Way: High voltage cables are installed in Public or private areas. In these two cases, the electrical company has to obtain a “right of way” which allows to excavate a trench, to bury high voltage cables and operate the underground line. • Rigid Installation: in a rigid system, the cable is held in such a manner that virtually no lateral movement occurs and the cable absorbs the thermal expansion by developing a high internal compressive force. To ensure a satisfactory performance, the cable must not buckle under this force giving rise to severe local sheath strains. • Flexible Installation: in a flexible system, the cable is held in such a manner that the expansion movement does not cause excessive strain in any of the cable components and hence a short fatigue life. The basic principle of flexible systems is that the thermal expansion and contraction are absorbed by movements of the cable at right angles to the longitudinal axis of the cable.

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• Caterpillar or Hauling Machine: pulling or pushing machine used for the installation of cables. The cable passes between two caterpillars and is belt-driven or braked by rubbing. They are frequently used in conjunction with cable rollers for the installation for cables in trenches, troughs and on bridges. Motorized rollers can be used to assist in the installation of cables around bends. When installing a cable down a steep tunnel, a braking caterpillar is used to prevent the cable from running away down the slope. In addition, braking rollers can be used to hold back the cable from running away on steep inclines. caterpillar

cable

• Manhole Visitable bay where joints are laid. Usually, a manhole has two covers that allow the workers to enter in. • Joint Bay Non visitable bay where joints are laid. Usually, these bays are backfilled after joint completion. Yves Maugain has spent all his career building the electrical Transmission System (63-400 kV) in France and abroad alternating between design positions and construction sites. After his MSc and some additional degrees in Civil engineering, he started within EDF in the area of underground substations, moved to overhead lines and then underground lines. He then went to asset management and finally prepared the connection to the grid of all new EDF power plants in the world addressing the technical and regulatory issues. He retired from EDF in 2017. He is an active member of CIGRE and acted as Convener for WG 21.17 on Cable laying in 1996. In 2000, he became Secretary of SC B1 on Insulated Cables and in 2012 Secretary of the Technical Council. He received the CIGRE Technical Committee Award in 2002, Distinguished Member in 2010, Honorary Member of CIGRE in 2018 and CIGRE fellow in 2021.

5

Recommendations for Mechanical Testing of Submarine Cables (and Their Accessories) Marc Jeroense

Contents 5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.2 Terms of Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.3 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Mechanical Handling of Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.1 Risk of Mechanical Damage During a Cable’s Life Cycle . . . . . . . . . . . . . . . . . . . . . . 5.3.2 Submarine Cable Loading and Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3 Submarine Cable Laying . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3.1 Typical Installation Sequence with Shore Landing . . . . . . . . . . . . . . . . . . . . 5.3.3.2 Installation at Offshore Platforms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3.3 Vessel and Machines Positioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3.4 Remotely Operated Vehicle (ROV) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3.5 Laying of Bundled Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.3.6 Fatigue During Installation and Jointing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4 Submarine Cable Protection Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.1 Route Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.2 Choosing of Cable Route and Protection Techniques . . . . . . . . . . . . . . . . 5.3.4.3 Ploughing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.4 Water Jetting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.5 Vertical Injector (Jetting Assisted Plough) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.6 Trenching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.7 Pipes at Landings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.8 Excavation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.9 Pre-Sweeping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.10 Rock Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.11 Mattress Coverings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.12 Split-Pipe Articulated Cable Protectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.13 Other Complementary Protection Techniques . . . . . . . . . . . . . . . . . . . . . . . . 5.3.4.14 Protection of Cables at Crossings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

354 354 355 356 356 359 359 361 363 363 365 367 367 368 368 370 370 370 371 372 373 374 374 375 375 375 376 377 377 377

M. Jeroense (*) Marcable Consulting, Karlskrona, Sweden e-mail: [email protected] © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_5

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5.3.5 Submarine Cable Operation and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.5.1 Possible Hazards for Cables in Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.5.2 Vortex-Induced Vibrations, Strumming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.5.3 Thermal Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.5.4 Repeated Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.5.5 Abrasion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.6 Submarine Cable Repair . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.7 Dynamic Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.7.1 Extreme Load Effect and Fatigue Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.7.2 Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4 General aspect of mechanical testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.1 Summary of Type Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.1.1 Static Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.1.2 Dynamic Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.2 Test Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.3 Characteristics of Cable Design/Installation Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.4 Test Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.4.1 Water Depth 0–500 m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.4.2 Water Depth >500 m or When Dynamic Vessel Characteristics Are Known . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5 Type Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1 Coiling Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1.4 Requirements/Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2 Tensile Bending Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.2.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.3 Pressure and Water Penetration Tests on Paper Lapped Cable Types . . . . . . . . . . . 5.5.3.1 External Water Pressure Tests: Mass-Impregnated Cables . . . . . . . . . . . . 5.5.3.2 External Water Pressure Tests: Oil-Filled Cables . . . . . . . . . . . . . . . . . . . . . . 5.5.3.3 Internal Pressure Withstand Test: Oil-filled Cables . . . . . . . . . . . . . . . . . . . . 5.5.4 Pressure and Water Penetration Tests on Extruded Cable Types . . . . . . . . . . . . . . . . 5.5.4.1 Radial Water Penetration Test: Rigid Joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.4.2 Radial Water Penetration Test: Factory Joint and Cable . . . . . . . . . . . . . . . 5.5.4.3 Conductor Water Penetration Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.4.4 Metal Sheath Water Penetration Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.5 Tensile Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.5.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.5.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.5.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.5.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.6 Full Scale Fatigue Test: Dynamic Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.6.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.6.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.6.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.6.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6 Project Specific Tests and Special Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2 Bending Test Without Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

378 378 378 379 380 380 381 383 383 385 386 386 387 388 390 390 390 391 391 393 393 393 393 395 395 396 396 397 397 399 399 399 400 401 402 402 402 403 403 403 403 404 404 404 405 405 405 405 406 406 406 408

5

Recommendations for Mechanical Testing of Submarine Cables (and Their. . .

5.6.2.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3 Crush Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.4 Crush Test for Long-Term Stacking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.4.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.4.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.4.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.4.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.5 Sidewall Force Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.5.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.5.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.5.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.5.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.6 Impact Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.6.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.6.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.6.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.6.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.7 Pulling Stocking Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.7.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.7.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.7.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.7.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.8 Handling Test for Rigid Joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.8.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.8.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.8.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.8.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.9 Sea Trial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.9.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.9.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.9.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.9.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.10 Tensile Characterization Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.10.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.10.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.10.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.10.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.11 Friction Coefficient Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.11.1 Purpose/Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.11.2 Preparations/Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.11.3 Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.11.4 Discussion/Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography/References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

353

408 408 408 408 408 408 409 410 410 410 410 410 411 411 411 411 413 413 414 414 414 414 415 416 416 416 417 417 417 417 417 417 418 418 418 418 419 419 419 419 419 420 420 421 421 421 422 422 422 422

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5.1

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Introduction

This chapter, which reproduces CIGRE TB 623 published by WG B1.43, convened by Marc Jeroense from Sweden, is divided into two principal parts: one part describes the general background of mechanical handling of cables throughout the life cycle and the general aspects of testing in relation to handling (Sects. 5.3 and 5.4); the other part describes the tests that are recommended or may be performed (Sects. 5.5 and 5.6).

5.1.1

Background

Several documents concerning recommendations for tests on submarine cables have been issued over the years under the responsibility of the CIGRE Study Committee B1. In 1980 the document titled “Recommendations for mechanical tests on sub-marine cables” was published in Electra No 68 (ELECTRA 68 1980). The field of application was defined as a rated voltage U0 of higher than 36 kV AC or 100 kV DC. It was also stated that the recommendations were primarily meant for single or three-core paper-insulated cables for AC voltages. For DC cables it was mentioned that the reader should refer to the CIGRE document as published in Electra No 32, 1974 (ELECTRA 32 1974). This document describes the test procedures for DC cables. The reference to the mechanical tests was very briefly confined in a note: “Note: in the case of submarine cables, special mechanical tests may be agreed upon.” After 1980, several deep sea and large submarine cable links were installed and as a consequence the experience of cable installations was increased. At that time, it was recognized that the computed test forces according to the Electra No 68 differed in some cases from the actual tension during laying and recovery. For these reasons the SC 21 (as the SC B1 was named at that time) decided in the Sydney meeting in 1993 to revise the recommendations. The work was done in the WG 21.02 and resulted in the document published in the Electra No. 171 article in April 1997 (ELECTRA 171 1997), titled “Recommendations for mechanical tests on sub-marine cables.” The field of applications in terms of voltages remained the same, although the limitation to paper-insulated cables was removed in this version. And the use of the recommendations for both AC and DC cables was explicitly stated. The number and scope of submarine cable installations has increased ever since and it is expected to increase even more in the future. It was also judged that the application areas are diversifying (offshore wind farms, floating platforms, etc.) and that the maximum installation depth is also increasing. These facts were recognized by SC B1 during the late 2000’s, subsequently initiating preparation of terms of reference for a new WG to update the Electra No. 171 document. Preparation of the terms of reference for the new WG was carried out by a Task Force within WG B1.27 and resulted in WG B1.43 being set up.

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The technical brochure 623, reproduced in this chapter is a result of the work of WG B1.43. The TB is divided into two parts, a descriptive part and a test part. The descriptive part aims to give the reader some basic background information. For further reading the TB 610 from WG B1.40 titled “Offshore generation cable connections” (CIGRE TB 610 2015) is recommended. The test part has revised the tests recommended by the Electra 171 document, makes references to the TB 490 for certain tests on extruded cables and proposes a set of tests for special projects and for information purposes.

5.1.2

Terms of Reference

Within the Working Group B1.27 “Recommendations for testing of long AC submarine cables with extruded insulation for system voltages above 30(36) to 500(550) kV” (CIGRE TB 490 2012), the Terms of Reference of the WG B1.43 that resulted in this chapter were defined. These Terms of Reference were as outlined below and it is the conclusion of Working Group B1.43 that all issues have been covered by the technical brochure reproduced in this chapter. Terms of Reference: 1. Cover both impregnated paper cables and extruded cables (AC and DC) including a review of cable installation methods and cable protection for submarine cables 2. Examination of relevant IEC standards, CIGRE recommendations, and standards from the offshore industry (e.g., umbilical testing) 3. Assess the risk for mechanical damage during installation and cable protection 4. Assess the risk for mechanical damage after installation (anchoring, drag-net fishing, pile driving) 5. Calculation of tensile tests to be updated and a more detailed background to be described to the selected factors (security factors and torsion as well as dynamic forces) 6. Propose test methods to cover: a. Dynamic cable system installations b. Very deep sea installations (including extruded cables) c. Impact tests 7. Consider the heat cycling influence on the metallic sheath and evaluate possible test methods 8. Update/introduce mechanical tests for rigid joints 9. Consider tests with for free-spans, strumming 10. Consider tests for the cable interaction with, for example, J-tubes and bend restrictors

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The WG should not specifically consider umbilicals but should look in general at umbilical power cables.

5.1.3

Scope

This technical brochure applies to cable systems intended for use in AC and DC power transmission systems with rated voltages above 30 (36) kV AC or 60 kV DC. It is the opinion of the WG that the TB can be used even for voltages down to 6 (10) kV AC or 10 kV DC. The technical brochure is applicable for extruded cable systems, MI cable systems and fluid-filled cable systems. The brochure has not been written specifically for gas-filled cables, although it cannot be stated that all or certain parts of the brochure are non-applicable in that case.

5.2

Definitions

In this section definitions of some commonly used terminology are provided and are in agreement with TB490, “Recommendations for testing of long AC submarine cables with extruded insulation for system voltage above 30 (36) to 500 (550) kV” (CIGRE TB 490 2012). Test definitions are also in agreement with IEC 60840 (IEC 60840 2020) and IEC 62067 (IEC 62067 2022). Submarine Cable System An AC or DC, HVor EHV submarine cable system may consist of submarine cable(s), termination(s), and different type of joints. Dynamic Cable Cable designed for dynamic loads during the operational life of the cable. The dynamic loads result directly or indirectly from wind, waves, and current. A dynamic cable is designed to ensure that the cable has sufficient fatigue life. Typically, a dynamic cable is hanging from a host facility down to the seabed. Static Cable Cable designed for static application after installation. The loads induced by wind, waves, and current will not introduce significant dynamic response in a static cable during operation. Factory Joint A factory joint is manufactured prior to the armoring operation so that the section of cable containing the joint is continuously armored without any discontinuity of the armor wires in the vicinity of the joint. The factory joint is generally fully flexible with the same handling restrictions as the original cable. Field Joint A field joint is a joint made on board a cable laying vessel or barge or in the beach area, between cable lengths which have been armored. They are generally used to connect two delivery lengths offshore. The design principles of field joints are the same as for repair joints and are treated as such.

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Repair Joint A repair joint is a joint between cable lengths that have been armored. They can be used for repairing a damaged submarine cable or for jointing two delivery lengths offshore or in the factory. A repair joint can be either flexible or rigid. Flexible Joint A flexible joint can be handled with the ordinary cable handling machinery and has the same limitations on bending radius and tension as the cable. Flexible Joint with Some Mechanical Restrictions A joint that can be bent to the same or greater bending radius as the cable and/or with reduced tension. Rigid Joint A rigid joint is a joint between two cable lengths that have been armored. The rigid joint is normally performed as a field joint. The rigid joint cannot undergo bending and cannot be handled with the ordinary cable handling machinery. It must be deployed with special equipment such as a crane or similar. Bend stiffeners or bend restrictors are normally used to protect the cable from over bending at the interface to the rigid joint housing. Internal Design of Joint Whether the joint is rigid or flexible, single-core or threecore, it has an electrical function based on the design principles of transferring the current, of controlling and withstanding the electrical stresses, of screening the joint electrically and protecting the insulation system from moisture ingress. These design principles are attributed to the internal design of the joint. External Design of Joint Whether the joint is rigid or flexible, single-core or three-core, it has a mechanical function based on the design principles of withstanding the impact from the surroundings, of withstanding (in some designs) the mechanical bending, and of withstanding the mechanical tension and torsion during laying and operation. These design principles are attributed to the external design of the joint. Manufactured Length A manufactured length is a complete production run or a part thereof. It normally does not contain any factory joints, but during a failure in routine testing, a factory joint may be part of the manufactured length. A manufactured length has normally not any armor but may contain armor. Delivery Length A delivery length may be one or more manufactured lengths joined with factory joints. A delivery length is typically the intended shipping length of the submarine cable. Long Length The definition of what constitutes a “Long” length is somewhat subjective. In general, underground cables are supplied on individual delivery lengths of a thousand meters, which are easily transportable. The manufactured or delivery lengths of submarine cables can be more than one hundred kilometers, which are beyond the capacity of individual transportable drums. They are

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commonly moved from the factory production line directly onto a very large turntable outside the factory, or onto a cable laying vessel. The considerably greater manufactured or delivery lengths of submarine cables imposes a range of practical difficulties on the testing of such submarine cables in accordance with current IEC standards for HV and EHV underground cables. For the purposes of this document, a “long” length is considered to be: • A cable delivery length which includes one or more factory joints, or • A cable delivery length for which the electrical characteristics make the carrying out of high voltage tests and partial discharge tests strictly in accordance with IEC 60840 (IEC 60840 2020)/IEC 62067 (IEC 62067 2022)/IEC 60885-3 (IEC 60885-3 2015) impractical in factory test facilities or on site, or • A cable delivery length which cannot be accommodated on an individual transportable drum suitable for moving around the factory to the appropriate test facilities Routine Tests Tests made by the manufacturer on all manufactured components (length of cable or accessory) to check that the component meets the specified requirements. Sample Tests Tests made by the manufacturer on samples of complete cable or components taken from a complete cable or accessory, at a specified frequency, so as to verify that the finished product meets the specified requirements. Type Tests Tests made before supplying on a general commercial basis a type of submarine cable system in order to demonstrate satisfactory performance characteristics to meet the intended application. Once successfully completed, these tests need not be repeated, unless changes are made in the cable or accessory with respect to materials or design or manufacturing process, which might change the performance characteristics. Project Specific Tests and Special Tests Tests that may be performed, if experienced design values are exceeded or there are changes in the conditions related to for instance handling, installation or operation that are not covered by the type tests. The tests can also be a characterization test, which is performed to measure specific properties of the cable system. The results of the characterization test are used for engineering purposes and are not subjected to acceptance criteria. Factory Acceptance Test (FAT) Tests made by the manufacturer on the completed cable to check that each length meets the specified requirements. These tests are often carried out in the presence of the customer. Electrical Tests After Installation Tests made to demonstrate the integrity of the cable system as installed.

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Significant Wave Height, Hs Parameter used to describe the wave height in a stationary irregular sea state. Traditionally defined as the average wave height (trough to crest) of the highest third of the waves.

5.3

Mechanical Handling of Submarine Cables

In this section general information and recommendations are supplied on typical loading, transport, laying, protection, operation, and repair. This information serves as an introduction to the physical effects and parameters for the testing and calculation parts of this chapter. Cable parameters like maximum pulling tension, minimum bending radius, minimum coiling height and diameter, maximum sidewall pressure, and maximum crush force must not be exceeded. In the following Table 5.1 typical mechanical forces and other factors that apply to submarine cable are listed. It is important to note that the phenomena mentioned in Table 5.1 are not necessarily a threat to the cable system, as it may already have been considered in the design of the cable system, in the installation methods, and in the protection system adopted.

5.3.1

Risk of Mechanical Damage During a Cable’s Life Cycle

Generally cables undergo a significant amount of mechanical handling during production, loading onto a cable vessel, laying, protection, operation, and finally potential recovery and repair. Damage to cables can occur at all stages of a cable systems life cycle: • Damages during installation are typically caused by mishandling, for instance due to break down of machinery or due to bad weather. • Damage that occurs before the cable goes into service is generally less critical, yet can be very costly. • Damage that occurs during active service is the most critical, because it is more expensive to repair and it affects system availability. The simplest way of installing submarine cables is to lay the cables on the seabed. This method leaves the cables unprotected against third party damage which is an acceptable risk if the probability and consequences of damage are low. The issue of third-party damage to cables is extensively discussed in CIGRE Technical Brochure TB 398 (CIGRE TB 398 2009). TB 398 concludes that failure statistics demonstrate

5.6.6 5.3.3.6, 5.5.6

Impact (mechanical, external)

5.6.11 5.3.5.3, 5.3.7.2 5.3.4.7, 5.3.4.14, 5.3.5.5, 5.3.7.2 5.3.5.3

5.3.3.3

5.3.2

Thermal fatigue

Kinks / minimum bottom tension

High or low temperature

Corrosion

Creep

Friction

Abrasion (sharp point, sand/water, during friction, tug boat lines)

5.3.5.5

5.6.5

Sidewall force

Bending fatigue

5.6.3, 5.6.4

5.5.2 5.5.3, 5.5.4 5.5.4 5.5.5, 5.6.10 5.6.2

5.5.1

Reference in this technical brochure

Crush (radial squeeze), short term or long term

Bending without tension

Tensile force

Longitudinal water penetration

Radial water pressure/penetration

Tensile bending

MECHANICAL PHENOMENON Torsion (e.g. during coiling and laying)

Loading and/or storage X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

Shore landing and entrance to platform X

Main cable lay with laying equipment

X

X

X

Movement of vessel when laying is stopped X

X

X

X

X

X

X

Cable protection and crossings X

X

X

X

Entrance to platform X

X

X

Anchors / fishing X

X

X

Cables with free spans X

X

X

Crossings X

X

X

X

X

X

X

X

X

Cable in normal operation

OPERATION

X

X

Movement of cable induced by wave or current

INSTALLATION Movement of seabed X

X

Dynamic cable X

X

X

X

X

X

X

X

X

Ice and earthquake X

X

X

X

X

Pull up X

X

X

X

X

X

X

REPAIR

X

X

Uncovering

LOADING

X

X

X

X

X

X

X

Movement of vessel during repair

Table 5.1 Informative overview over mechanical phenomena and their occurrence

Laying of repair joints X

X

X

X

X

X

X

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that the risk of third party mechanical damage is three to five times higher than the risk of internal failures. This alone may make it necessary to protect the submarine cables. For lower voltages and/or in sheltered areas it is possible that, based on a cost/risk analysis, less protection may be acceptable. A typical way of protecting submarine cable is to cover the cables. This may be done in soft soils by post lay jetting or in harder seabed materials by installing the cable in a pre-excavated trench. Naturally a narrow trench will yield a higher level of protection than a wide open trench. This is also true for jetting, but note that jetting may also leave the cable unprotected if the soil is blown away by high water pressure. Other methods are also used such as ploughing, vertical injection, concrete mattresses, rock placement, sand bags, steel/HDPE pipes, or split-pipe mechanical protectors, and many more. However, they all have the same purpose of protecting the cables from third parties and the environment, in the form of a cover. As described in CIGRE Technical Brochure TB 379 (CIGRE TB 379 2009), the annual failure rate for submarine cables is significantly lower compared to underground cables. However, the repair of submarine cables is significantly more costly and time consuming. A typical failure on a submarine cable system can take weeks up to months to repair, while a failure on an underground cable can be handled in the order of days or weeks.

5.3.2

Submarine Cable Loading and Transportation

Submarine cables are loaded on turntables, normal or extra size drums, or coiling basket/tanks using roller ways and a linear machine or a capstan wheel. Transportation is done by a vessel, a barge, a train, or sometimes on truck. Sometimes an additional intermediate transport by a barge, cargo vessel, or train is needed, for example, between cable factory and harbor or laying site. Before loading and transportation it is recommended to carefully study all mechanical parameters of the operations together with the cable information. Mechanical parameters are typically tensile force, tensile force with bending, sidewall pressure, bending radii, crush forces (height of stacking and caterpillar design), torsion, and temperature. The duration and number of cable handlings shall be taken into account. The cable information is for example cable type, cable length, cable diameter, cable weight, and minimum bending radii. Low temperatures may increase bending stiffness or cause cracking of bitumen layers of the cable. High temperature may cause melting and sweating of bitumen, particularly in tropical climates. In order to connect the cable to a pulling rope or wire, pulling heads or woven grips are installed at the cable ends. This has to be designed according to the required pulling forces expected in the following loading and installation processes. Figures 5.1 and 5.2 show examples of operations related to intermediate transport.

362 Fig. 5.1 Coiling of cables on a train set

Fig. 5.2 Storing cable on a turntable placed on a vessel

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363

Submarine Cable Laying

The laying of the submarine cables is one of the most significant steps in the installation of submarine cables.

5.3.3.1 Typical Installation Sequence with Shore Landing Table 5.2 and Fig. 5.3 illustrate a typical installation sequence of a submarine cable from shore to shore, where both ends of the cable are pulled into a pipe at the shore landings. Table 5.2 Typical installation of submarine cable from shore to shore FIRST LANDING POINT Phase 1: Cable laying vessel is positioned close to the first landing point with cable pay-out side facing to shoreline. The pulling wire is pulled through a pipe and connected to the cable head. The connection may be done at the vessel if vessel is near the outer end of the pipe. Alternatively if the vessel is further away the cable head may be floated close to the outer end of the pipe for connection to the pulling wire. The cable is pulled through the pipe by a winch on-shore to the final position. Helper caterpillars may be used in case of long on-shore trench. During the pulling operation the cable is paid out from the vessel. If necessary the cable may be put on floats between the vessel and the pipe. CABLE MAIN LAYING Phase 2: The vessel moves along the cable route while the cable is paid out and laid on the seabed.

CABLE MAIN LAYING

The cable is paid out under tension control and speed is adjusted considering various parameters. The vessel position during installation operations is typically controlled by a DGPS system SECOND LANDING POINT Phase 3: The vessel is arriving at the final landing point while laying the submarine cable. Close to the landing point the vessel turns around and stops as close as possible to the outer end of the pipe. The exact quantity of cable needed to reach the final position is defined. The length is measured on the cable on board. This amount of cable is paid out from the vessel, floated and arranged in suitable manner by boats and divers.

(continued)

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Table 5.2 (continued) Phase 4: The cable head is connected to a pre-installed wire at the outer end of the pipe. The cable is pulled by a winch through the pipe to the final position. Excessive bending have to be avoided.

Phase 5: All floats are removed by divers starting from the main cable lay side of the cable. At the same time the cable is kept tight by the winch.

Fig. 5.3 Submarine cable carried on floats from the cable laying vessel to shore

In case of a trenched installation at the first landing point the cable head is typically fed from the vessel, put on floats and pulled to the shoreline by a boat. At the shoreline the cable head is connected to a wire and the cable is pulled onto shore to the final position by a winch. The floats are then removed by divers, starting from the shoreline. After removal of all floats, the cable main laying may commence. At the second landing point, the sequence is typically according to Table 5.2, Phase 3–5, except that the cable head is pulled to the shoreline instead of the outer end of the pipe. When the route length is too long compared to the load capacity of the cable laying vessel or for example when the cable type is changed from deep water cable to shallow water cable, it is necessary to leave the cable end on the seabed for later

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recovery and for an offshore jointing operation. The cable jointing is typically made like an in-line joint or as an omega joint (also see Sect. 5.3.6).

5.3.3.2 Installation at Offshore Platforms Offshore platforms (see Figs. 5.4 and 5.5) with fixed foundations are usually equipped with J-tubes or I-Tubes. The tube is made of steel or polymeric materials, reaching from the seabed up to the platform deck. The tube is open at the top and has a bell-mouth at the bottom end in order to guide the cable from the seabed into the tube. A J-tube normally ends close to the sea bed level. It can also be partly buried to match the bottom of a cable trench and be able to facilitate cable entrance. It can also be extended prior to the installation of platform scour protection, permitting the cable to run under the scour protection and therefore providing enhanced protection against possible impact damage from dropped objects and permitting pull-in of cable at a later stage. I-tubes end a few meters above the sea bottom and the cable makes a gentle curve from vertical orientation in the I-tube to horizontal orientation in sea bottom. Tubeless hang-offs are also possible when attaching cables to platforms with fixed foundations. This facilitates ease of pulling in the cables and needs suitable cable protection systems to reduce dynamic stress during service life of the cable. During installation the first cable end is pulled through a pipe with a steel wire and a winch. The winch is located on the offshore structure above the tube or on the cable Fig. 5.4 Illustration of a transformer platform with J-tube connections for submarine cables

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Fig. 5.5 Illustration showing a number of J-tubes

laying vessel. Depending on water depth and sea bottom soil conditions, the cable end can be also be laid on the seabed in an omega or S loop near the bell-mouth, prior to the pull-in. During the pulling operation the cable is typically paid out from a cable laying vessel appropriately positioned near the offshore structure. Monitoring of the bottom bell-mouth during the pull-in operation is recommended. At the bottom end of the tube bend restrictors may be installed to restrict excessive bending and/or strumming of the cable. 5.3.3.2.1 Pull-In Head The pull-in head is a device used for terminating the end of a cable so that it can be loaded/offloaded from a vessel and pulled through an HDD, I- or J-tube. The pull-in head is designed to withstand installation loads, such as: • Tension during lay-down and pull-in (including increase in tension due to friction within the I- or J-tube) • Bending over chute/laying wheel, entrance to I- or J-tube and within J-tube The size of the pull-in head is designed based on the topside interface envelope (size of I-tube, J-tube, bends, landfall, etc.). Available space within the platform during pull-in has to be considered when deciding the length of the pull-in head. A pull-in head contains and protects the cable power cores which are sealed against water ingress. The pull-in head is temporary and is removed after the pull-in operation. The pull-in head is connected to the cable armor wires, through welding, molding, or clamping.

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5.3.3.2.2 Hang-off The hang-off assembly transfers cable loads to the platform structure. This is achieved by termination of load bearing elements (armor wires) in a strain termination (bounding epoxy mold, welded termination or clamping of armor wires). The loads are transferred from this anchor block to the platform structure via a split flange. For dynamic riser applications, the hang-off assembly is designed for the load variations given in the dynamic analysis. For static applications, the hang-off is designed to handle the service load.

5.3.3.3 Vessel and Machines Positioning Most cable laying vessels are equipped with Differential Global Positioning System (DGPS) which provides good positioning accuracy. Additional accuracy in cable laying is achieved if the cable laying vessel is equipped with a dynamic positioning (DP) system. Using information obtained from DGPS, the DP system moves vessel along the predefined route and keeps vessel in the given position and on the defined heading even if there are disturbing forces from wind, current, and wave action. Many cable installations have been done using vessels and barges with tugboats without a DP system, particularly in MV applications and in long cable landings where the sea bed is shallow and affected by tide. In these cases the cable laying vessel or barge may be kept in position with warp anchors or with hydraulic jacks. For non-torque balanced cables, for example, single armored cables, it is important at all times during laying to control the minimum bottom tension to avoid formation of loops and kinks. Therefore, it is important to control the vessel movement in relation to the pay-out speed of the submarine cable. The maximum bottom tension should not be too large in order to facilitate post lay protection such as jetting and to minimize free spans. 5.3.3.4 Remotely Operated Vehicle (ROV) The most common use of ROVs is for touch down monitoring during laying. Monitoring by ROV may be preferred in situations such as: • Irregular/uneven morphology of the seabed, which requires a visual check of the touch down distance in order to control the residual tension and in order to avoid free spans. • Cable laying along steep sections • Cable laying at crossings with other in-service utilities • Cable laying in deep water, where the laying angle from vertical is close to zero and laying tensions are high If an ROV is used for touchdown monitoring, it is possible to stop, recover the cable and re-lay it in a more preferable location, if necessary due to unforeseen bottom conditions being unacceptable.

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5.3.3.5 Laying of Bundled Cables Depending on installation constraints and system design, two or more submarine cables can be laid simultaneously in a bundled configuration (Fig. 5.6). A typical situation is to install the fiber optic cable bundled to a power cable or laying two cable poles in an HVDC bipolar system. Typically, for a bundled lay a multiple set of cable storage and handling equipment is required, depending on the number of cables to be bundled. The cables run from their storage tanks to the ship pay-out area and before entering the laying sheave or wheel, they are guided into a bundle. They are fixed together by wrapping ropes, tapes, or plastic straps. Accurate speed and tension control is required for each cable to ensure that the same lengths of the different cables in the bundle are paid off and no differential movement/stresses arise. Since the different cables may have a different diameter and weight per meter their elongation under tension might be different. For that reason a theoretical study is recommended to ensure that the length difference of the cables after their relaxation on the sea bottom will not create loops or twists due to trapped mechanical constraints between them. Here care needs to be taken for non-torque balanced cables, for example, single armored cables (Fig. 5.6).

5.3.3.6 Fatigue During Installation and Jointing During a jointing operation or during a temporary halt during laying the cable will be exposed to repeated bending cycles, primarily due to wave induced ship movements. This variation in cable curvature will result in cyclic strain variations in the cable components which can result in fatigue damage. Of the metallic components in a high voltage power cable the lead sheath is generally the component that is most sensitive to fatigue damage.

Fig. 5.6 The photo shows the pull-in to shore of bundled cables, where the fiber optical cable is strapped to the power cable. A fiber optic cable is visible on the left side of the power cable

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The largest curvature variations occur at the departure point from the vessel and in the touch down region. At the top, where the cable is supported by a chute or lay wheel, the cable is alternatively bend against the chute/lay wheel and alternatively straightened over a short distance. At the touch down point the curvature variations are smaller, but are spread out over a longer distance of the cable. During normal laying the cable is gradually fed out, preventing any accumulation of fatigue damage. A jointing operation can take several days, during which normal feeding of the cable onto the sea bed is halted. To verify that the accumulated fatigue damage due to the ship movement during a jointing operation or temporary halt is acceptable, a fatigue analysis may be performed. The fatigue life can be analyzed for different weather conditions (wave heights, periods and directions) in order to provide guidance on weather limitations for the jointing operation or for temporary halts, where the cable is suspended from the ship. The following process may serve as a guide to evaluate the fatigue accumulated during a jointing operation or temporary halt: • First evaluate the global bending conditions of the cable based on the environmental conditions, vessel response characteristics, and the shape of the chute/lay wheel or hang off arrangement. This can either be performed as a dynamic analysis with special purpose software or by simplified conservative assumptions, for instance neglecting the effect of cable bending stiffness. • Then translate the global bending conditions of the cable into strain variations in the fatigue sensitive components. For a single core cable, the strain,ε, in the lead sheath is given by: e ¼ r  κC where r is the radius of the sheath and κCis the curvature of the cable. For a three core cable, frictional stresses resulting from stick-slip of the cores, see Sect. 5.3.7, should also be evaluated. • The accumulated fatigue damage in the lead sheath can be calculated under the assumption of linear cumulative damage (Palmgren-Miner rule), where the accumulated fatigue damage, D, is given by: D¼

k i¼1

ni Ni

where k is the number of strain blocks, ni the number of strain cycles in block i, and Nithe number of cycles to failure at a constant strain range of εi. The S/N fatigue curve for the lead sheath is used to calculate Ni Fatigue failure is usually assumed to occur when the fatigue damage reaches 1.0. The accumulated fatigue damage, D, can be viewed as the fraction of life consumed during the analyzed fatigue loading. A safety factor shall be applied on the calculated damage to reduce the probability for failure,

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where the accumulated damage times the safety factor shall be less than 1.0. The safety factor shall be agreed upon between the customer and manufacture. If installation conditions or cable design go beyond what has previously been verified and/or a fatigue analysis is not considered sufficient, a more detailed investigation may be performed after agreement between the costumer and the manufacturer.

5.3.4

Submarine Cable Protection Techniques

5.3.4.1 Route Survey The aim of a route survey is to find a route enabling safe installation and operation considering various factors such as environmental impact and archaeology. For more details, see Annex 3. 5.3.4.2 Choosing of Cable Route and Protection Techniques Statistics from CIGRE Technical Brochure TB 379 (CIGRE TB 379 2009) indicate that 82% of the faults occurred at sea depths up to 50m and that over 50% of faults occurred on unprotected cables with the comment that buried cables are well protected against fishing gear, but can still be damaged by large sized anchors penetrating deeply into the seabed. When the route survey (seabed survey, fishing and shipping risk, etc.) has been performed and the cable route has been decided, the protection plan can be finalized. Cable protection is made either along the entire cable route or at selected areas like shore landings, shallow water areas, soft soil areas, crossings of shipping channels, crossings of other infrastructures, fishing areas, etc. When the burial of the cable in seabed along the whole cable route or over certain high risk areas is proposed as the optimal protection solution, then a burial assessment survey must be included in the route survey in order to define adequate burial spread and target burial depth. In shore landings protection is typically handled with a pre-excavated trench or preinstalled pipe (Steel/HDPE). Pipes are also used for lake crossings, connecting islands to the mainland, etc. The protection level adopted is a compromise between the effectiveness of the protection method, the risks during installation of the protection method, cost, available technologies, repair possibilities, and time. In areas with rock on the seabed the cable may be protected by rock placement, concrete mattresses, fixing the cable to the seabed, or the route may have been prepared by rock blasting prior to laying. In areas with softer soils post-lay jetting of the cable into the seabed is common. If the seabed consists of compacted sand or for instance hard clay, trenches may be made beforehand. Burial depth must also be chosen as a compromise between protection level and the possibility for the power cable to dissipate heat. In sand a typically burial depth is

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1–2 meters. However, local circumstances may lead to other choices. In harder soil areas more shallow burial depth may be sufficient. Protection of cables in shipping lanes should be chosen taking into consideration the size of the ships and their anchors combined with the knowledge of the inherent protection level of the seabed against anchor penetration. Magnetic fields and temperature rise in the seabed may also play a role in choosing cable route, burial depth, and the protection level. Special precautions are needed in areas with a dynamic seabed (sand waves or with a dynamic shoreline). In these cases cables may be protected in seabed during one period and exposed during another period. Repeated protection may be a needed or initially cables may be laid deep in the seabed. A more detailed explanation on cable protection is given in “Offshore Electrical Cable Burial for Wind Farms: State of the Art, Standards and Guidance & Acceptable Burial Depths, Separation Distances and Sand Wave Effect” prepared for Bureau of Ocean Energy Management, Regulation & Enforcement – Department of the Interior, US, November 2011 (“Offshore Electrical Cable Burial for Wind Farms: State of the Art, Standards and Guidance & Acceptable Burial Depths, Separation Distances and Sand Wave Effect” 2011).

5.3.4.3 Ploughing Ploughing is a cable protection method by direct burial of the cable into the seabed, and is normally done simultaneously with cable laying. The cable is guided through the plough into a narrow self-closing furrow cut by a sea plough towed by a surface vessel (Fig. 5.7). Different plough designs are available to suit various seabed conditions. The traditional plough-share is well suited for muddy substrates. Sandy sediments may require a plough equipped with water jets, thus reducing the required mechanical power, to cut a trench into which the cable is placed. Burial in more consolidated substrates may result only partial closure of the furrow. A plough can bury cables up to about 4 m in soft or sandy soils. Fig. 5.7 Cable plough

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Ploughs are often used for installation and protection of telecom cables and light weight power cables. It is also possible to use a large plough to install and protect larger power cables. This method entails some risks, if it is not both designed and handled with great care. In addition, if the seabed soil is inhomogeneous, or if the plough hits boulders, logs, or other large embedded objects, the plough can lurch, make a sudden sideways move, and may result in damaging the cable.

5.3.4.4 Water Jetting Water jetting is a cable protection method in which an underwater machine (usually a ROV) equipped with water jets liquefy the sediment below the cable, allowing it to sink to a specified depth (dependent on the penetrating length of the swords), after which coarse sediments are deposited. The water jets are fed by high power water pumps (Fig. 5.8). There are different types and sizes of jetting equipment. Some small water jetting machines usually have surface water pumps and need assistance from divers and they are typically used in shallow waters. Larger jetting machines with on-board water pumps are often remote-controlled and are capable of operating in deep waters. Water jetting has become an extensively used power cable protection method. Typically after having been first laid down on the seabed, the submarine cable is post-lay buried by water jetting. This means that it is also used to rebury repaired sections or old cables, which need protection. Post-lay burial has the advantage that cable laying operations are not delayed if difficult burial conditions are encountered. On the other hand, cables can be exposed to third party damage in the time between they are laid and finally buried. This time should be minimized. Water jetting is an effective method where the seabed consists of a thick layer of soft sediments (silt) and/or sand. Jetting can be used for shallow and deep waters (1000 m already achieved) or through areas with steep slopes.

Fig. 5.8 Schematic illustration of a jetting machine

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The effectiveness of the cable protection depends not only on burial depth, but also on the amount of material that will be removed from the trench. The best protection is obtained, if the trench is narrow and is filled with the original material immediately after the jetting operation. In some areas an open trench will be filled in a few days or weeks because of the natural current and tide and the transport of material in the waters. It is important to avoid a situation where the cable is jetted down to the desired depth, but is lying exposed in a wide open trench, without any protection, because all material near the cable has been jetted away.

5.3.4.5 Vertical Injector (Jetting Assisted Plough) The vertical injector (jetting assisted plough) consists of a jetting head/sword with water nozzles on the leading edge. The cable is routed through the jetting head and thus the laying and protection is done in one operation. The method is widely used in Asia and in some European countries (Fig. 5.9). The method is well suited for deep installation in the sea bed in jettable soils, where the water depth is relatively shallow. The method is suitable for deep installation in the sea bed of a cable near shipping lanes and in harbors. However, the method is time consuming and to some extent vulnerable to changes in weather. In case of severe weather the jetting head can be left in the seabed while the cable ship or barge is riding out the storm.

Fig. 5.9 Vertical injector

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Fig. 5.10 Chain saw trenching machines

Fig. 5.11 Example of a wheel trencher

5.3.4.6 Trenching Trenching is a cable protection technique using an underwater vehicle equipped with a trenching wheel or saw to cut a narrow trench on the seabed (Figs. 5.10 and 5.11). It is usually operated from the deck of a support vessel. It is used where seabed is composed of very hard clay or rock (and thus is also known as rock trenching), and also in mixed soils with gravel/stones. Trenching can be a time-consuming activity. It may be a pre-laying or a postlaying activity. Pre-trenching is preferable in terms of risk for the cable system, although problematic for later accurately laying the cable into the open trench. Trenching after laying has the inherent risks already explained for ploughing; operating heavy equipment in contact with the cable. 5.3.4.7 Pipes at Landings In some cases, pre-installed high density polyethylene (HDPE) or steel pipes are used in shore landings, including horizontal directional drilling (HDD) operations. Often a bell-mouth is installed in the end of the pipe in order to protect the cable against damage during cable installation. Extra pipes may be needed for filling the

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pipe with some slurry mixture like bentonite. The reason for filling the pipe is to improve heat transfer from the power cable or to reduce internal corrosion in the splash zone of the pipe. If ends of the pipes are sealed, chemical inhibitors, biocides, and oxygen scavengers may be periodically introduced from the top, to discourage bio-fouling and prevent growth of corrosive sulfide reducing bacteria in stagnant water within the pipe annulus. The cable is normally pulled in with a winch located on shore and with a wire pulled through the pipe fixed to the cable end by a pulling eye or a pulling stocking.

5.3.4.8 Excavation In case of hard soils such as stiff clay or compacted sand a trench can be made beforehand. The cable is laid in the trench and the trench is filled afterwards. Backfilling operation may be critical to avoid mechanical damages to the cable depending on the depth and width of the trench and the seabed conditions. The initial backfilling material on top of the cable is recommended to be either small grain size material or placed carefully by divers or crane to avoid cable damage. Final backfilling may be done for example with the excavated material, with gravel or stones or just leave as it is and wait natural backfilling. Larger size of final backfilling material may give better protection but may need more care during installation. Excavation is suitable for shallow water installations (typically 500 m, in Sect. 5.4.4.2, can be used to calculate the test tension. The test tension, T, is to be rounded up to the nearest 1 kN. The applied test tension shall be at least equal to the calculated test tensions.

5.4.4.2 Water Depth >500 m or When Dynamic Vessel Characteristics Are Known 5.4.4.2.1 Calculation of Maximum Installation Tensile Force For water depths larger than 500 m, or for projects where the vessel characteristics and laying conditions are known the expected maximum installation tension, TE, can be derived through a detailed dynamic installation analysis or calculated according to the following equation: TE ¼ w  d þ H þ D

ð5:2Þ

where: w– submerged weight of 1 m cable [N/m] d – maximum laying depth [m] H – maximum expected bottom tension during installation. The value of H shall not be taken as less than 40  w [N] D – is the dynamic tension [N]

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The dynamic tension, D, is given by the force resulting from the cables inertia, DI, and the drag force, DD, acting on the cable according to the following equation: D¼

D2I þ D2D

ð5:3Þ

The inertia force, DI, is calculated with the following formula: 1 DI ¼ 1:1   bh  m  L0  ω2 2

ð5:4Þ

Where: bh – the maximum vertical movement, crest to crest, of the laying sheave [m] m – mass of 1 m cable, including the mass of sea water inside the cable during installation [kg/m] ω –2π/t, circular frequency of the movement of the laying sheave [1/s] L0 – is the length of the catenary, and is given by L0 ¼ d

H [m] 1 þ 2 wd

t – movement period [s] The drag force onto the cable catenary is calculated based on a semi-empirical relationship according the following equation: DD ¼ 500  OD  R0:9  ðbh  ωÞ1:8

ð5:5Þ

where: OD – outer diameter of cable [m] R – bending radius at touch down point, given by R ¼ Hw [m] The vertical movement of the sheave and the period should be established based on the actual installation vessel and the worst weather conditions permitted during the operation. If the ship movement details are not known, some guidance for choosing bh can be found in Appendix 1. The maximum vertical displacement of the sheave, bh, should be based on the maximum expected wave height Hmax, The following relationship can be used to estimate the maximum wave height Hmax ¼ Hs*1.9, where Hs is the significant wave height.

5.4.4.2.2 Safety Factors to Establish the Test Tension The expected installation tension, TE can be derived through a detailed dynamic installation analysis or calculated based on the equations in Sect. 5.4.4.2.1. The test tension, T, is established by applying a safety factor on the derived expected maximum installation tension, according to:

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T ¼ 1:1  T S þ 1:3  T D where: Ts – the static tension TD – dynamic tension If the expected installation tension, TE is calculated based on Eq. 5.2 the static and dynamic tensions are defined according to: TS ¼ w  d þ H TD ¼ D

5.5

Type Tests

Factory and repair (flexible) joints shall be included in the test sample if it is a part of the delivery for the tests described in Sects. 5.5.1 Coiling Test and 5.5.2 Tensile bending test. If rigid joints are planned both as a field joints or repair joints, they must be tested mechanically according to the mechanical handling expected during installation before the electrical testing as described in Sect. 5.5.5 Tensile Test.

5.5.1

Coiling Test

5.5.1.1 Purpose/Applicability This test applies only to cables which are coiled during manufacturing, storage, transport, or laying and does not apply to cables which are simply wound on drums or turntables. During a coiling operation the cable experiences torsion. It is therefore important to check the cable construction after the coiling test. 5.5.1.2 Preparations/Conditions The coiling test shall be carried out on a cable of suitable length which forms at least six complete turns of the coil. The cable shall include at least one factory joint and a flexible repair joint if applicable. The number of joint(s) and the distance(s) between them are determined in accordance with the following principles: • Single Core Cable A minimum of two complete turns of the coil shall be kept between the joint end and the nearest end of test cable length. If two or more joints are included in the test cable length, the distance between adjacent joint ends shall be at least two complete turns of the coil.

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• Three Core Cable The number of phase joints included in the test cable depends on the cable construction. The outer diameter of the armor layer(s) is normally increased over the phase joints due to a larger outer diameter of the joint compare to the unjointed core. This section of the cable, with increased outer diameter of the armor, is considered as a “mechanically special part.” Also see Fig. 5.21. Two “mechanically special parts” are considered to be mechanically independent if the distance between them is at least one lay length of the outer armor layer, see Fig. 5.21 (a). Two mechanical independent sections will not affect each other during a coiling operation. If all “mechanically special parts” on the delivery cable will be sufficiently separated to ensure mechanically independence, the number of phase joints in the test cable and the distances between the phase joints can be determined in accordance with the same principle as for single core cables. If several (normally three) phase joints are installed in one continuous “mechanically special part,” or if the separation between two “mechanically special parts” is less than one lay length of the outer armor layer, the phase joints shall be considered as “mechanically dependent,” see Fig. 5.21 (b). In this case, the number of phase joints in the test cable shall be at least the same as the number of phase joints that are mechanically dependent in the delivery cable. The distance between the phase joints shall be representative for the minimum distance between the phase joints in the delivery cable. For example, if three phase joints are installed in one continuous “mechanically special part” in delivery cable, at least three phase joints shall be included in the test cable.

a

b

c

d Fig. 5.21 Test cable length for coiling test. In the figure (a) and (b) are referring to three cores cables while (c) and (d) are referring to single core cables

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The number of phase joints can be reduced by replacing some of the joints with dummy phase joint(s), if the joint(s) are not to be used in the testing. A dummy phase joint is a section of the cable that has been built up, through taping or molding, creating an arrangement with similar shape and mechanical properties as a normal phase joint. A minimum of two complete turns of the coil shall be kept between the end of a “mechanically special part” and the nearest end of the test cable length. If two or more “mechanically special parts” are included in the test cable length, the distance of the adjacent part ends shall be at least two complete turns of the coil. The manufacturer shall specify the minimum radius and the direction of coiling to be similar to that envisaged during any coiling operation. The test shall be performed in accordance with the specified radius and direction. The actual radius at the position of the joint(s) shall be recorded, and the test qualifies the joints for coiling down to this minimum coil radius. Before starting the coiling a line parallel to the cable axis shall be marked on the cable in order to check the uniformity of twist in the cable during coiling operations. The height of the jockey above the top layer of the coiled cable shall not exceed that to be used during any envisaged coiling operation. If the cable contains optical fiber cable(s), at least one optical cable factory splice shall be included in the coiling test, if the optical cable contains factory splices.

5.5.1.3 Test With both ends held in order to prevent rotation, the cable shall be coiled with a minimum coiling diameter equal to the value specified by the manufacturer. After coiling, the cable shall be rewound onto the storage facility. This cycle of operations shall be performed at least the number of times as expected for the cable during manufacturing, storage, transport, or laying. During the coiling operation the cable twist shall be substantially uniform, as assessed from the previously applied marker line. 5.5.1.4 Requirements/Discussion Visual Inspection After the coiling test the test cable including a joint are to be inspected visually for deformation of the outer layers. A complete visual inspection shall be performed after the mechanical and electrical tests have been completed. The purpose of the visual inspection is to ensure that the mechanical testing, covered by this Technical Brochure, has not caused any harmful damages to the cable system. It is not possible to specify objective acceptance criteria for all possible deformations and changes that can be encountered during a visual inspection. The visual inspection will therefore always contain some degree of subjectivity. The overall purpose is to check for signs of deterioration which could affect the system in service operation. In some cases it can be helpful to have an untreated cable sample as a reference for the visual inspection.

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A sample taken from the central part of the test cable length, and if applicable, also including one of the joints or “mechanically special part,” shall be subjected to the visual inspection. Examination of the samples with normal or corrected vision without magnification shall not reveal any of the following, but not limited to: • Break, crossing or permanent bird caging of armor wires • Harmful indentations in the cable core(s); for example resulting in indentations or cracks in lead sheath, sharp indentations of the semi-conductive screen into the insulation • For paper cables: breaks in the reinforcing tapes, tears in the insulating papers or harmful creasing in insulation papers • For polymeric cables: cracking or damages to the insulation • Damages to conductor which could have a detrimental effect on the cable performance Particular attention should be paid to the same components in the joint including metallic sheath connections.

5.5.2

Tensile Bending Test

5.5.2.1 Purpose/Applicability This test is designed to take into account the forces that apply to cables during laying and normal recovering. The tensile bending test is applicable for cables which are intended to be installed, recovered or repaired with a method that comprises simultaneous bending under tension, for example, laying over lay wheels, lay chutes, or around capstan wheels. A rigid joint may also be part of the test length if the test cable is sufficiently long such that the rigid joint is not passed around the wheel during the test. See also Tensile test, Sect. 5.5.5 (Fig. 5.22).

Fig. 5.22 Tensile bending test

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5.5.2.2 Preparations/Conditions Factory and flexible repair joints shall be included in the test sample, if they are a part of the cable system. If applicable, the tensile bending test shall be performed on a sample taken from the cable tested according to Sect. 5.5.1, Coiling Test. If the cable has earthing connections between metallic sheath and armor, the test cable shall also include one of these connections. The length of the sample shall be at least 30 m. The sample shall be wound on a drum having a radius not larger than the smallest radius of the pay-off wheel, capstan, or chute, installed on the cable laying vessel. The length of the cable in contact with the test drum shall not be less than half the circumference of the test drum. For all mechanical tests all the conductor and armoring shall be bonded together at both ends of the cable by means of an anchoring head which prevents them from longitudinal movement and relative rotation inside it. The cable heads should be installed in a way that the resulting forces on the different cable components far from the ends are equivalent to the distribution of forces during laying. One way to achieve this is to have separate anchoring devices for the armoring and cable core(s) where the relative load sharing can be controlled by a screw device or similar, an example is shown in Fig. 5.23. Before the test a small tensile load is applied to the cable and the core anchoring position is adjusted, relative to the armoring anchoring, to ensure that the core is also loaded. One head shall be free-rotating and one shall be fixed. The distance from a cable end to a flexible joint shall be at least 10 m or 5 times the lay length of the outer armor layer, whichever is greater. If the cable contains optical fiber cable(s), at least one optical cable factory splice shall be included in the tensile bending test if the optical cable contains factory splices. Establishing the Test Forces The test force, T, used in the test shall be established based on the maximum expected tension during laying or recovery. Recommendation for establishing the test force can be found in Sect. 5.4.4.

5.5.2.3 Test The tension in the cable shall be brought up to the established test tension, T. By means of suitable equipment, the cable sample including joints, if applicable, shall

Fig. 5.23 Illustration of an example of an anchoring head where relative load sharing between conductor and armor can be controlled

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be wound and unwound on the drum for three times consecutively without changing the direction of bending. Figure 5.24 shows an example of a device suitable for carrying out the test. For the joints, the wind and unwind on the drum can be achieved in two ways: 1. The joint is wound onto the drum from a straight position on one side and unwound to a straight position on the opposite side of the wheel. This is repeated three times as shown in Fig. 5.25. 2. The joint is wound onto the drum from a straight position, along at least one quarter of the wheel (from position A to position B in Fig. 5.26) and the joint is unwound back on the initial side to a straight position (from position B to position A). This is repeated three times as shown in Fig. 5.26. The applied load to the cable shall be continuously monitored during the test.

Fig. 5.24 Example of set up for tensile bending test with a flexible or factory joint

Fig. 5.25 Illustration of method to wind and unwind joint during tensile bending test

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Fig. 5.26 Illustration of alternative method to wind and unwind joint during tensile bending test

5.5.2.4 Discussion/Requirements Electrical Tests After the Tensile Bending Test the cable test length and its accessories shall be submitted to an electrical type test according to the applicable standard or recommendation for the actual cable type. Optical Fiber (If Applicable) Experience shows that it is difficult to measure change of attenuation on short lengths. Therefore, after the Tensile Bending test the integrity of the optical fiber shall be verified through a continuity check. Visual Inspection After the electrical test; a sample, including a flexible joint if applicable, shall be submitted to visual inspection. The sample shall meet the requirement outlined in Sect. 5.5.1 Coiling.

5.5.3

Pressure and Water Penetration Tests on Paper Lapped Cable Types

5.5.3.1 External Water Pressure Tests: Mass-Impregnated Cables 5.5.3.1.1 Purpose/Applicability The external water pressure withstand test is performed to simulate the maximum external water pressure that the cable will experience. If the cable has conductive connections between metallic sheath and armor, a cable sample including one such connection shall be tested to verify that the connection does not leak when submitted to the maximum water pressure.

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5.5.3.1.2 Preparations/Conditions If the cable will be coiled during manufacturing, storage, transport, or laying, the sample shall be subjected to a coiling test according to Sect. 5.5.1 of this Recommendation. The sample shall be subjected to a tensile bending test according to Sect. 5.5.2 of this Recommendation. 5.5.3.1.3 Test A cable sample of approx. 5 m, suitably sealed at the ends by means of caps, shall be introduced into a pressure tube and submitted for 48 hours to an external water pressure corresponding to the maximum depth + 50 m for depths up to 500 m and maximum depth + 100 m for depths over 500 m. 5.5.3.1.4 Discussion/Requirements After performing the test, a sample neglecting 0.5 m at both ends shall be submitted to visual inspection. The sample shall meet the requirements in Sect. 5.5.1 coiling. Furthermore, the test shall not give rise to the following: a) Water penetration through the radial watertight barrier shall not be accepted. b) water leaks in conductive connections, if any, have been included in the test sample.

5.5.3.2 External Water Pressure Tests: Oil-Filled Cables 5.5.3.2.1 Purpose/Applicability An external water pressure withstand test is performed to simulate the maximum external water pressure that the cable is to be subjected to. If the cable has conductive connections between metallic sheath and armor, a cable sample including one such connection shall be tested to verify that the connection does not leak when submitted to the maximum water pressure. 5.5.3.2.2 Preparations/Conditions If the cable will be coiled during manufacturing, storage, transport, or laying, the sample shall be subjected to a coiling test according to Sect. 5.5.1 of this Recommendation. The sample (including a joint in the case it is flexible) must be subjected to a tensile bending test according to Sect. 5.5.2 of this Recommendation. 5.5.3.2.3 Test A cable sample of approx. 5 m, suitably sealed at the ends by means of caps, shall be introduced into a pressure tube and submitted to a test pressure for 48 hours. The cable shall be internally filled with oil, maintained at atmospheric pressure during the test.

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The test pressure to which the metallic sheath is exposed shall be the maximum pressure difference at the maximum depth + 50 meter for depths up to 500 m and the maximum pressure difference at the maximum depth + 100 m for depths over 500 m.

5.5.3.2.4 Discussion/Requirements After performing the test the cable sample shall be inspected, neglecting 0.5 m at both ends. Before dissecting oil filled cable samples may be pressurized to the minimum operating pressure difference. The sample shall meet the requirements of Sect. 5.5.3.1.4.

5.5.3.3 Internal Pressure Withstand Test: Oil-filled Cables 5.5.3.3.1 Purpose/Applicability The purpose of this test is to verify the design with respect to the internal oil pressure.

5.5.3.3.2 Preparations/Conditions It is recommended to add a tensile bending test as preconditioning test for single armored cables when a coiling test is not performed. A sample of approx. 10 m of finished cable shall be used. Both cable ends shall be fixed in order to prevent any rotation. In the sample under test the tapes of the mechanical reinforcement shall include at least one manufacturing joint of the type normally used by the manufacturer (welded or soldered).

5.5.3.3.3 Test The sample shall be submitted for 24 hours to an internal pressure: p0 ¼ 1, 5 P0 0 þ 5  105 ðPaÞ where: P'0 being the maximum pressure difference, in Pascal, to which the metallic sheath will be subjected in service.

5.5.3.3.4 Discussion/Requirements After performing the test; a sample neglecting 1 m at both ends shall be submitted to visual inspection. The sample shall meet the requirement in Sect. 5.5.1 coiling. Furthermore, the test shall not give rise to leaks in the sheath.

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Pressure and Water Penetration Tests on Extruded Cable Types

5.5.4.1 Radial Water Penetration Test: Rigid Joint 5.5.4.1.1 Purpose/Applicability Refer to Sect. ▶ 3.8.7.1. 5.5.4.1.2 Preparations/Conditions Refer to Sect. ▶ 3.8.7.4. The tensile test is performed according to Sect. 5.5.5. 5.5.4.1.3 Test Refer to Sect. ▶ 3.8.7.4. 5.5.4.1.4 Discussion/Requirements Refer to Sect. ▶ 3.8.7.4.

5.5.4.2 Radial Water Penetration Test: Factory Joint and Cable 5.5.4.2.1 Purpose/Applicability Refer to Sect. ▶ 3.8.7.1. If the cable has conductive connections between metallic sheath and armor, a cable sample including one such connection shall be tested to verify that the connection does not leak when submitted to the maximum water pressure. 5.5.4.2.2 Preparations/Conditions If the cable will be coiled during manufacturing, storage, transport, or laying, the sample shall be subjected to a coiling test according to Sect. 5.5.1 of this Recommendation. The sample shall be subjected to a tensile bending test according to Sect. 5.5.2 of this Recommendation. 5.5.4.2.3 Test A cable sample of approx. 5 m, suitably sealed at the ends by means of caps, shall be introduced into a pressure tube and submitted for 48 hours to an external water pressure corresponding to the maximum depth + 50 m for depths up to 500 m and maximum depth + 100 m for depths over 500 m. 5.5.4.2.4 Discussion/Requirements After performing the test, a sample neglecting 0.5 m at both ends, including a factory joint if applicable, shall be submitted to visual inspection. The sample shall meet the requirements in Sect. 5.5.1 coiling. Furthermore, the test shall not give rise to the following: a) Water penetration through the radial watertight barrier. b) Water leaks in conductive connections, if any, have been included in the test sample.

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5.5.4.3 Conductor Water Penetration Test 5.5.4.3.1 Purpose/Applicability Refer to Sect. ▶ 3.8.7.1. 5.5.4.3.2 Preparations/Conditions If the cable will be coiled during manufacturing, storage, transport, or laying, the sample shall be subjected to a coiling test according to Sect. 5.5.1 of this Recommendation. The test object shall be subjected to a tensile bending test according to Sect. 5.5.2 of this Recommendation. The test object shall be preconditioned by heat cycles as described in Sect. ▶ 3.8.7.2. 5.5.4.3.3 Test Refer to Sect. ▶ 3.8.7.2. 5.5.4.3.4 Discussion/Requirements Refer to Sect. ▶ 3.8.7.2.

5.5.4.4 Metal Sheath Water Penetration Test 5.5.4.4.1 Purpose/Applicability Refer to Sect. ▶ 3.8.7.1. 5.5.4.4.2 Preparations/Conditions The test object shall be preconditioned by heat cycles as described in Sect. ▶ 3.8.7.3. 5.5.4.4.3 Test Refer to Sect. ▶ 3.8.7.3. 5.5.4.4.4 Discussion/Requirements Refer to Sect. ▶ 3.8.7.3.

5.5.5

Tensile Test

5.5.5.1 Purpose/Applicability The purpose of this test is to verify the performance of the cable and joints when exposed to an axial tensile force without bending. The tensile test shall be performed if: • A rigid joint is included in the cable system. A separate tensile test is not required, if the rigid joint is included in the tensile bending test but not passed around the wheel. This qualifies the rigid joint up to the test tension, T, used in the tensile bending test. • The expected axial tensile forces during the cable installation and/or service life are larger than the test tension, T, used in the tensile bending test. This could for instance be during a pull-in operation, if a vertical laying spread is used or during

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operation of a dynamic cable. The test tension, Ts, shall be evaluated according to the specific project. Factory joints and flexible repair joints shall be included, if they are to be qualified for an axial force, Ts, larger than the test tension T used in the tensile bending test Sect. 5.5.2, Tensile bending test, during straight pull. For engineering purposes, a tensile characterization test, see Sect. 5.6.10, may be performed in conjunction with the tensile test to establish axial stiffness and torsional balance of the cable.

5.5.5.2 Preparations/Conditions The length of the cable used for this test shall be at least 5 times the lay length of the outer armor layer. If a tensile bending test has been performed then this test may be performed on a sample taken from the cable tested according to Sect. 5.5.2 (Tensile bending test). The distance from the cable end to any joints shall be at least 10 m or 5 times the lay length of the outer armor layer, whichever is the greater. The cable heads shall be installed in a way that the resulting forces on the different cable components far from the ends are equivalent to the distribution of forces during laying operations – according to Sect. 5.5.2.2. One head shall be free-rotating and one shall be fixed. If the cable has earthing connections between metallic sheath and armor, the test cable shall also include one of these connections. If the cable contains optical fiber cable(s), at least one optical cable factory splice shall be included in the tensile test if the optical cable contains factory splices. 5.5.5.3 Test The tension in the cable shall be gradually increased up to the specified tension, T or Ts. The load shall be held for a minimum of 30 minutes. The applied load shall be continuously monitored during the test. 5.5.5.4 Discussion/Requirements Electrical Tests After the tensile test the cable test length shall be submitted to an electrical type test according to the applicable standard or recommendation for the actual cable type. Optical Fiber (If Applicable) Experience shows that it is difficult to measure change of attenuation on short lengths. Therefore, after the tensile test the integrity of the optical fiber shall be verified through a continuation check. Visual Inspection After the electrical test (if required), a sample including a joint (if applicable) shall be submitted to visual inspection. The sample shall meet the requirements set out in Sect. 5.5.1, Coiling.

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405

Full Scale Fatigue Test: Dynamic Cables

5.5.6.1 Purpose/Applicability The main purpose of the test is to verify that the dynamic cable can withstand the expected fatigue loads experienced during service life. The test is intended for dynamic cables, which will experience reoccurring bending and tension variations during operation. 5.5.6.2 Preparations/Conditions The full scale fatigue test shall be according to a project specific test procedure, taking into account installation and operational service parameters. To demonstrate the required service life, the test program shall be designed so that the accumulated fatigue damage during the test is greater than or equal to the accumulated fatigue damage during operation. The fatigue damage during operation is established through analysis as outlined below: • Global analysis, where the tension and curvature distribution during service life is established • Local analysis, where the global loads are related to stresses/strains in the internal cable components • Fatigue damage accumulation, where the component stress/strains are transformed into fatigue damage based on S-N data for the cable components Prior to application of the fatigue loading an electrical test is performed on the test length to verify the cable integrity. The electrical test should be performed as a routine test according to the applicable standard or recommendation for the actual cable type. If the cable contains optical fiber cable(s), continuity of the fibers shall be verified before the test. The test sample should have end fittings attached at both cable ends where the armor and cores are anchored. A bend stiffener, bell mouth or similar is utilized in the test setup to control the cable curvature The test sample shall be sufficiently long to allow electrical testing after completion of the fatigue loading. The distance from the end fitting to the top of the bend stiffener or bell mouth shall be at least one pitch length of the outer armor wires, unless the bend stiffener is mounted at a shorter distance from the end termination in service. The distance from the fatigue loaded section of the cable to the other end fitting should be sufficiently long to minimize end effects, as a minimum a distance of one pitch length of the outer armor wires is recommended.

5.5.6.3 Test The cyclic bending of the cable is divided into a number of blocks, typically 5–7, each with different bending radius and number of cycles. The total number of cycles

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in all blocks should be at least 1.5x106 for a test representing 20 years of dynamic operation. The bending radius and number of cycles for each block shall be chosen to achieve a similar distribution of fatigue damage between small and large cycles as experienced during service life. The number of cycles within each block is adjusted to achieve total accumulated fatigue damage equal or greater than the expected fatigue damage during service life. A constant tensile force, representative of the tensile force experienced during fatigue loading, is applied onto the cable during the bending cycles. The frequency of the bending cycles should be chosen such that unacceptable temperature increase is avoided during the test due to friction between the internal components.

5.5.6.4 Discussion/Requirements After completion of the fatigue loading the cable test length shall be submitted to an electrical routine test according to the applicable standard or recommendation for the actual cable type. Acceptance criteria for electrical test and resistance measurement shall be in accordance with the applicable standard or recommendation for the actual cable type. All optical fibers (if included) shall be checked for continuity. No fiber breaks shall be detected. After the electrical test the cable shall be dissected and subjected to visual inspection. A cable that has undergone a fatigue test simulating the entire service life can be expected to suffer some wear and layer degradation. The overall purpose of the inspection is to check for signs of deterioration which could affect the system in service operation. Examination shall not reveal any of the following: • • • • •

Cracks or holes in the outer sheath Permanent bird caging or break of more than two armor wires per layer Cracks or holes in the core sheath Cracking or damages to the insulation Damages to conductor which could have a detrimental effect on the cable performance

The metallic sheath from one core shall be subjected to a dye penetration examination as a mean to find any fatigue-induced cracks. The test shall not reveal any cracks or holes that penetrate through the metallic sheath.

5.6

Project Specific Tests and Special Tests

5.6.1

Introduction

Type tests are normally sufficient to verify the design of cable and accessories. However, if experienced design values are exceeded or there are changes in the conditions related to for instance handling, installation or operation then special considerations may be required. In specific cases one or more project specific test (s) for engineering or development purposes and/or qualification may be needed.

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It is not intention that all tests described in Sect. 5.6 are automatically part of testing regime for submarine cable systems, but more an exception to study and/or address project specific issues or for engineering information. Examples of specific issues that may need to be considered either by engineering means or by project specific tests are: • Deeper water depth, different climate or different environments like seabed conditions • New type of cable storages, roller ways, pulling or breaking devices or other equipment • New type of laying, installation, protection or repair method or configuration

X

X

5.6.3 Crush test

X

X

5.6.4 Crush test for long term stacking

X

X

X

5.6.5 Sidewall force test

X

X

X

5.6.6 Impact test

X

5.6.7 Pulling stocking test

X

5.6.8 Handling test for rigid joint

X

X

5.6.9 Sea trial

X

X

5.6.10 Tensile characterisation test

X

X

5.6.11 Friction Coefficient test

X

X

Final installation (backfilling, duct installation, J-tubes etc.)

Cable reel, roller way, cable basket, chute

X

Environment

Cable joint and earthing connection

5.6.2 Bending test without tension

Project specific tests and special tests

Cable handling equipment

Cable

Item that can be tested

Vessel

Table 5.3 Overview of project specific tests and special tests

X

X

X X X

X

X

X

X

X

X

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This chapter gives examples of tests. Other tests may also be considered. The intention of many of the tests is to verify that equipment or special conditions together with the cable system design give acceptable results (Table 5.3).

5.6.2

Bending Test Without Tension

5.6.2.1 Purpose/Applicability The purpose of the test is to verify the integrity of the cable when being bent to a small bending radius without tension. The test is recommended to be performed when the relative bending radius during handling of the cable is smaller compared to what has previously been verified with a similar cable design. A smaller bending radius could for instance be required for deliveries on drum or in storage of a spare cable on a drum or basket. 5.6.2.2 Preparations/Conditions Factory joint and earthing connection should be included in the test sample, if they will be handled on the same bending radius as the cable. The test can be performed on a complete armored cable or on a sheathed cable core depending on where in the production or installation phase the bending to small bending radius will be performed. 5.6.2.3 Test It is recommended that the test is based on the bending test method described in IEC60840 (IEC 60840 2020) or IEC62067 (IEC 62067 2022). However, the number of bending repetitions and the bending radius should reflect the expected conditions during cable handling. 5.6.2.4 Discussion/Requirements Electrical Test After completion of the bend test it is recommended that an electrical routine test is performed according to the applicable standard or the recommendation for the actual cable type. Visual Inspection After the electrical test, the sample shall be submitted to visual inspection. The sample should meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test.

5.6.3

Crush Test

5.6.3.1 Purpose/Applicability The purpose of the test is to verify that the cable can withstand the expected crush loads during installation or repair. This test replicates the crush loads experienced by the cable during installation with a linear tensioner system where traction is achieved by squeezing the cable between two or more tracks. The tracks can consist of tires, belts, or pads.

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The test is recommended if the crush loads are more severe than that previously tested with a similar cable design. For tensioners, the shape and material of the pads will affect the maximum crush capacity of the cable. A crush test is also recommended if the design (shape or material) of the tensioner pads have been significantly changed compared with the previously verified design. The contribution of radial force from the armor wires when the cable is in tension should also be considered. This can be performed by applying the maximum installation tension, see Sect. 5.4.4, to the cable simultaneously as the crush load is applied. Alternatively, the crush load can be increased to compensate for the additional radial forces resulting from the armor wires when the cable is exposed to the maximum installation tension.

5.6.3.2 Preparations/Conditions The test setup should represent the tensioner system installed on the cable laying vessel; the number of tracks and the wheel, pad, or belt geometry and the material should be comparable (Fig. 5.27).

Fig. 5.27 Tensioner systems

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Factory joints and flexible repair joints should also be tested if they will experience a crush load.

5.6.3.3 Test The crushing load is gradually increased from zero up to the specified load. It is recommended that the load is held for a minimum of 1 h.

5.6.3.4 Discussion/Requirements Visual Inspection After the crush test the sample shall be submitted to visual inspection. The sample shall meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test. Particular attention should be paid to harmful indentations in the cable core(s). Optical Fiber If the sample contains an optical fiber, the integrity of the optical fiber should be verified through a continuation check.

5.6.4

Crush Test for Long-Term Stacking

5.6.4.1 Purpose/Applicability The purpose of this test is to verify that the cable can withstand long term crush loads representative for stacking during storage, transportation, or operation. The test is recommended if the crush loads are more severe than that previously verified with a similar cable design.

5.6.4.2 Preparations/Conditions The cable(s) is placed on a flat surface, representative of the actual conditions during stacking. If applicable, at least one cable shall include a factory joint. A constant load is applied to the cable(s) by means of weights or other mechanical devices. Figure 5.28 shows an example of test setup using weights.

Fig. 5.28 Test arrangement example

Weights Steel plate Cable Stopper

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5.6.4.3 Test The cable diameter should be measured prior to the test and should be continuously monitored during the test by a suitable device. The diameter may change over time due to the applied load. The load should be applied for at least 7 days.

5.6.4.4 Discussion/Requirements After the long-term crush test the sample shall be submitted to visual inspection. The sample shall meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test. Particular attention should be paid to harmful indentations in the cable core(s).

5.6.5

Sidewall Force Test

5.6.5.1 Purpose/Applicability The purpose of the test is to verify that the cable can withstand the sidewall forces that the cable will be exposed to during installation or operation. Sidewall forces are radial forces that arise when a cable is in tension simultaneously as it is bent against another object. This may for instance occur when pulling the cable over rollers or pulling the cable over a fixed metallic curve like a chute or J-tube. In the tensile bending test a sidewall force, representative of a capstan wheel or chute during installation, is applied to the cable. This test is intended to cover other situations, which might result in larger sidewall forces or large point loads from rollers or similar. The test is recommended if the expected sidewall force during the cable installation is more severe than that previously verified with a similar cable design. The test may be performed as a destructive test for information. The interaction between the cable and the item of contact for the cable decides the character of the sidewall force and can be divided into the following three situations: Distributed Contact Force per Unit Length A force per unit length will be exerted onto the cable when it is in contact over an arc of a bend. This force is also often referred to as Sidewall bearing pressure. This loading situation is also tested as part of the Tensile bending test. The resulting contact force has the unit N/m (Fig. 5.29). The force per unit length, FSWP, is given by: FSWP ¼ where: T is the cable tension R is the bending radius of the curve

T R

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Fig. 5.29 Distributed contact force per unit length, illustration

Fig. 5.30 Distributed point contacts, illustration

Distributed Point Contacts If the cable is pulled around a bend built up of rollers this will result in a contact force between each roller and the cable. The sidewall force per unit length is divided between the rollers and has the unit N. The bending radius of the cable is the same as the bending radius of the curve built up by the rollers (Fig. 5.30). The force between each roller and the cable is given by: F¼

Td R

where: d is the distance between each roller [m]. R is the bending radius of the curve built up by the rollers [m] Point Contact A third situation arises if the cable is bent over an object but the bend stiffness of the cable prevents it from following the radius of the object. The bending radius of the cable is larger compared to the radius of the object. This will result in a contact force between the object and the cable with the unit N (Fig. 5.31). The sidewall force, F, onto the cable is given by: F ¼ 2  T  sin

θ 2

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Fig. 5.31 Side wall pressure due to point contact

where: θ is the angle between the directions of pulling

5.6.5.2 Preparations/Conditions The test setup should represent the actual installation conditions with regard to shape and size of object(s) in contact with the cable, the loading arrangement (see Sect. 5.6.5.1), and the applied tension.

5.6.5.3 Test The tension in the cable is gradually increased up to the specified tension. While in tension the cable is pulled around the specified object(s) (Figs. 5.32 and 5.33).

Fig. 5.32 Example of simulation of cable moving against a guiding plate of a capstan wheel

Fig. 5.33 Example of destructive test in which a three-core cable is moving against rollers which are too far away from each other. In the picture the rollers apply a sidewall force to the cable which is too high

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5.6.5.4 Discussion/Requirements After the side wall force test the sample shall be submitted to visual inspection. The sample shall meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test.

5.6.6

Impact Test

5.6.6.1 Purpose/Applicability The test is primarily performed for information to establish the impact capacity of the cable and to give an indication of the effect of a typical impact. Impact damage may for example result from accidentally dropped objects. Rock placement may be used as a protection method where the rock size is chosen to be small enough to avoid cable damage and large enough to give suitable long term protection. An impact test to simulate rock placement is recommended if the expected impact energy from the rocks is larger compared to what has previously been verified to be acceptable with a similar cable design and installation.

5.6.6.2 Preparations/Conditions The cable sample length depends on the number of impact positions. The minimum distance from the end to the impact location of the cable should be at least 0.5 m (Fig. 5.34). The cable is placed on a flat surface representative of the actual soil conditions; this can for example be a sand bed. If a rigid support is used, the impact energy transferred to the cable will increase compared to a soft support. Tests performed on a rigid support will therefore provide a conservative estimate of the impact capacity of the cable applicable for all sea bed types.

Fig. 5.34 Schematic illustration of an impact test setup

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5.6.6.3 Test The impact test is performed by dropping a hammer with a certain mass from a specific height. The shape of the front of the hammer should reflect the expected impacting object. The impact energy in the test can be calculated as a function of drop height and hammer mass according to: E ¼ m  g  Δh where: E – impact energy [J] m – mass of hammer [kg] g – gravitational constant [m/s2] h – drop height [m]. For a three core cable, the orientation of the cores with respect to the impact location can affect the severity of the impact. It is therefore recommended that the test is performed for different orientations to find the most severe orientation. Examples of impact locations are directly over a core or on top of a filler profile containing an optical fiber as shown in Fig. 5.35. The test is repeated with gradually increasing impact energy. The cable is moved between each impact and a distance of at least 0.5 m should be used between each impact location. Example of Typical Impact Test Procedure 1. 2. 3. 4. 5. 6.

Mark the impact locations on the cable. Position the cable in the test rig at the first drop location. Adjust drop mass and/or height to achieve specified energy level at location. Execute impact. Remove impact hammer and mark actual impact location for future identification. Execute FO continuity check.

Fig. 5.35 Illustration of impact location on three core cable

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Fig. 5.36 Photo of three core armored cable after impact test

7. Repeat steps 2, 3, 4, 5, and 6 for all specified drop locations. 8. Perform visual inspection.

5.6.6.4 Discussion/Requirements Visual Inspection After completion of the impact test the sample shall be submitted to visual inspection (Fig. 5.36). The sample should meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test. During impact testing the energy may be transferred to the core(s) and cause damage to the inner semiconductor while still leaving the metallic sheath intact and without physically damaging the outer semiconductor. Optical Fiber If the sample contains an optical fiber, the integrity of the optical fiber should be verified through a continuation check.

5.6.7

Pulling Stocking Test

5.6.7.1 Purpose/Applicability This test is performed to verify the integrity of the cable after being held by a pulling stocking. The test procedure is also applicable for other cable holding devices that grip the cable through friction by applying a radial force onto the cable. During laying, jointing, and lifting operations, the cable may be attached to the vessel by a pulling stocking (sometimes referred to as a Chinese finger). During these operations, the cable is suspended and undergoes cyclic tensile forces. This test is recommended to be performed if the design of the pulling stocking, cable design or tensile loads differ from what has previously been verified to be

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acceptable. If the pulling stocking is applied to an end that will be removed, the test is normally not necessary.

5.6.7.2 Preparations/Conditions The length of the cable should be at least 10 m or five times the lay length of the outer armor layer, whichever is greater. The cable is fastened by the pulling stocking in one end and a cable head is in installed on the other end. The cable head should be installed in such a way that the resulting forces on the different cable components are equivalent to the distribution of forces during laying operations – according to Sect. 5.5.2.2. Factory joints do not need to be tested, if they are not intended to be supported by the pulling stocking. 5.6.7.3 Test The cable, fastened by the pulling stocking, should undergo a cyclic tensile test. The mean tensile force, the tensile force amplitude, and the number of cycles should be representative for dynamic conditions during which the pulling stocking is used. 5.6.7.4 Discussion/Requirements Electrical Test After completion of the bend test it is recommended an electrical routine test is performed according to the applicable standard or recommendation for the actual cable type. Visual Inspection After the electrical test, the sample shall be submitted to visual inspection. The sample should meet the requirements set out in Sect. 5.5.1.4 for the condition of the cable after the coiling test.

5.6.8

Handling Test for Rigid Joint

5.6.8.1 Purpose/Applicability The purpose of the handling test is to verify the ability of the rigid joint, together with cable, to withstand the expected handling during off-shore installation. If mechanical supports such as bend stiffeners or bend restrictors are used, these should be included in the test (Fig. 5.37). 5.6.8.2 Preparations/Conditions The test is performed on a rigid joint including at least 10 m of free cable length on both sides of the joint. If mechanical supports such as bend stiffeners or bend restrictors are used, these should be installed on the cable. Depending on the purpose of the test, core joints may be excluded, for example if the primary purpose is to verify the bending radius of the cable and the interaction with the bend protection system outside the joint.

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Fig. 5.37 Example of handling test on rigid joint with bend restrictors

5.6.8.3 Test The test object shall be moved according to the planned handling situation off-shore. The load is applied to the test object either by lifting the joint and cable or by applying a tension on the cable in relation to a joint that has been fixed by clamping or similar. Cable bending radius should be monitored during the test. The test procedure shall be repeated the same number of times as is expected during the actual installation and laying situations. 5.6.8.4 Discussion/Requirements The cable bending radius on both sides of the rigid joint shall not be less than the minimum bending radius of the cable without tension. After the test the cable and the rigid joint shall be visually inspected according to Sect. 5.5.1.4.

5.6.9

Sea Trial

5.6.9.1 Purpose/Applicability A sea trial is a very costly test and should only be performed in exceptional cases. The focus of the sea trial test is the interaction between the submarine cable and the installation equipment. In special cases, where for example installation conditions are close to the operational limits of the laying spread, if the installation and protection techniques utilized significantly differ from established practice, a sea trial may be a required to confirm the overall installation capability. A sea trial can include the laying vessel, but it can also focus on other aspects of the installation such as post lay protection.

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Mechanical tests covered in this Technical Brochure are intended to reproduce actual installation conditions as far as possible. The benefit of performing laboratory test is that the test loads (anticipated during installation) are controlled and safety factors can be introduced. A sea trial test is not meant as a qualification test of the cable system design. Changes in the mechanical construction of a cable will not normally give grounds for a sea trial.

5.6.9.2 Preparations/Conditions The object under test depends on the issues to be tested during the sea trial. Accessories such as repair joints, field joints, factory joints, and earthing connections between metallic sheath and armor are only included if relevant for the test. 5.6.9.3 Test The laying spread, equipment used, installation conditions, and cable system shall be representative of the actual conditions for the cable installation. 5.6.9.4 Discussion/Requirements The tests to be performed after the sea trial test will depend on the issues to be investigated. The following tests are recommended: Electrical Test After the Sea Trial Test the cable test length shall be submitted to an electrical test as a minimum corresponding to an after laying test. Additional or alternative electrical test can be agreed. Visual Inspection After the electrical test, the sample shall be submitted to visual inspection with the aim of discovering significant damage and water leaks. Optical Fiber If the sample contains an optical fiber, the integrity of the optical fiber shall be verified after the sea trial test. Acceptance criteria and other additional tests can be agreed between the customer and the manufacturer.

5.6.10 Tensile Characterization Test 5.6.10.1 Purpose/Applicability The test is performed for engineering information to establish axial stiffness, torsional balance, and rotational characteristics of the cable. These characterization measurements can be performed during the Tensile Test, Sect. 5.5.5, if applicable. Axial stiffness, EA, is a measure of the axial elongation of the cable as a function of the applied tensile load. The axial stiffness can be computed as:

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EA ¼

T e

where T is the applied axial tension and ε is the cable strain, given by the change in length Δl per unit of the original length l according to: e¼

Δl l

The induced twist per unit length as a function of the applied tension is a measure of the torsional balance and rotational characteristics of the cable. By measuring the rotation angle at two positions along the cable, ϕ1and ϕ2, which are separated by a distance, l, the twist per unit length can be calculated from: Δϕ ϕ1  ϕ2 ¼ l l

5.6.10.2 Preparations/Conditions The length of the cable used for this test should be at least five times the lay length of the outer armor layer. The cable heads should be installed in a way that the resulting forces on the different cable components remote from the ends are equivalent to the distribution of forces during laying operations. One head shall be free-rotating and one shall be fixed. The cable should be as straight as possible during the test in order to avoid introducing effects from straightening of the cable when the tensile load is applied. This can be achieved by placing the cables on rollers or similar. Cable elongation is measured over a distance of the cable using elongation sensors. Rotation can be measured by monitoring the angular rotation of the free rotating head or by measuring the relative rotation at two positions, at a defined distance along the cable, using angular sensors. 5.6.10.3 Test The tension in the cable shall be gradually increased up to the specified maximum tensile tension, Ts. The load application should be sufficiently slow to avoid introduction of dynamic effects. This maximum tension should be maintained for a minimum of 15 min. The tension should then be decreased down to the minimum tension, T0. The minimum tension, T0, should be chosen so that the cable is maintained straight during the load cycles. A recommended value is: T0 ¼ w  L where: w ¼ weight of 1 m cable in Newtons L ¼ length of cable used for the test

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The tension T0 is equal to the weight of the total cable length under the test, and represents roughly the tension required to keep the cable straight with the aid of suitable supports (eliminating in this way any catenary). The load cycle should be repeated three times or until stable elongation and rotation readings are achieved. Applied load, elongation, and rotation should be recorded throughout the test.

5.6.10.4 Discussion/Requirements The evaluation of the parameters should be performed based on stable readings because initial setting and straightening of the cable can occur during the first load cycles. To separate straightening of the cable from elongation it is recommended to have two sets of elongation sensors, facing each other on opposite sides of the cable. Axial elongation is calculated as the average of the two recordings. Alternatively, the effect of straightening can be reduced by ensuring that the cable is straight and measuring elongation over a long section of the cable.

5.6.11 Friction Coefficient Test 5.6.11.1 Purpose/Applicability Existing information on submarine cable pulling forces, friction coefficients, and friction forces is often of value. If new conditions, equipment, or cable design is planned, then it may be reasonable to make friction tests to get engineering information about friction of these submarine cables in different conditions. Changes in installation conditions can also have an impact on the friction coefficient, for instance: • • • • • • • • •

Static or dynamic conditions Temperature Rough or smooth surface Water, oil, lubricant, mud, sand, ice, tape, sheet, or other third material or agent in contact with the cable surface Properties of cable material in a caterpillar belt or rubber wheel Edges and bending radius Radial force or pressure Change of material properties due to wear or ageing Deformation of a cable or deformation of contact material Places where friction plays some role are:

• Cable sliding against a sheave, chute, caterpillar contact surfaces, capstan wheel, or other laying equipment on a cable laying vessel

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• Cable sliding in pulling grips (Pulling Stockings) or in clamps/ropes and in buoyance units • Cable sliding against a wall of a straight or curved pipe, hole, or cable support during installation • Cable sliding in cable clamps during cable operation

5.6.11.2 Preparations/Conditions Test conditions should reflect actual conditions. Some safety margin in test conditions or in analyzing the test results may be applied if necessary. Several samples and repeated test will give some information on the variation of values. Tests may also be done also to reflect real conditions. In all tests suitable representative pieces of submarine cable are needed. In the following the basic test methods are described. The test rig can change depending on the situation it is required to represent. 5.6.11.3 Test To measure static friction a cable is pulled in test conditions or in real conditions and a dynamometer is used to register the maximum force, which is needed to make the cable start moving. The coefficient of friction is calculated by dividing the pulling force by the weight of the test object. Another way to measure the static friction is to place a cable sample on a horizontal surface of the material which is being tested. Then the surface will be inclined slowly until the cable starts to slide. The angle where the cable starts sliding is registered and the coefficient of friction is calculated from the inclination angle. The coefficient of friction, μ, is given by: μ ¼ tan α where α is the inclination angle where cable starts to slide. To measure dynamic friction the cable is moved with a realistic speed against the test surface. The pulling force is measured. Normally the pulling force has some variation and it is recommended to register several values to get an average value and variation of values.

5.6.11.4 Discussion/Requirements If a static and/or dynamic friction test is done, it is done for engineering information. There are no requirements for coefficient of friction.

Bibliography/References CIGRE TB 194, Working Group 21.17, “Construction, laying and installation techniques for extruded and self-contained fluid filled cable systems” (2001) CIGRE TB 379, Working Group B1.10, “Updating of Service Experience of HV Underground and Submarine Cable Systems” (2009) CIGRE TB 398, Working Group B1.21, “Third Party Damage to Underground and Submarine Cables” (2009)

5

Recommendations for Mechanical Testing of Submarine Cables (and Their. . .

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CIGRE TB 490, Working Group B1.27, “Recommendations for testing of long AC submarine cables with extruded insulation for system voltages above 30(36) to 500(550) kV” (2012) CIGRE TB 496, Working Group B1.32, “Recommendations for testing DC extruded cable systems for power transmission at a rated voltage up to 500 kV” (2003) CIGRE TB 610, Working Group B1.40, “Offshore Generation Cable Connections” (2015) DNV recommended practice DNV-RP-C205, “Environmental conditions and environmental loads” (2010) DNV recommended practice DNV-RP-F105, “Free spanning pipelines” (2006) ELECTRA 171, CIGRE Working Group 21.02, “Recommendations for mechanical tests on submarine cables” April 1997 ELECTRA 189, CIGRE Working Group 21.02, “Recommendations for long AC submarine cables with extruded insulation for system voltage above 30(36) to 150(170) kV” April 2000 ELECTRA 32, “Recommendations for tests on DC cables for a rated voltage up to 550 kV” (1974) ELECTRA 68, CIGRE Working Group 21.06, “Recommendations for mechanical tests on submarine cables” (1980) ELECTRA 89, “Transient pressure variations in submarine cables of the self contained oil filled type” (1983) IEC 60840, “Power Cables with extruded insulation and their accessories for rated voltages above 30 kV (Um¼ 36 kV)) up to 150 kV (Um¼ 170 kV) – Test methods and requirements 2020 IEC 60885-3 Ed.2.0, “Electrical test methods for electric cables – Part 3: Test methods for partial discharge measurements on lengths of extruded power cables” April 2015 IEC 62067, “Power Cables with extruded insulation and their accessories for rated voltages above 150 kV (Um¼ 170 kV)) up to 500 kV (Um¼ 550 kV) – Test methods and requirements” April 2022 International Cable Protection Committee (ICPC) Recommendation No. 3, “Criteria to be Applied to Proposed Crossings Between Submarine Telecommunications Cables and Pipelines/Power Cables” (2002) International Cable Protection Committee (ICPC) Recommendation No. 9, “Minimum Technical Requirements for a Desktop Study” (2012) ISO 13628-5:, “Petroleum and natural gas industries – Design and operation of subsea production systems – Part 5: Subsea umbilicals” (2009) “Offshore Electrical Cable Burial for Wind Farms: State of the Art, Standards and Guidance & Acceptable Burial Depths, Separation Distances and Sand Wave Effect” prepared for Bureau of Ocean Energy Management, Regulation & Enforcement – Department of the Interior, US, November 2011. Marc Jeroense (PhD), born in The Netherlands in 1966 and living in Sweden since 1997 has previously worked in different roles at NKF, ABB and NKT. The roles range from specialist via project and product management to global R&D management. He has had a profound role in the development and commercialization of HVDC cable systems. He acts since long at the interface of market and technology. He is an active member of the CIGRE organization and has received the Technical Council Award. He is Senior Member of IEEE. He chaired the ISTC of Jicable-HVDC in 2017 and the Young Researchers Contest of Jicable HVDC Symposium in 2019 and 2021. He has a uniquely placed, 30 years, broad and in-depth knowledge and experience from the cable industry. With a solid and unique PhD on MI cables in the background, he has built his knowledge ranging from performing R&D work, managing the latter both as project and portfolio (Global R&D Manager), managing HV test lab and as Product Manager at the melding interface of market and technology.

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With long experience in the respected CIGRE organization he has contributed in several recommendations. He operates across various organizational levels within CIGRE from expert to Convener and member of the Strategy Advisory Group. HVDC for the renewable sector provides fertile ground for innovation. Marc has been at the forefront from inception to the development and qualification of the world record 525 & 640 kV extruded DC cable system. First line engagement in development, qualification and commercialization of the first dynamic power cable is also on the list of his achievements. He is now active as Owner and Expert of MarCable Consulting in giving services like cable testing inspection, developing technical specifications, clarification meetings, cable system courses and technical advisory.

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Recommendations for Testing DC Extruded Cable Systems for Power Transmission at a Rated Voltage up to 500 kV Bjørn Sanden

Contents 6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.2 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.3 Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.4 Summary of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.2 Test Objects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.3 Test Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.4 Thermal Cable Design Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.5 Thermal Conditions for Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5.6 Conditions for Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 Development Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Prequalification Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.1 Range of Approval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.2 Summary of Prequalification Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.3 Test Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.4 Long Duration Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.5 Superimposed Switching Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.6 Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.7 Success Criteria, Re-Testing and Interruptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4 Type Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1 Range of Approval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.2 Test Objects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.3 Non-Electrical Type Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4 Electrical Type Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4.1 Mechanical Preconditioning Before Electrical Type Test . . . . . . . . . . . . . . 6.4.4.2 Load Cycle Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4.3 Superimposed Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4.4 Test of Outer Protection for Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

427 427 427 428 428 429 429 430 431 433 433 433 434 435 435 436 437 437 438 439 439 439 439 440 441 441 441 442 443 443

B. Sanden (*) Nexans, Oslo, Norway e-mail: [email protected] © Springer Nature Switzerland AG 2023 P. Argaut (ed.), Accessories for HV and EHV Extruded Cables, CIGRE Green Books, https://doi.org/10.1007/978-3-030-80406-0_6

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6.4.4.5 Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4.6 Success Criteria, Re-Testing, and Interruptions . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5 Return Cable Type Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.2 Mechanical Preconditioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.3 Thermo-Mechanical Preconditioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.4 AC Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.5 Lightning Impulse Withstand Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.5.6 Cable Design with Integrated Return Conductor . . . . . . . . . . . . . . . . . . . . . . . 6.5 Routine Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5.1 Routine Tests on Transmission Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5.2 Routine Tests on Cable Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5.2.1 Tests on Prefabricated Joints and Terminations . . . . . . . . . . . . . . . . . . . . . . . . 6.5.2.2 Tests on Factory Joints of Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5.2.3 Tests on Repair Joint for Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5.3 Return Cables or Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6 Sample Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1 Sample Tests on Transmission Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.1 Frequency of Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.2 Conductor Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.3 Measurement of Electrical Resistance of Conductor . . . . . . . . . . . . . . . . . 6.6.1.4 Measurement of Capacitance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.5 Measurement of Thickness of Insulation and Non-metallic Sheath . . . 6.6.1.6 Measurement of Thickness of Metallic Sheath . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.7 Measurement of Diameters, if Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.8 Measurement of Density of HDPE Insulation, if Applicable . . . . . . . . 6.6.1.9 Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.10 Water Penetration Test, if Applicable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.1.11 Tests on Components of Cables with Longitudinally Applied Metal Tape or Foil, Bonded to the Oversheath, if Applicable . . . . . . . . . . . . 6.6.2 Sample Tests on Factory Joints for Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.2.1 Tensile Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.2.2 PD Measurement and AC Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.2.3 Impulse Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.2.4 Hot Set Test for Insulation Where Applicable . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.2.5 Pass Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.3 Sample Tests on Repair Joints and Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6.4 Sample Tests on Field Molded Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7 After Installations Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7.1 High Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7.2 Test on Polymeric Sheaths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7.3 TDR Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A: Derivation of Test Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DC Voltage Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impulse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Polarity Reversal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Duration of Tests: Prequalification & Type Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix B: Technical Basis for the Detailed Prequalification Test Schemes . . . . . . . . . . . . Appendix C: Schematic Representation of the Sequence of Tests for Land and Submarine Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D: Comparison with Guidelines and Recommendations for Transmission Cable Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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6

Recommendations for Testing DC Extruded Cable Systems for Power. . .

6.1

Introduction

6.1.1

Background

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In 2003 TB 219 “Recommendations for testing DC extruded cable systems for power transmission at a rated voltage up to 250 kV” was issued by CIGRE study committee B1 (CIGRE TB 219 2003). This was the first document issuing recommendations for testing of high voltage DC extruded cable systems. The recommendation was recognized by a large and relevant technical community and has become the reference for the user community. In 2008 it was decided by SC B1 to launch a new working group to prepare recommendations for testing DC extruded cables systems at a rated voltage up to 500 kV. The decision was motivated by the fact that commercially available HVDC extruded systems above 250 kV were emerging. At the time of preparing this recommendation there is laboratory experience at voltages up to and including 500 kV, but operating experience is limited to 200 kV (Bacchini et al. 2010). Contracts have been awarded at a voltage level up to 320 kV (Vatonne et al. 2011). A further increase in voltage level is to be expected and this recommendation will therefore cover voltages up to 500 kV. However, it is important to emphasize that the lack of operational experience above 200 kV and the limited number of tests at higher voltage levels represent an uncertainty in the preparation of this recommendation. Consequently new relevant knowledge that emerges from increased testing and/or service experience at higher voltages may necessitate new revisions of this recommendation in the future. The tests in this recommendation follow the same principles as in TB 219. For completeness, the backgrounds for the different tests are included also in this recommendation. The philosophy adopted is that the tests recommended should apply to the complete HVDC cable system as installed and as intended to function. Wherever possible, the tests are based on existing recommendations, standards and practices. It must be recognized that DC extruded cables may involve the use of many different materials such as thermoplastic or crosslinked polymers (either filled or unfilled) and differing manufacturing processes. In consequence, the tests recommended are largely functional and not specific to one material or manufacturing process. This technical brochure replaces TB 219 issued in March 2003 (CIGRE TB 219 2003).

6.1.2

Scope

This document recommends a series of tests on extruded cables for DC power transmission systems (land or submarine cables with their accessories in

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fixed installations) up to and including 500 kV. Within the scope of these recommendations “extruded” shall mean either filled (e.g., with mineral or carbon) or unfilled and either thermoplastic (e.g., polyethylene, etc.) or thermoset (e.g., crosslinked polyethylene, ethylene propylene rubber, etc.) insulations.

6.1.3

Revisions

Essential in TB 219 are the principles for determination of voltage test factors and duration of the different test sequences. The WG have had thorough discussions of this approach extended to higher voltage levels and there is a consensus in the WG that these principles shall be adopted also for the recommendation covering higher voltage levels. Consequently, the voltage test factors and test sequences from TB 219 are kept in this recommendation. The main changes made to the text of TB 219 can be summarized as follows: – The voltage range covered is extended up to 500 kV. – The text has been updated to take into account the latest revisions of IEC 60840 (Edition 4) (Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements 2020) and IEC 62067 (Edition 2) (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). – The range of approval for both prequalification tests and type tests has been revised. – For the load cycle blocks of the prequalification test, the requirement has been changed from number of days to number of cycles. – Recommendations for routine and sample tests on cable accessories have been included.

6.1.4

Summary of Tests

Where applicable, test definitions are in line with IEC 60840 (Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements 2020) and IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020).

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Recommendations for Testing DC Extruded Cable Systems for Power. . .

Development tests Prequalification test

Type tests

Routine tests

Sample tests

Tests after installation

6.1.5

429

Tests made during the development of the cable system Test made before supplying on a general commercial basis a type of cable system covered by this recommendation, in order to demonstrate satisfactory long term performance of the complete cable system NOTE 1: The prequalification test need only be carried out once unless there is a substantial change in the cable system with respect to material, manufacturing process, design or design electrical stress levels NOTE 2: A substantial change is defined as that which might adversely affect the performance of the cable system. The supplier should provide a detailed case, including test evidence, if modifications are introduced, which are claimed not to constitute a substantial change Tests made before supplying on a general commercial basis a type of cable system covered by this recommendation, in order to demonstrate satisfactory performance characteristics to meet the intended application NOTE: Once successfully completed, these tests need not be repeated, unless changes are made in the cable or accessory with respect to materials, manufacturing process, design or design electrical stress levels, which might adversely change the performance characteristics Tests made by the manufacturer on each manufactured component (length of cable or accessory) to check that the component meets the specified requirements Tests made by the manufacturer on samples of complete cable or components taken from a complete cable or accessory, at a specified frequency, so as to verify that the finished product meets the specified requirements Tests made to demonstrate the integrity of the cable system as installed

Definitions

Where applicable, definitions are in line with IEC 60840 (Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements 2020) and IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020).

6.1.5.1 General Cable system

A cable system consists of cables with installed accessories. Cable accessories are typically joints and terminations. There may be other types of accessories associated with a cable system (e.g., measuring devices or fixtures). These need only to be incorporated in the test objects to the extent that they are deemed to have an impact on the operational characteristics of the cable system (continued)

430 Test object Return cable

Transmission cable Test loop Test set-up

LCC

VSC

B. Sanden A test object is a cable length or an accessory to be subjected to testing A return cable is the low/medium voltage DC cable used for the return current in monopolar operation of HVDC schemes. The return cable can either be connected over the full length between the converters or only be connected for part of the length connecting a converter to an electrode station A transmission cable refers to the high voltage cable of a monopolar or bipolar scheme. The term is used in this document where appropriate to distinguish from the return cable A test loop is a combination of series connected test objects simultaneously under test (Fig. 6.1) A test set-up is a combination of clearly separate test loops. A number of test loops may be simultaneously under test, possibly using same test equipment A HVDC system using Line Commutated Converters. LCC is a converter that has the feature of changing voltage polarity on the cable system when the direction of power flow is reversed IEC 60633 (Terminology for High Voltage Direct Current (HVDC) transmission 2019) A HVDC system using Voltage Source Converters. VSC is a converter that does not change the voltage polarity of the cable system when the direction of power flow is reversed CIGRE TB 289 (VSC Transmission 2005)

6.1.5.2 Test Objects Possible configuration of test objects in a test loop is shown in Fig. 6.1. Special definitions are described hereafter. Example of test loop

test object Termina on

minimum 5 m cable between Accessory test objects

test object Joint

0.5 m cable included in the Accessory test object

test object Joint minimum 5 m cable between Accessory test objects

Fig. 6.1 Possible configuration of test objects within a test loop

test object Termina on

test object Cable. Minimum 10 m.

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Recommendations for Testing DC Extruded Cable Systems for Power. . .

Extrusion length

Manufacturing length Delivery length

Factory joint Repair joint Field joint Transition joint CIGRE TB 177 (Accessories for HV cables with extruded insulation, CIGRE WG 26-06 2001)

431

An extrusion length is the length of cable conductor with the insulation and semiconducting layers continuously extruded in the same non-interrupted extrusion operation (excluding possible scrapped sections cut off from the starting and ending sections) A manufacturing length is a whole extrusion length (or parts thereof if cut), where construction elements (outside the outer semiconducting layer) have been applied A delivery length may be one or more manufacturing lengths joined with factory joints. A delivery length is typically the intended shipping length of a submarine cable or the completed cable length on a drum for a land cable A factory joint is a joint between extrusion lengths/manufacturing lengths that is manufactured under controlled factory conditions A repair joint is a joint between two cables that are completed with all construction elements A field joint is a joint between two cables that are completed with all construction elements and in a state as installed in the field in the actual cable system A transition joint in the context of this recommendation is a joint that connects the same type of insulation technology (extruded), such as jointing cables with different conductor cross-sections NOTE: Test on joints between extruded cables and other types of insulation technology (MI or oil filled) are not covered in this document. This should be agreed between supplier and customer. If special considerations are needed in case of transition joints between extruded cables, detailed agreements between supplier and customer are recommended

6.1.5.3 Test Voltages U0 UT UTP1

UTP2 UP1

UP2,S

UP2,O

Is the rated DC voltage between conductor and core screen for which the cable system is designed Is the DC voltage during the type test and routine test. For the scope of this recommendation UT ¼ 1.85  U0 Is the DC voltage during the prequalification test (load cycle test), type test (polarity reversal test) and test after installation. For the scope of this recommendation UTP1 ¼ 1.45  U0 Is the DC voltage during the prequalification polarity reversal test. For the scope of this recommendation UTP2 ¼ 1.25  U0 Is 1.15 x the maximum absolute peak value (Fig. 6.2) of the lightning impulse voltage, which the cable system can experience when the impulse has the opposite polarity to the actual DC voltage Is 1.15 x the maximum absolute peak value (Fig. 6.2) of the switching impulse voltage, which the cable system can experience when the impulse has the same polarity as the actual DC voltage Is 1.15 x the maximum absolute peak value (Fig. 6.2) of the switching impulse voltage which the cable system can experience when the impulse has the opposite polarity to the actual DC voltage (continued)

432 URC,AC

URC,DC

B. Sanden Is the maximum voltage a return cable can be subjected to due to temporary damped alternating overvoltage. This voltage is typically induced by a commutation failure, and the value should be supported by the supplier’s system calculations of the HVDC link. The nature of the overvoltage depends upon the configuration of the HVDC link and needs to be calculated for each case Is the max DC voltage in normal operation of the return cable

NOTES: The ripple content of the DC test voltages shall not be greater than 3% Calibration shall be according to IEC 60060-1 (High-voltage test techniques. Part 1: General definitions and test requirements 2010) The basis for the selection of test factors is described in Appendix A

sitive tive

ative itive

sitive

tive

Fig. 6.2 Schematic representations of the switching impulse and lightning impulse test voltages. Due to the constraints within the DC system design UP2,S does not necessarily equal UP2,O, i.e., the same polarity impulse is limited by surge arresters, but the opposite polarity impulse may be limited by the converter

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6.1.5.4 Thermal Cable Design Parameters Tcond, max

ΔTmax

Is the maximum temperature at which the cable conductor is designed to operate. This value is to be stated by the supplier Is the maximum temperature difference over the cable insulation in steady state (not including semiconducting screens) at which the cable is designed to operate. This value is to be calculated and stated by the supplier, who shall also provide evidence of the correlation between this design value and data measured during testing

6.1.5.5 Thermal Conditions for Tests The heating method used shall be conductor heating. The heating may be achieved by either DC or AC current, possibly in combination with external thermal insulation or cooling. The actual ΔT and Tcond during testing need to be demonstrated. Load cycles (LC)

High load (HL)

Zero load (ZL) Impulse test

Ambient temperature

Load cycles consist of both a heating period and a cooling period “24 hours” load cycles (for prequalification and type tests) consist of at least 8 hours of heating followed by at least 16 hours of natural cooling. During at least the last 2 hours of the heating period, a conductor temperature  Tcond, max and a temperature drop across the insulation  ΔTmax shall be maintained “48 hours” load cycles (for type test only) consist of at least 24 hours of heating followed by at least 24 hours of natural cooling. During at least the last 18 hours of the heating period, a conductor temperature  Tcond,max and a temperature drop across the insulation  ΔTmax shall be maintained. 48 hour load cycles are only required as part of the type test procedure to ensure that electrical stress inversion is well advanced within the cycle High load consists of a continuous heating period. Within the first 8 hours of the heating period conductor temperature  Tcond,max and temperature drop across the insulation  ΔTmax shall be achieved and maintained for the rest of the high load test NOTE: If, for practical reasons, the specified temperatures can not be reached within the first 8 hours, a longer time can be used. This additional time shall not be constituted as being part of the test period No heating is applied Conductor temperature  Tcond,max and temperature drop across the insulation  ΔTmax shall be reached for a minimum 10 hours before voltage impulses (superimposed impulse, switching, lightning) are applied and shall be maintained throughout the duration of the test Unless otherwise specified in the details for the particular test, tests shall be carried out at an ambient temperature of (20  15)  C

6.1.5.6 Conditions for Tests 6.1.5.6.1 Polarity Reversal Test (PR) The voltage and temperature conditions are defined in § 6.1.5.3 and 6.1.5.5 respectively. Starting with positive voltage, the voltage polarity shall be reversed three times every “24 hours” load cycle (evenly distributed) and one reversal shall coincide with the cessation of loading current in every “24 hours” load cycle. The recommended time duration for a polarity reversal is within 2 minutes.

434

B. Sanden

NOTE: If, for practical reasons, polarity reversals cannot be achieved within 2 minutes, the duration for polarity reversals shall be agreed between customer and supplier. 6.1.5.6.2 Superimposed Impulse Voltage Test Prior to the first impulse of each test the test object shall be heated so that the temperature conditions as defined in § 6.1.5.5 are achieved for at least 10 hours and the test object shall have been subjected to U0 (of the relevant polarity) for at least 10 hours. These conditions have been selected to reflect the electrical dynamics present within extruded insulations used for HVDC. Superimposed impulse voltage shall be applied according to the procedure given in Electra 189 (Recommendations for tests of power transmission DC cables for a rated voltage up to 800 kV (Electra 72, 1980 – revision) 2000). 6.1.5.6.3 Check on Insulation Thickness of Cable Prior to the electrical tests, the insulation thickness shall be measured by the method specified in IEC 60811-1-1 (Common test methods for insulating and sheathing materials of electric cables and optical cables – Part 1-1: Methods for general application – Measurement of thickness and overall dimensions – Tests for determining the mechanical properties 2001) on a representative piece of the length to be used for the tests, to check that the thickness is not excessive compared with the nominal value tn declared by the manufacturer. If the average thickness of the insulation does not exceed the nominal value by more than 5%, the test voltages shall be the values specified for the rated voltage of the cable. If the average thickness of the insulation exceeds the nominal value by more than 5% but not by more than 15%, the test voltage shall be adjusted by considering the following coefficient α to maintain the same level of average electric field, e.g., a 10% increase in average insulation thickness shall be accounted for by a 10% increase in the test voltage: t α¼ tn t ¼ measured average insulation thickness, tn ¼ declared nominal thickness. The cable length used for the electrical tests shall not have an average thickness exceeding the nominal value by more than 15%.

6.2

Development Tests

The manufacturer should complete all analyses and development testing prior to commencing the prequalification test. The precise nature and extent of development work and analyses shall be left to the discretion of the manufacturer, but may include the following:

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Fig. 6.3 Space charge measurements aiming at selecting insulating materials with advantageous space charge accumulation properties

– An evaluation of the materials and processes employed. Such evaluations would normally include electrical resistivity assessments, breakdown tests and space charge measurements. Example of space charge measurements is shown in Fig. 6.3. – An analysis of the electric stress distribution within the cable system insulation for a range of typical installation and loading conditions. – An assessment of the long-term stability, possibly involving factory experiments to assess the ageing effects of various parameters, e.g., electrical stress, temperature, environmental conditions, etc. – An assessment of the sensitivity of the electric stress distribution to the expected variations in cable dimensions, material composition and process conditions (extrusion, post extrusion treatments and finishing).

6.3

Prequalification Tests

6.3.1

Range of Approval

The prequalification test is intended to indicate the long-term performance of the complete cable system and should normally be completed after the development tests have been carried out. The prequalification test need only be carried out once, unless there is a substantial change in the cable system with respect to materials, manufacturing processes, construction or design parameters. Substantial change is defined as that which might adversely affect the performance of the cable system. The supplier shall provide a detailed case including test evidence if modifications are introduced, which are claimed not to constitute a substantial change.

436

B. Sanden

NOTE: It is the opinion of the WG that the CIGRE TB 303 (Revision of qualification for HV and EHV AC extruded underground cable systems, CIGRE WG B1.06 2006) can be regarded as a relevant document to assess the need for further prequalification testing or not. However, the HVDC extruded cable system technology is at present considered to be too immature to include the concept of “Extension of Qualification” in this document. The prequalification test qualifies the manufacturer as a supplier of cable systems provided that the following conditions are fulfilled: (a) The rated voltage U0 is not more than 10% higher than that of the tested cable system. (b) The calculated average electrical stress in the insulation (given by U0 divided by the nominal insulation thickness) is less than or equal to that of the tested system. (c) The calculated Laplace electrical stress at U0 (using nominal dimensions) at the cable insulation screen is less than or equal to that of the tested system. (d) The maximum conductor temperature Tcond,max is less than or equal to that of the tested system. (e) The maximum temperature drop across the insulation layer ΔTmax (excluding the semiconducting screens) is less than or equal to that of the tested system. (f) A cable system prequalified according to this recommendation for LCC is also prequalified for VSC. A cable system prequalified according to this recommendation for VSC is not prequalified for LCC. (g) An unarmored cable prequalified according to this recommendation prequalifies an armored cable and vice versa. NOTE 1: For the sake of clarity the conditions for range of approval do not involve considerations of DC electrical fields. In the design of DC cable systems, the DC electrical fields are critical design criteria. The supplier must therefore have detailed knowledge of the DC electrical fields in the cable system (cable and accessories) under all operating conditions and should be able to present a detailed case upon request of the customer. NOTE 2: It is recommended to carry out a prequalification test using a cable of a large conductor cross-section in order to cover thermo-mechanical aspects. NOTE 3: Prequalification tests that have been successfully performed according to TB 219 are valid. NOTE 4: At the end of a prequalification test an impulse test must be performed. The reason for this test is to verify that no major thermo-mechanical changes have taken place during the long-term testing. This test is not intended to qualify the system for a specific impulse level. Project-specific impulse levels should be qualified during the type test.

6.3.2

Summary of Prequalification Tests

Approximately 100 m of cable including complete accessories (at least one of each type) with a dielectric design suitable for practical applications shall be tested.

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437

Where appropriate mechanical preconditioning may be considered before starting the prequalification test. The normal sequence of tests shall be as follows: (a) Long duration voltage test (see § 6.3.4) (b) Superimposed impulse voltage test (see § 6.3.5) (c) Examination (see § 6.3.6)

6.3.3

Test Arrangement

Cable and accessories shall be assembled in the manner specified by the manufacturer’s instructions, with the grade and quantity of materials supplied, including lubricants if any. NOTE: The main objective of the prequalification test is to satisfactorily demonstrate the insulation integrity during long time periods under DC, given the long dielectric time constants as compared to AC. It is however recognized that other aspects of a specific installation may be important, such as the thermo-mechanical effects due to the installation conditions. The representation of specific installation conditions in the test set-up should be considered. Prior to the electrical prequalification test, the insulation thickness of the cable shall be checked as specified in § 6.1.5.6.3.

6.3.4

Long Duration Voltage Test

General: (a) Minimum duration is 360 days. (b) Conductor temperature and temperature difference across the insulation shall both be controlled to the design level. Design levels in accessories and adjacent cables may differ. The sequence of tests for LCC and VSC are shown in the tables below. Line commutated converter, LCC LC Number of cycles or days Test voltage

LC

LC þ PR

HL

HL

ZL

LC

LC

LC þ PR

S/IMP

30 30 20 40 40 120 30 30 20 Not applicable cycles cycles cycles days days days cycles cycles cycles + UTP1

 UTP1

UTP2

+   + UTP1 UTP1 UTP1 UTP1

 UTP1

UTP2

UP2,O ¼ 1.2  U0 UP1 ¼ 2.1  U0a

LC ¼ Load Cycle, HL ¼ High Load, PR ¼ Polarity Reversal, ZL ¼ Zero Load, S/IMP¼Superimposed Impulse Test a If required

438

B. Sanden

Voltage source converter, VSC

Number of cycles or days Test voltage

LC 40 cycles

LC 40 cycles

HL 40 days

HL 40 days

ZL 120 days

LC 40 cycles

LC 40 cycles

S/IMP Not applicable

+ UTP1

 UTP1

+ UTP1

 UTP1

 UTP1

+ UTP1

 UTP1

UP2,O ¼ 1.2  U0 UP1 ¼ 2.1  U0a

LC ¼ Load Cycle, HL ¼ High Load, ZL ¼ Zero Load, S/IMP¼Superimposed Impulse Test a If required

Sects. 6.1.5.5 and 6.1.5.6 provide guidance on test conditions. NOTE: Ambient conditions may vary during the test and this is not considered to have any major influence. In such cases, the conductor current shall be adjusted to maintain the conductor temperature and temperature drop across the insulation within the specified limits. The length and sequence of the thermal conditions were selected with regard to the particular electrical effects that can occur in extruded insulations when operated under DC voltage. The technical basis for the test durations is given in Appendix A. A minimum rest period of 24 hours without voltage, but with heating, is recommended between blocks of different polarities. This does not apply to the individual polarity reversals in the PR blocks of the LCC test scheme.

6.3.5

Superimposed Switching Impulse Voltage Test

It is the opinion of the WG that the prequalification test should not be evaluated on the basis of the impulse level. The aim of the superimposed impulse test after the long duration test is only to check the integrity of the insulation system. Evaluation of available specifications for different projects show that the values of UP2,Oand UP1 vary between the different projects. In this respect, and based on the recorded experience, the impulse voltage values to be considered for the prequalification test have been defined as follows: UP2,O ¼ 1.2  U0 UP1 ¼ 2.1  U0 (if required) Project specific requirements regarding impulse levels should be covered by the electrical type test (§ 6.4.4). The test shall be performed according to § 6.1.5.6.2 on one or more cable samples, with a minimum total active length of 30 m cut from the assembly. The temperature conditions are defined in § 6.1.5.5. NOTE: As an alternative, the test may be carried out on the whole test assembly. The cable samples shall withstand without failure 10 positive and 10 negative superimposed switching impulses at the voltage levels UP2,O.

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If by agreement between supplier and customer a lightning impulse test is also to be performed, the cable samples shall withstand without failure 10 positive and 10 negative superimposed lightning impulses at the voltage level UP1.

6.3.6

Examination

Examination of the cable by dissection of a sample and, whenever possible, of the accessories by dismantling, with normal or corrected vision without magnification, shall reveal no signs of deterioration (e.g., electrical degradation, leakage, corrosion, or harmful shrinkage) which could affect the system in service operation.

6.3.7

Success Criteria, Re-Testing and Interruptions

The criteria for a successful outcome of the prequalification test are that all tests shall have been performed without breakdown of that test object and that the system examination is in accordance with § 6.3.6. If there is a breakdown in a test object, the complete prequalification test shall be repeated for that particular test object. If a breakdown of a test object occurs, causing an interruption to the ongoing testing of connected test objects, the test may be resumed after the failed test object is removed. The actual load cycle or impulse during which the failure occurred shall be repeated for the remaining test objects. If breakdown occurs during a constant load period, the time elapsed without voltage applied shall be added to the remaining test period. After any interruption, for example an interruption caused by external factors the test may be resumed. If the interruption is longer than 30 min, the specific lost load cycle shall be repeated. If the interruption occurs during a constant load period and is longer than 30 min, the day the interruption occurred shall be repeated.

6.4

Type Tests

6.4.1

Range of Approval

The type approval shall be accepted as valid for cable systems supplied within the scope of this recommendation if the following conditions are fulfilled: (a) The actual designs, materials, manufacturing processes and service conditions for the cable system are in all essential aspects equal. (b) All service voltages, U0, UP1, UP2,S, and UP2,O (URC,AC and URC,DC in case of return cable), are less than or equal to those of the tested cable system. (c) The mechanical stresses to be applied during preconditioning are less than or equal to those of the tested cable system.

440

B. Sanden

(d) The service maximum conductor temperature Tcond,max is less than or equal to that of the tested cable system. (e) The maximum temperature drop across the insulation layer ΔTmax (excluding the semiconducting screens) is less than or equal to that of the tested cable system. (f) The actual conductor cross-section is not larger than that of the tested cable system. (g) The calculated average electrical stress in the insulation (given by U0 divided by the nominal insulation thickness) is less than or equal to that of the tested system. (h) The calculated Laplace electrical stress (using nominal dimensions) at the cable conductor and insulation screen is less than or equal to that of the tested system. (i) A cable system qualified according to this recommendation for LCC is also qualified for VSC provided the switching impulse withstand tests at UP2,S voltage levels as specified in § 6.4.4.3.3 are carried out. A cable system qualified according to this recommendation for VSC is not qualified for LCC. NOTE 1: For the sake of clarity the conditions for range of approval do not involve considerations of DC electrical fields. In the design of DC cable systems, the DC electrical fields are critical design criteria. The supplier must therefore have detailed knowledge of the DC electrical fields in the cable system (cable and accessories) under all operating conditions and should be able to present a detailed case upon request of the customer. NOTE 2: Type tests which have been successfully performed according to TB 219 are valid. The non-electrical type tests (see § 6.4.3) need not be carried out on samples from cables of different voltage ratings and/or conductor cross-sectional areas unless different materials and/or different manufacturing processes are used to produce them. However, repetition of the ageing tests on pieces of complete cable to check compatibility of materials (see IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020)) may be required if the combination of materials applied over the screened core is different from that of the cable on which type tests have been carried out previously.

6.4.2

Test Objects

All components of the cable system (cable and accessories) shall be subjected to type testing. It is acceptable to test different parts of a system in different test loops. However, these test loops must cover all relevant cable system components. By definition, an accessory includes 0.5 m of cable on each side (Fig. 6.1), measured from the point on the cable where no disassembling or dismantling for the purpose of installation of the accessory has taken place. The non-interrupted cable length between accessories (Fig. 6.1) in a test loop shall be a minimum of 5 m. A minimum of 10 m of continuous non-interrupted cable shall be included in a test loop.

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Any non-continuous design feature (such as a metallic connection between metallic layers) shall be included in the cable test object. Test objects for land or submarine application shall be subjected to the appropriate mechanical preconditioning. Test objects for the electrical and non-electrical type tests must not necessarily be the same physical samples unless required by the recommendation for the non-electrical test.

6.4.3

Non-Electrical Type Tests

The cable system shall be subjected to the applicable non-electrical type testing as specified in IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). The test program shall be agreed between supplier and customer. Cable systems intended for installation on land where water blocking is included shall be subjected to a water penetration test as specified in IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). Cable systems intended to be installed as submarine cables shall be subjected to water integrity testing as specified in Electra 189 (Recommendations for testing of long AC submarine cables with extruded insulation for system voltage above 30 (36) to 150 (170) kV 2000). This test would also qualify the cable for installation on land. Cables with metallic earthing connections through plastic sheaths shall be subjected to the test in Electra (Recommendations for tests of power transmission DC cables for a rated voltage up to 800 kV (Electra 72, 1980 – revision 2000).

6.4.4

Electrical Type Test

The principal overview of the electrical type tests is described in Appendix C. Prior to the electrical type test, the insulation thickness of the cable shall be checked as specified in § 6.1.5.6.3.

6.4.4.1 Mechanical Preconditioning Before Electrical Type Test The intent of mechanical preconditioning is to subject the test objects to the maximum mechanical stress that the cable system will experience during handling, installation and recovery. Consequently the factory joints and repair joints for submarine cables shall be included, but field joints for land cables are not to be included. Cable systems to be installed on land shall be subjected to mechanical preconditioning (bending) as specified in IEC 62067 (Power cables with extruded

442

B. Sanden

insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). Cable systems intended to be installed as submarine cables shall be subjected to mechanical tests as specified in Electra 171 (Recommendations for mechanical tests on submarine cables 1997).

6.4.4.2 Load Cycle Test 6.4.4.2.1 General The load cycle test shall be performed on test objects that have been subjected to the appropriate mechanical preconditioning. Accessories in the cable system that are not relevant for mechanical preconditioning are to be installed as test objects together with the preconditioned test objects. The temperature conditions are defined in § 6.1.5.5. If the test loop consists of cables with different designs connected with a transition joint, then each cable design is qualified to the relevant thermal conditions (Tcond,max and ΔT) and the transition joint is qualified to the higher temperature. (Note that this means that the cable on one side of the transition joint under test may not have been qualified in this test to its maximum temperature in the scheme). 6.4.4.2.2 Load Cycle Test for Cable System to Be Qualified for LCC The test objects shall be subjected to the following conditions (definitions of “24 hours” load cycles and “48 hours” load cycles are described in § 6.1.5.5): – – – –

Eight “24 hours” load cycles at negative polarity at UT Eight “24 hours” load cycles at positive polarity at UT Eight “24 hours” load cycles with polarity reversal cycles at UTP1 Three “48 hours” load cycles at positive polarity at UT

A minimum rest period of 24 hours without voltage but with heating is recommended between blocks of different polarities. This does not apply to the individual polarity reversals in the PR blocks. Positive polarity was selected for the “48 hours” load cycles as this is believed to be the most stringent condition for accessories. 6.4.4.2.3 Load Cycle Test for Cable System to Be Qualified for VSC The test objects shall be subjected to: – Twelve “24 hours” load cycles at negative polarity at UT – Twelve “24 hours” load cycles at positive polarity at UT – Three “48 hours” load cycles at positive polarity at UT A minimum rest period of 24 hours without voltage but with heating is recommended between blocks of different polarities.

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Positive polarity was selected for the “48 hours” load cycles as this is believed to be the most stringent condition for accessories.

6.4.4.3 Superimposed Impulse Voltage Test 6.4.4.3.1 General The superimposed impulse voltage test is to be performed on test objects that have successfully passed the load cycle test. § 6.1.5.6.2 describes the test procedure. 6.4.4.3.2

Switching Impulse Withstand Test for Cable System to Be Qualified for LCC – The test object at U0, 10 consecutive impulses to -UP2,O – The test object at -U0, 10 consecutive impulses to UP2,O 6.4.4.3.3 – – – –

Switching Impulse Withstand Test for Cable System to Be Qualified for VSC The test object at U0, 10 consecutive impulses to UP2,S The test object at U0, 10 consecutive impulses to -UP2,O The test object at -U0, 10 consecutive impulses to -UP2,S The test object at -U0, 10 consecutive impulses to UP2,O

6.4.4.3.4 Lightning Impulse Withstand Test If the intended installation of the cable system is such that it is not exposed to lightning strikes (direct or indirect), these tests need not be done. – The test object at U0, 10 consecutive impulses to -UP1 – The test object at -U0, 10 consecutive impulses to UP1 6.4.4.3.5 Subsequent DC Test After the successful completion of the impulse testing the test object shall be subjected to 2 hours at a negative DC voltage of UT, no heating. A rest period prior to this test is acceptable.

6.4.4.4 Test of Outer Protection for Joints Cable joints intended for burial on land shall be subjected to the outer protection test specified in § 12.4 in IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). 6.4.4.5 Examination 6.4.4.5.1 Cable and Accessories Examination of the cable by dissection of a sample and, whenever possible, of the accessories by dismantling, with normal or corrected vision without magnification,

444

B. Sanden

shall reveal no signs of deterioration (e.g., electrical degradation, leakage, corrosion or harmful shrinkage) which could affect the system in service operation. 6.4.4.5.2

Cables with a Longitudinally Applied Metal Tape or Foil, Bonded to the Oversheath A 1 m sample shall be taken from the cable length and subjected to the tests and requirements in IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020).

6.4.4.6 Success Criteria, Re-Testing, and Interruptions The criteria for a successful outcome to the type test are that all tests have been performed without breakdown of that test object and that all other non-electrical requirements have been complied with. After any interruption, for example an interruption caused by external factors the test may be resumed. If the interruption is longer than 30 min, the specific lost load cycle shall be repeated. If the interruption is longer than 24 hours, the actual test block (“24 hours” load cycles block at negative or positive polarity, “24 hours” load cycles block with polarity reversals, “48 hours” load cycles block under positive polarity) shall be repeated. In case of deviations in test parameters during load cycles or superimposed impulse voltage test, the load cycle or the superimposed impulse in question shall be repeated. In case of a breakdown of insulation, when testing several objects simultaneously, the faulty object may be removed and the incident treated as an interruption. The faulty object is considered to have failed the test requirements. Any fault within any extension (0.5 m) to a test object, for example an accessory, is considered to be associated with that test object only.

6.4.5

Return Cable Type Test

6.4.5.1 General Return cables are grounded at one end and are subjected to a DC voltage determined by the cable resistance and the current at the other end of the link. System calculations, taking into account the different fault scenarios, should be performed by the supplier to determine the relevant temporary over-voltages in the power frequency domain for the return cable for the actual link. In particular, temporary over-voltages caused by commutation failure may be the criteria for dimensioning of the return cable insulation and accessories. To verify that the cable system can withstand overvoltages caused by commutation failure an AC voltage test at power frequency shall be performed. If different designs (different insulation thicknesses) are used along the return path, each design shall be considered individually.

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445

Return cables may be protected by surge arresters, in which case this feature shall be taken into consideration in the system studies and consequently in determining URC,AC.

6.4.5.2 Mechanical Preconditioning The Return Cable test object shall be subjected to mechanical preconditioning according to §6.4.4.1, as applicable. 6.4.5.3 Thermo-Mechanical Preconditioning After mechanical preconditioning, the return cable test object shall be subjected to thermo-mechanical preconditioning, consisting of 24 daily load cycles (“24 hours” load cycles as per § 6.1.5.5 without the requirement of ΔTmax). During the execution of this preconditioning the relevant thermal properties for the return cable shall be fulfilled according to the principles stipulated in § 6.4.4.2.1. No voltage needs to be applied. 6.4.5.4 AC Voltage Test After the mechanical and thermo-mechanical preconditioning, the return cable test object shall be subjected to an AC test at a power frequency voltage of 1.15 x URC,AC at ambient temperature. The voltage shall be applied for 30 minutes. 6.4.5.5 Lightning Impulse Withstand Test If applicable, the return cable test object shall be subjected to a lightning impulse withstand test with the relevant test voltages and according to the principles given in § 6.4.4.3.4. 6.4.5.6 Cable Design with Integrated Return Conductor If the Transmission Cable is such that the return path is integrated, the return path function should be tested together with the Transmission Cable in an integrated test program. The test program shall be agreed between customer and supplier.

6.5

Routine Tests

Routine tests (which include what is in some other documents referred to as Factory Acceptance Test) are made to demonstrate the integrity of the delivery lengths.

6.5.1

Routine Tests on Transmission Cables

Every delivery length of cable shall be submitted to a negative DC voltage equal to the test voltage defined for the load cycle test UT and applied between conductor and sheath for 1 hour. The experience of using DC voltage for routine testing of extruded DC cables is limited. It is the opinion of the WG that in addition to the DC test, testing with AC

446

B. Sanden

voltage could be considered provided that the insulation system and the cable design allow AC testing. Long manufacturing lengths and high voltage levels may render AC testing impractical. In the event that AC testing is employed, the voltage level, frequency (power or other frequencies) and time of application shall be agreed between the supplier and customer. If required for the particular contract or order, the oversheath may be subjected to the routine electrical test specified in IEC 60229 (Tests on cable oversheaths which have a special protective function and are applied by extrusion 2007).

6.5.2

Routine Tests on Cable Accessories

The experience of using DC voltage for routine testing of accessories for DC cables is limited and the efficiency of DC testing for prefabricated joints and terminations is arguable and has not been proven so far. It is the opinion of the WG that the DC test could be in principle a necessary test; however it may not be sufficient to prove the quality of the accessory, e.g., the presence of voids in the insulation molding. Testing with AC voltage could be considered as an integration or alternative test, provided that the insulation system and the cable design allow AC testing.

6.5.2.1 Tests on Prefabricated Joints and Terminations Prefabricated joints are generally used for the DC land cable connections while the terminations are used for land and submarine connections. The DC test voltage applied to the main insulation of each individual prefabricated accessory shall be as specified under § 6.5.1. The following additional tests may be carried out according to the quality assurance procedures of the manufacturer: – AC voltage test, if applicable – PD measurement, if applicable

6.5.2.2 Tests on Factory Joints of Submarine Cables Factory joints are generally used for long lengths of submarine cable. There are at least four possible methods available today for checking the quality of the factory joint insulation system: – – – –

DC test AC voltage test, if applicable PD measurement, if applicable X-ray inspection

The AC voltage test and the partial discharge measurement may be carried out if applicable to the cable insulation system. The procedure and requirement for these tests will be in accordance with the quality assurance procedures of the

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447

manufacturer. X-ray inspection gives additional information regarding the quality of interfaces and possible metallic inclusions. All joints in the complete delivery length shall be DC voltage tested in the high voltage test described in §6.5.1. However, a screening DC or AC voltage test directly after jointing would reduce the time delay in case the joint were to fail at a later stage in the production process. In addition, it is recommended that each welded conductor joint be checked by an X-ray inspection. Even if each factory joint is routine tested, the joint must be installed by experienced personnel. It is recommended that the supplier show qualification records of jointers.

6.5.2.3 Tests on Repair Joint for Submarine Cables Depending on the joint construction it may be difficult to test the whole joint after installation. If the joint consists of pre-fabricated insulation components for which it is possible to routine test prior to installation, the procedures described in § 6.5.2.1 shall be followed, as closely as possible and according to agreement between supplier and customer. If the joint is not built up by any pre-fabricated components, the manufacturer and customer shall agree on the most practical solution, if any, to check the quality of the repair joint after installation.

6.5.3

Return Cables or Conductors

Every delivery length of cable shall be submitted to a voltage test applied between conductor and sheath. AC testing is to be preferred for the testing of return conductors. The voltage level and time of application shall be agreed between the supplier and customer. Long manufacturing lengths and high voltage levels may, however, render AC testing impractical. In this case a suitable DC voltage, agreed between supplier and customer, shall be applied. It is recommended that the DC test voltage be no lower than the highest of either 2.5  URC,DC, or 25 kV, the voltage shall be applied between conductor and sheath for 1 hour.

6.6

Sample Tests

Cables and certain types of cable accessories shall have tests carried out on samples.

6.6.1

Sample Tests on Transmission Cables

For the tests in this section, refer to the respective IEC specification for AC extruded power cables IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020), except where not differently specified. NOTE: For materials which are not considered by IEC 60840 and IEC 62067, the test program shall be agreed between manufacturer and customer.

448

B. Sanden

6.6.1.1 Frequency of Tests The frequency of tests shall be according to IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). 6.6.1.2 Conductor Examination Refer to IEC 62067. 6.6.1.3 Measurement of Electrical Resistance of Conductor Refer to IEC 62067. 6.6.1.4 Measurement of Capacitance Refer to IEC 62067. 6.6.1.5 Measurement of Thickness of Insulation and Non-metallic Sheath Refer to IEC 62067. 6.6.1.6 Measurement of Thickness of Metallic Sheath Refer to IEC 62067. 6.6.1.7 Measurement of Diameters, if Required Refer to IEC 62067. 6.6.1.8 Measurement of Density of HDPE Insulation, if Applicable Refer to IEC 62067. 6.6.1.9 Impulse Voltage Test Test procedures and requirements shall be according to § 6.4.4.3.4 or § 6.4.4.3.2 and 6.4.4.3.3 if the intended installation of the cable system is such that it is not exposed to lightning strikes (direct or indirect)]. 6.6.1.10 Water Penetration Test, if Applicable Refer to IEC 62067. 6.6.1.11 Tests on Components of Cables with Longitudinally Applied Metal Tape or Foil, Bonded to the Oversheath, if Applicable Refer to IEC 62067.

6.6.2

Sample Tests on Factory Joints for Submarine Cables

For DC submarine cable systems it is recommended to test each manufactured length and each factory joint under the routine tests described in § 6.5.1 and 6.5.2.2. Since routine tests check the quality of the entire submarine cable system itself, the sample tests listed in § 6.6.2.1, 6.6.2.2, 6.6.2.3 and 6.6.2.4 shall be performed on one factory core joint only, prior to starting manufacture of the joints. A sample of at least 10 m of cable and a factory joint shall be prepared for the tests.

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Recommendations for Testing DC Extruded Cable Systems for Power. . .

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If the factory joint is type tested under the contract, the tests in § 6.6.2.1, 6.6.2.2, 6.6.2.3 and 6.6.2.4 may be omitted.

6.6.2.1 Tensile Test A tensile test of the conductor joint shall be performed according to manufacturer specification. The tensile force applied in the conductor shall not be lower than the design value. 6.6.2.2 PD Measurement and AC Voltage Test This test shall be carried out only if applicable to the insulation system. The test must be performed after restoring the outer semiconductive layer and the metallic ground conductor or outer sheath. The PD-measurement and the AC voltage test shall be performed in accordance the manufacturer quality assurance procedures. 6.6.2.3 Impulse Voltage Test Test procedures and requirements according to § 6.4.4.3.4 or § 6.4.4.3.2 and 6.4.4.3.3 if the intended installation of the cable system is such that it is not exposed to lightning strikes (direct or indirect). 6.6.2.4 Hot Set Test for Insulation Where Applicable Refer to IEC 62067 § 10.9 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020). 6.6.2.5 Pass Criteria If a factory joint fails in any of the tests listed above, two additional joints shall be tested successfully.

6.6.3

Sample Tests on Repair Joints and Terminations

Sample tests are not applicable for repair joints and terminations for submarine cable systems. The terminations as well as the repair joints will be routine tested according to § 6.5.2.1 and 6.5.2.3.

6.6.4

Sample Tests on Field Molded Joints

Field molded joints may be used for DC cable land connections. This kind of joints cannot be routine tested and the sample test sequence with the frequency and procedure as requested by the IEC 62067 (Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements 2020) is recommended. The same tests as prescribed in the § 6.5.2.2 are applicable.

450

B. Sanden

6.7

After Installations Tests

6.7.1

High Voltage Test

The installed HV cable system shall be subjected to a negative polarity DC voltage of UTP1. The test duration shall be 1 hour. The installed return cable system shall be subjected to a negative polarity DC voltage that has been agreed between the supplier and the customer. The test duration shall be 1 hour. Negative polarity shall be used regardless of the polarity of the pole.

6.7.2

Test on Polymeric Sheaths

For underground cables electrical testing of the outer sheath subsequent to laying should be considered. If appropriate, the test shall be performed according to IEC60229.

6.7.3

TDR Measurement

A TDR (Time Domain Reflectometry) measurement could be performed for engineering information. If TDR equipment is to be used with the cable link it is advisable to perform a TDR measurement to obtain a “fingerprint” of the wave propagation characteristics of the cable. The propagation of the pulses used during TDR measurements is dependent upon resistance, capacitance and inductance of the cable (Fig. 6.4). As all electrical signals travel so as to consume a minimum of energy, the pulse propagates where the inductance/resistance is its lowest. Submarine power cables have a metallic screen and the pulses do not propagate outside the screen since the inductance (and impedance) would increase considerably. Hence the pulse is not affected by the coiling on a turntable or after installation.

Fig. 6.4 Circuit diagram for TDR testing, traditional transmission line diagram, π-model

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Appendices Appendix A: Derivation of Test Parameters DC Voltage Factors The multiplication factors for the test voltages and periods have been determined based on consideration of the available voltage-time (V-t) characteristics. The precise nature of the V-t characteristic has not been determined for DC operation. However the WG was of the opinion that the Inverse Power Law model provided a conservative basis for the work. The precise details of the approach are shown below: V n  t ¼ const where: V: voltage t: time n: life exponent from V-t characteristics Test voltage Vdc is: V dc ¼ V 0  K 1 where: V0: system voltage K1: test voltage ageing factor

K1 ¼

n

t0 t1

where: t0: design life t1: test duration Using the approach described above it is possible to determine the test voltage factors that are equivalent to a prescribed system life when testing for a shorter time. In this work the WG has used a system life of 40 years. The approach requires knowledge of the exponent “n” which is determined empirically from endurance tests on cables. The knowledge of “n” under DC was not sufficient for the WG to identify a precise value at the time this brochure was written. However the WG was able to estimate a lower limit (n ¼ 10), which was used to determine the test voltage factor.

452

B. Sanden

Prequalification test 40 360

Design life, t0 (years) Test duration, t1 (days) Test voltage aging factor, K1

10

Test factor

Type test 40 30

40  365=360

10

1.45

40  365=30

1.85

On this basis the WG identified a test factor of 1.45 as equivalent to approximately 40 years operation at rated voltage when applied for 1 year and a test factor of 1.85 as equivalent to approximately 40 years operation at rated voltage when applied for 30 days.

Impulse In the light of the good experience which has resulted from the use of the previous Electra recommendations within (Recommendations for tests of power transmission DC cables for a rated voltage up to 800 kV (Electra 72, 1980 – revision) 2000; Recommendations for tests on DC cables for a rated voltage up to 550 kV 1974; Recommendations for tests of power transmission DC cables for a rated voltage up to 600 kV 1980) it was decided that the same approach to selection of test factors would be applied. Polarity Reversal The approach for test factors is based on the principle of applying the same additional voltage for the polarity reversal as that applied for the constant voltage test. This approach has been used in previous DC recommendations. The table sets out previous practice relating the polarity reversal tests and the used test factors. For example: at a polarity reversal in real operation, the cable system experiences a voltage step of 2  U0. Applying a test factor of 1.45 in a polarity reversal test gives that the cable system under test experiences a voltage step of 2  1.45  U0 ¼ 2.9  U0, i.e., 0.9  U0 more than in real operation.

Document Electra 32 (Recommendations for tests on DC cables for a rated voltage up to 550 kV 1974) Type test

Test Condition factor Test voltage

Constant voltage Polarity reversal Electra 72 (Recommendations for Constant tests of power transmission DC voltage cables for a rated voltage up to Polarity 600 kV 1980) Type test reversal Electra 189 (Recommendations Constant for tests of power transmission voltage DC cables for a rated voltage up to Polarity 800 kV (Electra 72, reversal 1980 – revision) 2000) Type test

Additional voltage during test vs. operation

2

2  U0

U0

1.5

2  (1.5  U0)

U0

2

2  U0

U0

1.5

2  (1.5  U0)

U0

1.8

1.8  U0

0.8  U0

1.4

2  (1.4  U0)

0.8  U0

Comment

Test in Cold condition

(continued)

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Recommendations for Testing DC Extruded Cable Systems for Power. . .

Test Condition factor Test voltage

Document CIGRE TB 219 (CIGRE TB 219 2003) Type test

CIGRE TB 219 (CIGRE TB 219 2003) Prequalification test This recommendation: Type test

This recommendation: Prequalification test

Constant voltage Polarity reversal Constant voltage Polarity reversal Constant voltage Polarity reversal Constant voltage Polarity reversal

Additional voltage during test vs. operation 0.85  U0

1.85

1.85  U0

1.45

2  (1.45  U0) 0.9  U0

1.45

1.45  U0

1.25

2  (1.25  U0) 0.5  U0

1.85

1.85  U0

1.45

2  (1.45  U0) 0.9  U0

1.45

1.45  U0

1.25

2  (1.25  U0) 0.5  U0

0.45  U0

0.85  U0

0.45  U0

453

Comment Test in hot Condition

Test in hot Condition

Test in Hot condition

Test in hot Condition

Duration of Tests: Prequalification & Type Tests The field distribution within a DC power cable system in operation differs from the Laplace field due to the fact that the conductivity of the insulation depends on its temperature (which decreases from the conductor to the sheath) and on the local electric field. These phenomena generate a divergence, which is in addition to that derived from the cable geometry. The evolution of the additional divergence can be represented as a function of a dimensionless parameter t/τ where τ is the “time constant.” In the table below, ρ is the volume resistivity and ε the permittivity. Calculations show that a time equivalent to 10 τ must pass to approach the steady state distribution of the divergence. The table below gives the range of times to stability (10 τ) as a function of temperature for different materials that are likely to be used for DC extruded cables. Practically, this means that the time to achieve a stable electrical stress distribution will depend upon temperature. Thus, it is important to select test times that permit probable insulation systems to reach a stable electrical stress distribution. These considerations provide the foundations for the times of the Zero Load, High Load and 48 hours Load Cycle Tests in the recommendations. Temperature ( C)

ε (F/m)

ρ (Ω.m)

Time for stability, 10 τ (hours)

20 60 90

2  1011 < ε < 3  1011 2  1011 < ε < 3  1011 2  1011 < ε < 3  1011

1015 < ρ < 5  1016 2  1013 < ρ < 5  1014 1012 < ρ < 5  1013

55 < 10 τ < 4300 1 < 10 τ < 43 0.06 < 10 τ < 4.3

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B. Sanden

Injection of charges from the electrodes may also occur, but the 10 τ time constant covers the time needed for these injection processes to reach a steady state. In addition, considering the actual usage of HVDC links, the experimentation constraints and the total time of the tests the WG adopted the following testing times. The WG judged that they would “test” the performance of the proposed HVDC insulation systems in a practical manner (Aladenize et al. 1997, 1999): Condition Zero load (prequalification) 48 hour load cycle: (type approval)

Temperature Ambient temperature (20  15  C) At least maximal conductor temperature (60–90  C depending on manufacturer design)

Testing time (Days) At least 120

Time for stability, 10 τ (Days) 2.3 < 10 τ < 180

1 (heating period)

0.003 < 10 τ < 1.8

It is the opinion of the WG that higher resistivity materials may be developed in the future and therefore that it may become necessary to review the duration of the test cycles.

Appendix B: Technical Basis for the Detailed Prequalification Test Schemes The development of the detailed technical test schemes described in § 6.3.4 has been guided by the following principles: 1. Minimum duration is 360 days. 2. Conductor temperature and temperature difference across the insulation, for part of the test loop, shall both be controlled to the design level within the loading portions of the test. 3. The tests shall commence with a minimum of 60 “24 hours” load cycles (see § 6.1.5.5) at UTP1 for thermo-mechanical conditioning. 4. There shall be, in total, a minimum of 120 “24 hours” load cycles. For LCC, a minimum of 80 “24 hours” load cycles shall be at UTP1 and a minimum of 40 “24 hours” load cycles with polarity reversals at UTP2. 5. There shall be a minimum of 30 consecutive days under constant high load (see § 6.1.5.5) at positive polarity UTP1. 6. There shall be a minimum of 30 consecutive days under constant high load (see § 6.1.5.5) at negative polarity UTP1. 7. There shall be a minimum of 120 consecutive days with zero load (see § 6.1.5.5) at negative polarity UTP1. 8. The test shall be completed with a superimposed impulse voltage test (see § 6.1.5.6.2 and 6.3.5).

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Recommendations for Testing DC Extruded Cable Systems for Power. . .

Appendix C: Schematic Representation of the Sequence of Tests for Land and Submarine Cables Principal overview of electrical type tests

Submarine cables Tensile bend test Electra 171 [13]

Land cables Bend test IEC 62067 [4]

LCC Load Cycling (§ 6.4.4.2.2)

VSC Load Cycling (§ 6.4.4.2.3)

LCC Switching (§ 6.4.4.3.2)

VSC Switching (§ 6.4.4.3.3)

Lightning (§ 6.4.4.3.4)

Subsequent DC (§ 6.4.4.3.5)

455

Not defined

100m including accessories 360days, 1.45xU0 Different procedures for LCC & VSC Load Cycle Test (min 120) High Load Test Zero Load Test Superimposed LI Test

Non-electrical Test Mechanical Pre-conditioning 30 days 1.85xU0 (rest periode of 24h recommended with heating) Different procedures for LCC & VSC Load Cycle Test Superimposed Lightning Impulse Test Subsequent DC Test

Delivery Length DC Test : 1.85xU0x15min AC test (optional)

According to IEC 60840

High Voltage Test : -1.45xU0x15min Test on Polymeric Sheaths : according to IEC 60229 TDR for information

Prequalification Test

Type Test

Routine Test

Sample Test

After Installation Test

DC voltage test : 1.4xU0, 15min.

High-voltage test : 1.8xU0, 15min. Conductor resistance test Capacitance test Power factor test Factory acceptance test : 1.8xU0, 15min.

1.8xU0x10 (rest periode min 8 hours, no heating & short circuit) Polarity reversal test (after LC) : 1.4xU0x60, every 4h, 10 l.c. Superimposed impulse test :U0+1.15Imp, U0-1.15Imp

Load cycle test : +1.8xU0x10,-

Not defined

Evaluation of material and processes Evaluation of Weibullparameters Determination of “n”

Tests shall be at the discretion of the manufacturer.

Development Test

1.7xU0 1h or voltage dependent factor 1h

DC voltage test (oversheath) AC voltage test (insulation): U0 24h or

245kV ~2xU0 at 500kV) Electrical test on oversheath

Partial discharge test Voltage test (voltage dependent, ~2.3xU0 at

Bending test Partial discharge test Tanδ measurement Load Cycle Test: 2xU0 x 20, 24h Switching impulse voltage test Lightning impulse

Load cycle Test : 1.7U0, 1year : 180 heating cycles Lightning impulse voltage test : 10 positive, 10 negative

IEC 62067 AC500kV, Extruded AC cable

CIGRE Electra 189, 2000 DC800kV, Paper-insulated DC cable

CIGRE TB219 Extruded DC cable

Cables with Extruded Insulation and Their Accessories for Rated Voltages above 150kV up to 500kV

Recommendations for Tests of Power Transmission DC Cables for A Rated Voltage up to 800kV

Recommendations for Testing DC Extruded Cable System for Power Transmission at a rated voltage up to 250 kV

DC voltage test (oversheath) AC voltage test (insulation): U0 24h or or voltage dependent factor 1h

Partial discharge test Voltage test: 2.5xU0, 30 min Test of oversheaths

Bending test Partial discharge test Tanδ measurement Load Cycle Test: 2xU0 x 20, 24h Switching impulse voltage test Lightning impulse

Not defined

Not defined

IEC 60840 Extruded AC cable

Cables with Extruded Insulation and Their Accessories for Rated Voltages above 30kV up to150kV

: 1.0xU0, 24hours

AC voltage test : 1.7xU0, 90min.

On manufacturing length High voltage test Partial discharge test on factory installed joints Factory acceptance High voltage test TDR

Mechanical test Water penetration test Conductor penetration Outer sheath penetration Partial discharge test Loss angle measurement Load cycle test = IEC 60840 Partial discharge test Ligthning Impulse test

Not defined

Not defined

CIGRE Electra 189, 2000, AC 150kV, Extruded AC Submarine Cable JEC 3408, 1997 Extruded AC cable

1.9U0 at 400kV)

Voltage test: voltage dependent (2.5 U0 at 220kV -

Long term AC test with heat cycles (voltage level not clearly defined) Impulse test AC test

(Based on 30 years lifetime, n=15 for cable, n=12 for taped joint)

30 days, Utest=k1xU0 k1=1.48 cable, k1=1.64 taped joint

Not defined as "Prequalification test" in this standard but "Development test" has the same purpose as PQ test.

0.5 years, Utest =k1xU0 Evaluation of material and processes k1=1.32 cable, k1=1.41 taped joint Evaluation of Weibull parameters Determination of “n” (Based on 30 years lifetime, n=15 for cable, n=12 for taped joint)

CIGRE Electra 151, 1993, AC400kV, Extruded AC Cable, PQ

Not defined

U IEC 60840 U>150kV => IEC 62067

U>150kV => IEC 62067 U8kV/mm => IEC 62067

Not defined

AIEC CS9-06, 2006 Extruded AC cable

Rec. for Electrical Tests Recommendations for Testing of High voltage tests on cross-linked Specification for extruded Prequalification and Development Long AC Submarine Cables with polyethylene insulated cables and insulation power cables and on Extruded Cables and Extruded Insulation for System their accessories for rated voltage their accessories rated Accessories at Voltages >150kV Voltage above 30 to 150kV from 11kV up to 275 kV above 46kV to 345 kV and 20 bar) the test margin should be agreed between customer and manufacturer. Epoxy resin components should be tested according to Sect. 7.4.1. If there are premolded components, these should be tested according to Sect. 7.4.1. Testing of epoxy resin components may be performed in a separate test setup without the presence of MI cable.

7.4.3

Test on External Housing

It is recommended to perform leakage test/vacuum drop, gas leak, and hydraulic pressure test as specified in IEC 60141-1/60141-3 (1998).

7.5

Sample Test

Due to the small numbers of transition joints which are expected to be supplied under single orders, sample tests will not normally be appropriate. Note: In special cases sample tests may be agreed between manufacturer and customer.

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G. Evenset

7.6

Type Test

7.6.1

General

The tests specified in this clause are intended to demonstrate the satisfactory performance of transition joints. The type test may be omitted: • As defined in the Range of Type Test Approval (see Sect. 7.6.2) or • If the transition joint is a combination of existing type tested accessories. An example is a back-to-back transition joint. Note 1: If suitable paper-insulated cable is unavailable, type testing will not be possible, thus approval of a transition joint design is dependent on agreement between manufacturer and customer, subject to consideration of any relevant test data. Note 2: In the event that breakdown occurs in the paper-insulated cable or within the joint and the primary cause is attributable to the quality of the paper-insulated cable then approval of a transition joint design is dependent on agreement between manufacturer and customer, taking into account the extent of tests passed and any other relevant test data.

7.6.2

Range of Type Test Approval

When a type test has been successfully performed on a transition joint for connecting cables of specific conductor cross-sections and of specific rated voltage and construction, the type approval shall be considered as valid for a transition joint within the scope of these test recommendations with other conductor cross-sections, rated voltages and with other cables provided that all the conditions of (a) to (h) are met: (a) The actual designs, materials, manufacturing processes and service conditions for the transition joint are in all essential aspects equal. (b) All service voltages, U0, UP1, UP2,S and UP2,O (URC,AC and URC,DC in case of return cable) are less than or equal to those of the tested transition joint. (c) The mechanical stresses for submarine transition joints to be applied during preconditioning are less than or equal to those of the tested transition joint. (d) The temperature of the conductors on both sides shall be less than or equal to the tested transition joint cables. (e) The maximum temperature drop across the insulation layer ΔTmax (excluding the semiconducting screens) on both cables is less than or equal to that of the tested transition joint cables. (f) The actual conductor cross-section is not larger than that of the tested transition joint cables.

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(g) The calculated Laplace electrical stress (using nominal dimensions) at the conductor and insulation screen is less than or equal to that of the transition joint cables. (h) A transition joint qualified according to this recommendation for LCC is also qualified for VSC provided the switching impulse withstand tests at UP2,S voltage levels as specified in Sect. 7.6.4 – Switching impulse withstand test for cable system to be qualified for VSC are carried out. A transition joint qualified according to this recommendation for VSC is not qualified for LCC. A type test certificate signed by the representative of a competent witnessing body, or a report by the manufacturer giving the test results and signed by the appropriate qualified officer, or a type test certificate issued by an independent test laboratory, shall be acceptable as evidence of type testing.

7.6.3

Type Test Arrangement

The transition joint shall comply with the tests specified in Sect. 7.6.4. The minimum length of free cable between accessories shall be 5 m. By definition, a transition joint includes 0.5 m of cable on the extruded side and 1 m of cable on the lapped side, as shown in Fig. 7.1, measured from the point on the cables where no disassembling or dismantling for the purpose of installation of the joint has taken place. As a minimum one sample of each transition joint type shall be tested. The accessory shall be assembled on the cables in the manner specified by the manufacturer’s instructions, with the grade and quantity of materials supplied, including lubricants and insulating fluids if any. There should be provision for measuring internal pressure of insulating fluid/gas during the test. In units that are intended to operate with internal oil pressure, whether such pressure is from the cable system or a separate source, the maximum pressure during the test must not exceed the minimum design operating pressure +25% (as specified in IEC 60141-3 1998). If the accessory includes a gas filled compartment then the gas pressure must be set so that at 20
C the pressure is no greater than the minimal functional pressure for insulation specified for the accessory +0.02 MPa (CIGRE Technical Brochure 415 2010; IEC 60859 1999). Neither the cables nor the accessories shall be subjected to any form of conditioning not specified in the manufacturer’s instructions, which might modify the electrical, thermal or mechanical performance. During electrical tests specified in Sect. 7.6.4, it is advisable to test joints with their outer protection fitted. If it can be shown that the outer protection does not influence the performance of the joint insulation, e.g., there are no thermal or compatibility effects, the protection does not need to be fitted.

472

7.6.4

G. Evenset

Type Test Procedure

Test Voltage Values Test voltage factor for extruded and lapped HVDC cables in TB 496 and Electra 189 is different for the load cycle and polarity reversal tests, even though the difference is small. Based on Electra 189, 1.8U0 and 1.4U0, respectively, are chosen for the load cycle and polarity reversal tests of transition joints in order not to overstress the lapped insulation. Note: If suitable paper lapped cable of the required insulation thickness is not available then it is allowed to use a cable with a greater insulation thickness and to reduce the insulation thickness in the region where the joint is to be installed to the required level. As an alternative it is also allowed to adjust the test voltages in order to achieve the required electrical stress values. Load Cycle Test The load cycle test shall be performed on test objects that have been subjected to the appropriate mechanical preconditioning. For testing of land joints, mechanical preconditioning of the cable is not mandatory. Submarine transition joints need to be tested according to the recommendations in Electra 171, which will be replaced by work done in WG B1.43 – TB 623 (2015) Recommendations for mechanical testing of submarine cables. The temperature conditions are defined in Sect. 7.2.5. The cable with the lowest Tcon,max should be at the maximum conductor temperature and temperature drop over insulation (ΔTmax). The conductor temperature of the cable with the highest Tcon,max should be measured and used as a design criteria for the joint installation conditions (Note that one cable system could be operating at much higher temperature and the thermal influence of this may be difficult to replicate under test conditions see Appendix B). This means that the cable on one side of the transition joint under test may not have been qualified in this test to its maximum conductor temperature or ΔTmax. It is recommended to perform the joint bay engineering prior to performing the type test in order to define the relevant temperature conditions for the test. The type test procedure is based on single core cables where the lay-out of the joint bay can be made to take into account the thermal influence from the two cable types. For multi core cables the cable cores may have to be split out before the transition joint in order to control the longitudinal temperature influence. For concentric cables with low voltage return insulation, the return conductor may have to be split out before the transition joint. Load cycle test for cable system to be qualified for LCC The test objects shall be subjected to the following conditions (definitions of “24 hours” load cycles and “48 hours” load cycles are described in Sect. 7.2.5.

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Eight “24 hours” load cycles at negative polarity at UT Eight “24 hours” load cycles at positive polarity at UT Eight “24 hours” load cycles with polarity reversal cycles at UTP1 Three “48 hours” load cycles at positive polarity at UT A minimum rest period of 24 h without voltage, but with heating, is recommended between blocks of different polarities. This does not apply to the individual polarity reversals in the polarity reversal test. Load cycle test for cable system to be qualified for VSC The test objects shall be subjected to: Twelve “24 hours” load cycles at negative polarity at UT. Twelve “24 hours” load cycles at positive polarity at UT. Three “48 hours” load cycles at positive polarity at UT. A minimum rest period of 24 h without voltage, but with heating, is recommended between blocks of different polarities. Superimposed impulse voltage test The superimposed impulse voltage test is to be performed on test objects that have successfully passed the load cycle test. The test procedure is described in Sect. 7.2.6 – Superimposed voltage test. Switching impulse withstand test for cable system to be qualified for LCC the test object at U0, 10 consecutive impulses to -UP2,O the test object at -U0, 10 consecutive impulses to UP2,O Switching impulse withstand test for cable system to be qualified for VSC the test object at U0, 10 consecutive impulses to UP2,S the test object at U0, 10 consecutive impulses to -UP2,O the test object at -U0, 10 consecutive impulses to -UP2,S the test object at -U0, 10 consecutive impulses to UP2,O Lightning impulse withstand test If the intended installation of the cable system is such that it is not exposed to lightning strikes (direct or indirect), these tests need not be done. For transition joints included in long cable systems, attenuation of lightning impulse voltages from terminations to the joint location may be considered when lightning impulse test voltage for the joint is determined (CIGRE Technical Brochure 268 2005). the test object at U0, 10 consecutive impulses to -UP1 the test object at -U0, 10 consecutive impulses to UP1

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G. Evenset

Subsequent DC test After the successful completion of the impulse testing, the test object shall be subjected for 2 h to a negative DC voltage of UT, no heating. A rest period prior to this test is acceptable. Test of outer protection for joints Cable joints intended for burial on land shall be subjected to the outer protection test specified in § 12.4 in IEC 62067 (2011). Examination Examination of the transition joint, whenever possible, by dismantling, with normal or corrected vision without magnification, shall reveal no signs of deterioration which could affect the system in service operation (e.g., electrical degradation, corrosion, harmful shrinkage or leakage, in particular across any seal separating the extruded and oil filled cables). Success criteria, re-testing and interruptions The criteria for a successful outcome to the type test are that all tests have been performed without breakdown of that test object and that all other non-electrical requirements have been complied with. After any interruption, for example an interruption caused by external factors, the test may be resumed. If the interruption is longer than 30 min, the specific lost load cycle shall be repeated. If the interruption is longer than 24 h, the actual test block (“24 hours” load cycles block at negative or positive polarity, “24 hours” load cycles block with polarity reversals, “48 hours” load cycles block under positive polarity) shall be repeated. In case of deviations in test parameters during load cycles or superimposed impulse voltage test, the load cycle or the superimposed impulse in question shall be repeated. In case of a breakdown of insulation, when testing several objects simultaneously, the faulty object may be removed and the incident treated as an interruption. The faulty object is considered to have failed the test requirements. Any fault within the extension (0.5 m/1.0 m for extruded and lapped side respectively) of a transition joint is considered to be associated with that test object only. Leak Test The vacuum leak test is to be performed as per manufacturer’s instructions when applicable. Pressure Test Apply 2 times rated internal pressure for 1 h. For very high internal pressure (>20 bar) the test margin should be agreed between customer and manufacturer. Leakage shall be detected at the end of this period by visual examination of the test specimen and by pressure drop. This test may be performed at the end of the type tests. No leak or rupture shall occur.

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Radial Water Penetration Test for Joints This test is only intended for submarine transition joints. Preparation The joint sample has to be taken from the joint subjected to mechanical tests, (see 8.6.1 and 8.6.2 in TB 490 (2012)) and at least 10 heating cycles shall be applied. Each heating cycle consists of at least 8 h of heating followed by at least 16 h of cooling. Current heating shall be used to give the declared maximum conductor temperature for the cable with the lowest Tcon,max for that specific installation. The temperature shall be kept at the stated value at least 2 h in the end of each heating cycle. The test is to be performed on the pressurized part of the joint and not necessary to the whole joint body for rigid joints. The joint sample shall be suitably sealed at the cable ends by means of caps. The test sample shall be placed inside a pressure vessel. Test The test object is submerged in pressurized water corresponding to the specified maximum laying depth. The test continues for 48 h with a water temperature of 5–35
C. When the test time has elapsed, the test object is removed from the water. No water ingress should be present under the water blocking barrier of the joint. No appreciable shape irregularity in the metal sheath. Examination Examination of the transition joint, whenever possible, by dismantling, with normal or corrected vision without magnification, shall reveal no signs of deterioration which could affect the system in service operation (e.g., electrical degradation, corrosion, harmful shrinkage or leakage, in particular across any seal separating the extruded and oil filled cables).

7.7

Prequalification Test

7.7.1

General and Range of Prequalification Test Approval

The prequalification test is intended to indicate the long-term performance of the transition joint and should normally be completed after the development tests have been carried out. The prequalification test need only be carried out once, unless there is a substantial change in the transition joint with respect to materials, manufacturing processes, construction or design parameters. Substantial change is defined as that which might adversely affect the performance of the transition joint. The supplier shall provide a detailed case including test evidence if modifications are introduced, which are claimed not to constitute a substantial change. NOTE: It is the opinion of the WG that the CIGRE TB 303 (2006) can be regarded as a relevant document to assess the need for further prequalification testing or not. However, the HVDC extruded cable system technology is at present considered to be too immature to include the concept of “Extension of Qualification” in this document.

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G. Evenset

As no prequalification test is required for the paper lapped side of the joint, the requirements below are focused only on the extruded side of the joint. The prequalification test qualifies the manufacturer as a supplier of transition joints provided that the following conditions are fulfilled: (a) The transition joint is a back-to-back joint (Appendix A) with prequalification tested extruded insulation accessories. (b) The transition joint of the same design has been prequalified. (c) U0 is not more than 10% higher than that of the tested cable system. (d) The calculated Laplace electrical stress at U0 (using nominal dimensions) at the extruded cable insulation screen is less than or equal to that of the tested system. (e) The maximum conductor temperature Tcond,max is less than or equal to that of the tested extruded cable system. (f) The maximum temperature drop across the insulation layer ΔTmax (excluding the semiconducting screens) is less than or equal to that of the tested extruded cable system. (g) A cable system prequalified according to this recommendation for LCC is also prequalified for VSC. A cable system prequalified according to this recommendation for VSC is not prequalified for LCC. A prequalification test certificate signed by the representative of a competent witnessing body, of a report by the manufacturer giving the test results and signed by the appropriate qualified officer, or a prequalification test certificate issued by an independent test laboratory shall be acceptable as evidence of prequalification testing. Note 1: If suitable paper-insulated cable is unavailable, prequalification testing will not be possible, thus approval of a transition joint design is dependent on agreement between manufacturer and customer, subject to consideration of any relevant test data. Note 2: In the event that breakdown occurs in the paper-insulated cable or within the joint and the primary cause is attributable to the quality of the paper-insulated cable then approval of a transition joint design is dependent on agreement between manufacturer and customer, taking into account the extent of tests passed and any other relevant test data.

7.7.2

Summary of Prequalification Tests

A minimum of 5 m of cable on each side of the joint with a dielectric design suitable for practical applications shall be tested. Appropriate mechanical preconditioning may be considered before starting the prequalification test. The normal sequence of tests shall be as follows: Long duration voltage test (see Sect. 7.7.4) Superimposed impulse voltage test (see Sect. 7.7.5) Examination (see Sect. 7.7.6)

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7.7.3

477

Test Arrangement

Cable and accessories shall be assembled in the manner specified by the manufacturer’s instructions, with the grade and quantity of materials supplied, including lubricants if any. Note: The main objective of the prequalification test is to satisfactorily demonstrate the insulation integrity during long time periods under DC, given the long dielectric time constants as compared to AC. It is however recognized that other aspects of a specific installation may be important, such as the thermo-mechanical effects due to the installation conditions. A rigid joint design should only be installed in rigid conditions to reproduce the net force effect resulting from different conductor cross sections at each side of the joint. Prior to the electrical prequalification test, the insulation thickness of both cables shall be checked as specified in Sect. 7.2.6 – Check on insulation. The minimum length of free cable between accessories shall be 5 m. One sample of each transition joint type shall be tested. The accessory shall be assembled on the cables in the manner specified by the manufacturer’s instructions, with the grade and quantity of materials supplied, including lubricants and insulating fluids if any. There should be provision for measuring internal pressure of insulating fluid in the lapped cable compartment during the test. In units that are intended to operate with internal oil pressure, whether such pressure is from the cable system or a separate source, the maximum pressure during the test must not exceed the minimum design operating pressure +25%. If the accessory includes a gas filled compartment then the gas pressure must be set so that at 20
C the pressure is no greater than the minimal functional pressure for insulation specified for the accessory +0.02 MPa. Prequalification test done with a transition joint in rigid configuration qualifies the joint for use in rigid and flexible installation. Neither the cables nor the accessories shall be subjected to any form of conditioning not specified in the manufacturer’s instructions which might modify the electrical, thermal or mechanical performance.

7.7.4

Long Duration Voltage Test

General: Minimum duration is 360 days. Conductor temperature Tcon,max and temperature difference ΔTmax on the extruded side of the joint shall both be controlled to a level corresponding to the maximum current carrying capacity of the system. The temperature requirements of the lapped cable side might limit the current possible to apply in the test setup. If so, the conductor temperature and temperature difference of the extruded side should correspond to expected service conditions of the cable close to the transition joint (separation of the cables close to the transition joint will reduce the maximum operating temperature – see Appendix B). If possible, it is recommended to perform the joint bay engineering prior to performing the prequalification test in order to define the relevant temperature conditions for the test.

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G. Evenset

Table 7.1 Line commutated converter, LCC LC LC Number 30 30 of cycles cycles cycles or days Test +  voltage UTP1 UTP1

LC þ PR HL HL ZL LC LC 20 40 40 120 30 30 cycles days days days cycles cycles

UTP2

+   + UTP1 UTP1 UTP1 UTP1

 UTP1

LC þ PR S/IMP 20 Not applicable cycles

UTP2

UP2,O ¼ 1.2  U0 UP1 ¼ 2.1  U0*

LC ¼ load cycle, HL ¼ high load, PR ¼ polarity reversal, ZL ¼ zero load, S/IMP ¼ superimposed impulse test * If required

Table 7.2 Voltage source converter, VSC LC Number 40 cycles of cycles or days Test + voltage UTP1

LC HL HL ZL LC LC S/IMP 40 cycles 40 days 40 days 120 days 40 cycles 40 cycles Not applicable  UTP1

+ UTP1

 UTP1

 UTP1

+ UTP1

 UTP1

UP2,O ¼ 1.2  U0 UP1 ¼ 2.1  U0*

LC ¼ load cycle, HL ¼ high load, ZL ¼ zero load, S/IMP ¼ superimposed impulse test * If required

The sequence of tests for LCC and VSC are shown in the above tables (Tables 7.1 and 7.2). Sections 7.2.5 and 7.2.6 provide guidance on test conditions. Note: Ambient conditions may vary during the test and this is not considered to have any major influence. In such cases, the conductor current shall be adjusted to maintain the conductor temperature and temperature drop across the insulation within the specified limits. The length and sequence of the thermal conditions were selected with regard to the particular electrical effects that can occur in extruded insulations when operated under DC voltage. A minimum rest period of 24 h without voltage, but with heating, is recommended between blocks of different polarities. This does not apply to the individual polarity reversals in the PR blocks of the LCC test scheme.

7.7.5

Superimposed Impulse Voltage Test (Optional)

It is the opinion of the WG that the prequalification test should not be evaluated on the basis of the impulse level. The aim of the superimposed impulse test after the long duration test is only to check the integrity of the insulation system. Evaluation

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of available specifications for different projects show that the values of UP2,O and UP1 vary between the different projects. In this respect, and based on the recorded experience, the impulse voltage values to be considered for the prequalification test have been defined as follows: UP2,O ¼ 1.2  U0. UP1 ¼ 2.1  U0 (if required). The voltage may be limited by the LIWL of the lapped cable. If so, UP1 should be adjusted accordingly. Project specific requirements regarding impulse levels should be covered by the electrical type test (Sect. 7.6). The temperature conditions are defined in Sect. 7.2.5. The transition joint shall withstand without failure 10 positive and 10 negative superimposed switching impulses at the voltage levels UP2,O. If by agreement between supplier and customer a lightning impulse test is also to be performed, the transition joint shall withstand without failure 10 positive and 10 negative superimposed lightning impulses at the voltage level UP1.

7.7.6

Examination

Examination of the transition joint, whenever possible, by dismantling, with normal or corrected vision without magnification, shall reveal no signs of deterioration which could affect the system in service operation (e.g., electrical degradation, corrosion, harmful shrinkage or leakage, in particular across any seal separating the extruded and oil filled cables).

7.7.7

Success Criteria, Re-testing, and Interruptions

The criteria for a successful outcome of the prequalification test are that all tests shall have been performed without breakdown of that test object and that the system examination is in accordance with Sect. 7.7.6. If there is a breakdown in a test object the complete prequalification test shall be repeated for that particular test object. If a breakdown of a test object occurs, causing an interruption to the ongoing testing of connected test objects, the test may be resumed after the failed test object is removed. The actual load cycle or impulse during which the failure occurred shall be repeated for the remaining test objects. If breakdown occurs during a constant load period the time elapsed without voltage applied shall be added to the remaining test period. After any interruption, for example an interruption caused by external factors, the test may be resumed. If the interruption is longer than 30 min, the specific lost load cycle shall be repeated. If the interruption occurs during a constant load period and is longer than 30 min, the day the interruption occurred shall be repeated.

480

7.8

G. Evenset

Electrical Test After Installation

Tests on newly installed transition joints are carried out when the installation of the cable and its accessories has been completed. If required, both sides of the transition joint may be tested separately according to the relevant standard before the transition joint is installed. The test voltages recommended for general use should be limited to the lowest test voltage for the two cable system, 1.4U0 negative polarity for 15 min, however test regimes should be evaluated on an individual basis to take into account the condition of an existing cable system.

Appendixes Appendix A: Back-to-Back Transition Joint with Two Insulators The transition joint as shown in Fig. 7.3 comprises either: (a) Two GIS terminations in a common joint shell or (b) two oil immersed terminations in a common joint shell The terminations are in back-to-back arrangement and connected with a short length of bus bar. In the case of GIS terminations the joint shell is filled by insulating gas (either with SF6 gas or mixture of SF6 gas and nitrogen). In the case of oil immersed terminations either cable oil, transformer oil or other insulating oil is used (CIGRE Technical Brochure 89 1994; CIGRE Technical Brochure 177 2001).

Fig. 7.3 Back-to-back transition joint with (2) insulators

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Features Extruded and lapped cable terminations are identical to terminations used in either SF6 switchgear or transformer applications and therefore further approval testing should not be necessary. Current carrying connection between two terminations may be specific to transition joint, in which case this may need separate evaluation. The electrical field design in the central region may be specific to the transition joint, however this may be assessed by electric field calculations if adequate test data is available. In the case of gas, a gas supply is required, and in case of oil the oil may be connected to the cable oil system or alternatively a header tank of some type could be used. Both systems would normally require some sort of fluid loss alarm. In special cases, the bus bar connection can be designed so that the two cables may be disconnected allowing independent high voltage commissioning tests on the two cables.

Appendix B: Temperature Distribution in Transition Joints with Dissimilar Cable Insulation The transition joints may be used to connect cables with XLPE or paper insulation operating at significantly different temperatures. To evaluate the likely distance over which the temperature may stabilize in a generic HVDC joint configuration a simplified model was built in a 2D axisymmetric configuration. It is well known that heat flows from the point of high temperature to a point of low temperature along a uniform conducting bar with homogeneous material properties. Cable rating is fully covered in IEC60287 although joint bay ratings are not and are further complicated by sections of higher thermal radial resistance at the joint positions leading to localized increase in temperature. The diagram below represents an HVDC transition joint bay with two identical cable poles (Fig. 7.4).

A

Fig. 7.4 HVDC joint bay layout

B

C

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Table 7.3 Zones in Fig. 7.4 If A is a cable system operating at a higher temperature than C

It therefore follows the spacing has to be adjusted so that by the time the cables are at B, the temperature is as for C plus a further temperature drop for the joint insulation TR

The temperature at B should already be the same as at C

This configuration can be further simplified by removing the mutual heating element due to the second cable which can be reconstituted by temperature superposition. The distance between the cables has direct impact on the operating temperature. The type approval test has to replicate the maximum temperature conditions, the cable on site has to match these conditions or the spacing has to be increased to confine the conditions to what is within the specification. For example an XLPE cable system at position A may be able to operate at 90
C whereas an MI cable system at B could have a maximum operating temperature of 50
C. It is uncertain how the longitudinal heat flow would affect the temperature distribution and over what distance (Table 7.3). A series of models was run using Finite element software to evaluate the longitudinal heat flow based on volumetric heat generated in the conductor and adjusted to match the maximum operating temperature of the cables (Fig. 7.5). The other key parameters for the model are: • • • • • •

Subsea Transition simulated at 1000 mm depth and @1 K.m/W Armor stripped off Epoxy Resin joint body Length of model 10 m 1000 sqmm Cu to 1600 sqmm Cu transition shown On approach cable temperatures at maximum (but would be lower due to increased spacing) • Joint center at 5 m

15ºC along this interface (axi-symmetric) 1m Section 1

Section 2 CL

Fig. 7.5 Individual HVDC cable and joint FEA model

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The following scenarios were modelled (Table 7.4): The Fig. 7.6 shows the results of the model applied to a XLPE to MI transition. The XLPE cable outside of the joint bay will be operating at almost maximum conductor temperature, this is at the point A of Fig. 7.4. The temperature drops as the spacing between the two phases is increased but in this instance due to the longitudinal flow from the smaller XLPE conductor (1000 mm2 Cu) to a much bigger MI conductor (1600 mm2 Cu). Small increase in temperature is also expected in the middle of the joint due to the extra radial thermal resistance but in this instance the size of the conductors negates this effect. The temperature on the MI side of the joint

Table 7.4 FEA section parameters

Section 1 (1000 sqmm) XLPE (70
C) XLPE (90
C) PPL MI (85
C)

Section 2 (1600 sqmm) MI (50
C) MI (50
C) XLPE (70
C)

Temparature (K) 70 69 68 67 66

A

65 64 63 62 61 60

B

59 58 57 56 55 54 53

C

52 51 50 0

1

2

3

4

5

6

Fig. 7.6 Example figure XLPE (70
C) connected to MI (50
C)

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8

9

10 L (m)

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from the 5 m point onwards fall off to the 50
C as the heat flux is redistributed further up the MI cable. In a full 3D rating, the phase separation would be increased to further reduce the temperature at the center of the joint to a maximum of 50
C. The FEA was able to demonstrate that within 5–9 m the longitudinal flow stabilizes the temperature to within acceptable levels for mainstream conductor sized but specific 3D ratings will always be necessary to confirm the exact site situation.

Appendix C: Terms of Reference of WG B1.42 WG* N
B1.42

Name of Convenor: Gunnar Evenset (NORWAY) E-mail address: [email protected] Strategic Directions # (3): 1

Technical Issues # (2): 3 The WG applies to distribution networks (4): No Title of the Group: TESTING OF TRANSITION JOINTS BETWEEN HVDC CABLES WITH LAPPED AND EXTRUDED INSULATION UP TO 500 KV Scope, deliverables and proposed time schedule of the Group: Background: Although the extruded HVDC cable technology is developing very fast, lapped HVDC cables will still be on the market for many years. There are projects that consider mass-impregnated cables for the submarine part of the route and extruded cables for the land part of the route. There is a need to define test specifications for how to qualify transition joints between these two technologies Scope: 1. Review relevant test recommendations for testing of HVDC cables 2. Review relevant test recommendations for testing of transition joints for AC cables 3. Prepare a Technical Brochure on testing of transition joints between lapped and extruded HVDC cables 4. Prepare report for Electra 5. Prepare a tutorial Deliverables: Technical brochure with summary in Electra and tutorial Time Schedule: start: August 2012 Final report: 2014 Comments from Chairmen of SCs concerned: Approval by Technical Committee Chairman: Date:

References CIGRE Electra 176: Diagnostic Methods for HV Paper Cables and Accessories (1998) CIGRE Electra 189: Recommendations for tests of power transmission DC cables for rated voltages up to 800 kV (2000) CIGRE Technical Brochure 177: Accessories for HV cables with extruded insulation (2001) CIGRE Technical Brochure 268: Transient voltages affecting long cables (2005) CIGRE Technical Brochure 269: VSC Transmission (2005) CIGRE Technical Brochure 279: Maintenance for HV Cables and Accessories (2005) CIGRE Technical Brochure 303, Revision of Qualification Procedures for HV and EHV AC Extruded Underground Cable Systems (2006)

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CIGRE Technical Brochure 415: Test Procedures for HV Transition Joints for Rated Voltages 30 kV up to 500 kV (2010) CIGRE Technical Brochure 446: Advanced design of metal laminated coverings: Recommendation for tests, guide to use, operational feedback (2011) CIGRE Technical Brochure 490: Recommendations for Testing Long AC Submarine Cables with Extruded Insulation for System Voltage Above 30 (36) to 500 (550) kV (2012) CIGRE Technical Brochure 496: Recommendations for Testing DC extruded Cables Systems for Power Transmission at Rated Voltage up to 500 kV (2012) CIGRE Technical Brochure 560: Guideline for Maintaining the Integrity of XLPE Cable Accessories (2013) CIGRE Technical Brochure 89: Accessories for HV extruded cable. Types of accessories and terminology (1994) IEC 60060-1 Ed. 3: High-voltage test techniques. Part 1: General definitions and test requirements (1989) IEC 60141: Tests on oil-filled and gas-pressure cables and their accessories (1998) IEC 60633: Terminology for high-voltage direct current (HVDC) transmission (1988) IEC 60811-201: Electric and optical fibre cables – Test methods for non-metallic materials – Part 20: General tests – Measurment of insulation thickness (2012) IEC 60840: Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements (2004) IEC 60859: Cable connections for gas-insulated metal-enclosed switchgear for rated voltages of 72.5 kV and above – Fluid-filled and extruded insulation cables – Fluid-filled and dry type cableterminations (1999) IEC 61901: Development tests recommended on cables with a longitudinally applied metal foil for rated voltages above 30 kV (Um ¼ 36 kV) (2005) IEC 62067: Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements (2011) CIGRE Technical Brochure 652: Guide for the operation of self contained fluid filled cable systems (2016)

Gunnar Evenset was born in Norway on May 16, 1969. He received his master degree in electrical power engineering from the Norwegian University of Technology in 1992. He was employed by Alcatel Kabel Norge in 1994 and started to work on R&D for HVDC cable systems. From 1996 to 1999 he continued research on HVDC mass-impregnated HVDC cable systems at the Norwegian University of Science and Technology and received his PhD degree with the thesis – Cavitation as a precursor to breakdown of mass-impregnated HVDC cables. From 1999 to 2012 he was technical manager for HV cables in Nexans Norway and from 2012 to 2013 he was Corporate Technical Manager High Voltage & Underwater Cable Systems in Nexans. He founded Power Cable Consulting AS in 2013 and is currently working as consultant. He has been convener and member of several Cigré working groups and member of the SC B1 SAG from 2008 to 2016. He received the Cigré Technical Committee Award in 2008 for outstanding contribution to the work of SCB1.

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Sheath Bonding Equipment for AC Transmission Cable Systems Tiebin Zhao

Contents 8.1 Basic Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1 Overview of Bonding Systems and Sheath Voltage Limiters . . . . . . . . . . . . . . . . . . . . 8.1.1.1 Cable Metal Screen Design and Screen Bonding . . . . . . . . . . . . . . . . . . . . . . 8.1.1.2 Sheath Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1.3 Sectionalized Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1.4 Sheath Voltage Limiters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1.5 Link Boxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1.6 Bonding and Grounding Leads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1.7 Safety Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2 Review of Related Literature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.1 Existing CIGRE Publications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.2 Technical Standards and Guides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.3 Relevant National Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.4 IEC Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.5 Cross References – Existing Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2.6 Published Papers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3 Review of Service Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.1 Bonding Schematics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.2 Withstand Voltage Level of Bonding Components . . . . . . . . . . . . . . . . . . . . 8.1.3.3 SVLs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.4 Bonding Lead Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.5 Link Boxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.6 Calculation Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.7 Tests During Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.3.8 Maintenance Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2 Bonding System Design and Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1 Bonding Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1.1 Solid or Multi-point Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1.2 Single Point Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1.3 Mid-point Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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8.2.1.4 8.2.1.5 8.2.1.6 8.2.1.7 8.2.1.8 8.2.1.9

Cross-Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cross-Bonding in Tunnel Installations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impedance Bonding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Siphon Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bonding of Special Cable System Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . Example of Induced Voltage Calculations of a Single Point Bonded System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1.10 Example of Circulating Current Calculations for a Solid Bonded System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1.11 Example of Circulating Current Calculations for a Cross-Bonded System with Two Minor Sections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2 Sheath Voltage Limiter Selection and Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2.1 Sheath Voltage Limiters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2.2 Selection of Sheath Voltage Limiters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2.3 SVL Connection Configurations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2.4 SVL Installations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3 Cable System Models for Overvoltage Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3.1 Cable Impedances and Admittances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3.2 Power Frequency Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3.3 Transient Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3.4 Modelling of Other Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.4 Insulation Coordination of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.4.1 Sheath Bonding System Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.4.2 Sheath Bonding System and Component Requirements . . . . . . . . . . . . . . . 8.2.5 Special Protection on GIS Cable Terminations Against High Frequency Transient Overvoltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3 Testing of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.1 Introduction and Section Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2 Testing of System Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2.1 Cable Sheath Insulating Jacket . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2.2 Sheath Interruption Insulators and Joint Casings . . . . . . . . . . . . . . . . . . . . . . 8.3.2.3 Bonding Leads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2.4 Sheath Voltage Limiters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2.5 Link Box or Enclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2.6 Mounting Insulators (Standoff Insulators) and GIS Insulation Flange for Terminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3 System/Commissioning Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3.1 Induced Voltage and Bonding Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3.2 Sheath Jacket Integrity Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3.3 Contact Resistance Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3.4 Others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 Maintenance of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.1 Maintenance of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2 Common Failure Modes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.1 Jacket Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.2 SVL Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.3 Loose Connections (Bonding Leads, SVLs) . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.4 Damaged Bonding Leads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.5 Link Box Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2.6 Stand-Off Insulator (Termination Support) Failure . . . . . . . . . . . . . . . . . . . . 8.4.2.7 Other Failure Modes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.3 Corrective Maintenance of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.4 Preventative Maintenance of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

518 523 523 524 524 525 528 530 531 531 533 535 535 536 537 538 540 542 544 544 545 546 549 549 549 549 550 551 552 552 554 555 555 555 556 556 556 556 557 557 557 557 557 558 558 558 558 559

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8.4.4.1 Online Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.4.2 Offline Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.5 Maintenance Schedule of Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.5.1 Safety Considerations During Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.5.2 Parameters to Consider for Maintenance Planning . . . . . . . . . . . . . . . . . . . . 8.4.5.3 Recommendations for Maintenance Schedule for Cable Bonding Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.5 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A: Abreviations, Definitions, and Symbols . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A1: Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A2: Specific Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A3: Symbols . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D: Bibliography/References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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This chapter contains the study outcome for sheath bonding of ac transmission cable systems. It comes from Technical Brochure 797 prepared by WG B1.50 and published in March 2020. The WG B1.50 was convened by T.ZHAO from the USA, The Technical Brochure 797 (TB) incorporates design, testing (including after installation testing), and maintenance of these sheath bonding systems. Sheath bonding is required for all cable systems to ensure an effective bond to earth of the cable system metal sheath, armoring, and semi-conductive outer sheath covering. Incorrectly performed sheath bonding systems may lead to cable system failures or pose a human safety risk. Sheath bonding systems for the purpose of this chapter include related cable system components and equipment that are connected to form the required ac cable system sheath, armoring, and semi-conductive outer sheath bond and connection to earth. The basic information and requirements needed to design such sheath bonding systems are included in several documents such as Electra 128 (1990), TB 189 (2001), TB 268 (2005), TB 283 (2005), TB 347 (2008), TB 403 (2010), TB 556 (2013), and TB 680 (2017). Due to recent developments, trends and industry best practices in sheath bonding system designs, component standards, and related national regulations, CIGRE Work Group (WG) B1.50 was established to develop this TB 797. Section 8.1 provides an overview of the sheath bonding system functions and requirements through review of existing documents and other engineering information related to sheath bonding systems. It furthermore includes the service experience feedback received in terms of sheath bonding system configurations, schematics, standing voltages, and voltage withstand requirements. Section 8.2 lists and discusses the most commonly used sheath bonding system methods used for the design of ac cable systems (i.e., single point, multiple point (solid), and cross-bonding) and the challenges regarding the protection (insulation) of cable system sheaths. The TB provides basic knowledge on voltage withstand requirements, current rating, and energy absorption for the selection and implementation of bonding leads, link boxes, and sheath voltage limiters, depending on the cable system parameters, sheath bonding methods, earthing connection, and insulation

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co-ordination technical study results. The TB also provides guidelines for performing insulation co-ordination technical studies related to the design and voltage withstand requirements of sheath bonding systems, and the cable system models that can be used for computer software overvoltage calculations and simulations. Testing of sheath bonding systems is discussed in Sect. 8.3 to provide guidance on type testing of bonding system components and equipment, and on performing after installation tests. Maintenance of the sheath bonding systems is addressed in Sect. 8.4 by providing recommendations on industry best practices for maintenance of sheath bonding systems (including sheath voltage limiters and testing criteria). Condition monitoring options for the sheath bonding systems are also discussed. Appendix of this document include lists of Abbreviations, Term Definitions, Symbols, References.

8.1

Basic Information

8.1.1

Overview of Bonding Systems and Sheath Voltage Limiters

8.1.1.1 Cable Metal Screen Design and Screen Bonding Single-core high voltage transmission (66 kV and above) cables are normally provided with an outer concentric conductor, generally referred to as the metal screen which surrounds the current carrying conductor and insulation. The metal screen can be in the form of a sheath (welded or extruded), wires, tapes, or a combination thereof. Metal tubes enclosing fiber optics may also be part of the metal screen. Metal sheaths also have the added benefit of providing a radial water barrier. Many different designs for metal screens are used worldwide, of which two examples are shown in Fig. 8.1.

1

2

Fig. 8.1 Examples of metal screens of high voltage transmission land cables – Left: 150-kV EPR insulated with copper wire screen (1); Right: 400-kV XLPE insulated with longitudinally welded aluminum sheath (2)

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In this document, metal screens are called metal sheaths or sheaths to align with traditionally used terminology. Where more than a general reference to metal screens is required, the specific metal screen type is further described to prevent confusion on the use of the words metal sheaths or sheaths. The sheath also includes any armoring layer of the cable. When single core cables carry ac currents, voltages are induced in the metal sheaths and currents flow along the metal sheaths if they are connected so as to form a closed circuit, for example, by earthing the metal sheaths at both ends of the cable. These sheath currents cause additional power losses in the cable that reduce the cable current rating. Metal sheath bonding methods have therefore been developed to ensure the cable sheaths are bonded and earthed in such a way to eliminate or reduce these longitudinal sheath currents. Sheath bonding methods to eliminate or reduce sheath current are economically desirable, as the reduction in sheath current losses for cable circuits allows an appreciably smaller conductor size to be used (or conversely an increase in the current rating of the same cable) and lower energy losses to the cable system operator. A sheath bonding system is a system to protect the insulation of the following components against normal operating voltages and transient overvoltages from lightning, switching, and fault surges: • • • • • • • • •

Cables and accessories Cable sheath insulating jacket or outer (over) sheath Joint casing outer protection Sheath interruption insulators or gaps between interrupted semi-conductive shield Stand-off insulators for outdoor terminations Insulating flanges for GIS Bonding lead insulation Link box internal components Fluid-filled hydraulic insulation Connecting Components of the bonding system include:

• • • • • • •

Bonding lead cables Bonding lead connectors Link boxes or link enclosures Sheath voltage limiters Earth continuity conductors Metal sheaths Earthing

The bonding system connections shall be rated for fault current and circulating current where applicable. The cable metal sheath is designed to: • Provide cable capacitive return path • Provide fault current return

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• Provide earth potential for human safety • Provide moisture barriers to cable insulation, where applicable For single-core cable circuits carrying currents in excess of 500 A, special sheath bonding considerations in accordance with TB 283 is economically desirable as the reduction in sheath current losses allows an appreciably smaller conductor size to be used. Special sheath bonding systems are therefore single point or cross-bonded systems used to eliminate or reduce sheath currents. There is however no clear-cut load level for which sheath bonding methods to eliminate or reduce sheath currents should be introduced. The extra cost of the energy losses and larger conductor cable and/or multiple cables per phase system required for solidly bonded systems must be weighed against the cost of the additional equipment and the maintenance cost arising from the greater complexity of a special bonded system to eliminate or reduce sheath currents. The choice shall be based on the cable system design, case by case. Bonding options are discussed in Sect. 8.2.

8.1.1.2 Sheath Insulation Sheath insulation is necessary to electrically isolate the cable metal sheath from earth and to prevent metal sheath corrosion. The sheath insulation is subjected to voltages induced by the power frequency cable conductor current and fault current, and by the transient voltages imposed to the cable conductor by lightning or switching surges. Sheath insulation should have appropriate dimensional and physical characteristics for the intended application. Sheath insulation can be coated with a semiconducting layer of graphite or can be covered with an extruded semi-conducting layer in order to facilitate on-site testing of the sheath insulation after installation and periodically thereafter. Special caution shall be taken when any semi-conductive layers are applied on cable system installations. The semi-conductive layers are usually applied to the bonding and earthing design to mitigate the risk of any capacitive coupled steady state or transient overvoltages. When the user requires an extruded outer semiconducting layer over the insulating sheath for tunnel installations, it is required to solidly bond the semi-conductive outer sheath layers to the metal structures along the entire tunnel length in order to prevent any voltage difference between the semi-conductive outer sheath and the tunnel metal structure. The voltage difference could lead to sparking. It is advisable that any personnel contact with the cable system semi-conductive outer sheath and racking system in the event of switching operations should be prevented. Insulation coordination technical studies in accordance with TB 189, TB 268, TB 283, TB347, and TB 556 are recommended to be performed for each ac cable system sheath bonding system design, and shall include considerations for all transients as defined by IEC 60071 (International Electrotechnical Commission 2006). These insulation co-ordination technical studies shall also consider the impact of the connecting power system and various network operating condition that may exist.

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Fig. 8.2 Example of high voltage land cable sectionalized joint/casing

8.1.1.3 Sectionalized Joints A sectionalized joint is particularly suited for bonded systems. For this joint, the metal screen, semiconducting screen, and metal casing (if present) are electrically interrupted. The metal screen is interrupted by an insulating ring or other similar designs, while the semiconducting screen is interrupted by means of a gap in the semi-conductive layer in the pre-molded joint or paper lapping, which is located in an area of relatively low or no electric field in order not to impair the performance of the joint. IEC 60840 and IEC 62067 provide testing procedures for sectionalized joints. Figure 8.2 shows a design example of a sectionalized joint. 8.1.1.4 Sheath Voltage Limiters Sheath voltage limiters (SVLs) are surge arrester devices that are connected to the cable metal sheaths in the bonding systems that eliminate or reduce sheath currents. SVLs are required in these bonding systems to protect the sheath insulation, sectionalizing interruption at joints, GIS insulation flanges, and other accessories against overvoltages on the metal sheaths during system transients. System transients may be lightning, switching, or fast transient associated with the initial part of a short circuit event. SVLs should withstand the power frequency overvoltage associated with short circuit events. Three main types of SVLs are typically used: (a) Nonlinear resistances, such as metal-oxide surge arresters without spark gaps (b) Nonlinear resistances, such as silicon carbide (SiC) blocks, in series with spark gaps (c) Spark gaps Currently, metal-oxide surge arresters are most widely used due to their fast response to transients, compact design, and ac voltage withstand recovery following a transient. SVLs must be selected in relation to power frequency and transient voltages to which SVLs may be subjected. The energy absorption capability of SVLs must be considered in the designs. SVLs should limit slow and fast transient overvoltages while they should not intervene to limit power frequency overvoltages. Commercially available SVLs have generally either porcelain or polymer housing. SVLs are often housed in link boxes. The link boxes represent an accessible place to allow for inspection and maintenance while ensuring proper operation under local environmental conditions. Figures 8.3, 8.4 and 8.5 show examples of installation connection configurations of SVLs.

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Sheath Voltage Limiter Parallel earth continuity conductor

Concentric bonding lead

Bonding leads for other phases

Fig. 8.3 Sheath voltage limiters used at termination of single point bonded cables

Concentric Bonding Lead

Optional Earth Link

Sheath Voltage Limiters (may also be connected in delta) Fig. 8.4 Sheath voltage limiters placed in a link box remote from buried joints

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Bonding Leads

Fig. 8.5 Sheath voltage limiters used close to joint sleeve sectionalizing insulators

8.1.1.5 Link Boxes Link boxes provide housing for bonding and earthing connections generally made of removable or disconnecting links. Link boxes may also contain SVLs when necessary according to the bonding system design. Link boxes are expected to be corrosion resistant and match the specified installation requirements, such as being water tight when installed below the earth surface. Some users require explosion proof link boxes. Different housing materials are used, such as, stainless steel, fiberglass, or cast iron. Different mounting designs are used for underground vault, transition pole or substation, kiosk, pit, and direct buried installations. Section 8.3 discusses testing requirements of link boxes and other bonding system components. Figure 8.6 shows an example of a link box. The sheath bonding system design and connection to earth shall ensure safe touch and step potentials for any part of the Fig. 8.6 Example of a cross bonding link box with SVLs and single-core bonding leads

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bonding system, including the link box housing. Due to safety reasons, the link boxes should not be opened while the cable circuits are energized or while any adjacent circuits are energized that may lead to induced voltages at the link box location.

8.1.1.6 Bonding and Grounding Leads Bonding leads are insulated conductors connecting between the cable metal sheath and the bonding connections within link boxes. Grounding leads are also insulated conductors connecting between link boxes and earth or termination ground. In the following document, bonding leads are used with the inclusion of the grounding leads, but the requirements for bonding leads, grounding leads, or earth continuity conductors can be different. Figures 8.7 and 8.8 show examples of sheath bonding configurations for the identification of bonding leads, grounding leads, and earth continuity conductors.

Fig. 8.7 Example of a single-point bonding system where bonding and grounding leads are identified

Fig. 8.8 Example of a cross-bonding system where bonding and grounding leads are identified

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Connection between SVLs and the metal sheath of a power cable requires proper insulation coordination, taking into account of insulation withstand of bonding leads, metal sheaths, insulators, and the protective level of the SVLs. In general, it is desirable to keep bonding lead lengths as short as possible to provide proper protection against transient overvoltages. Bonding leads could be made of singlecore cables or concentric cables. Bonding leads must be adequate to carry the expected short circuit currents and to withstand the expected overvoltages. Further consideration for the type of bonding leads selected and bonding lead length shall be considered in the insulation co-ordination study performed. Bonding leads are normally insulated with extruded dielectrics. The most widely used are PVC, XLPE, and EPR. The higher permittivity of PVC results in a lower surge impedance and a lower propagation velocity. The lower permittivity of PE increases the propagation velocity (which means also a shorter “electrical length” is required) and a higher surge impedance. EPR offers intermediate conditions. The choice of the most appropriate insulating material must be made within a specific cable system design. Some users require bonding leads with outer semiconducting layer for testing purposes. Special caution shall be applied for any outer semiconducting layer bonding for capacitive coupled overvoltages during transients and steady state normal or fault conditions. Bonding leads when installed below earth surface should use some form of longitudinal water blocking to prevent water ingress into high voltage cable joints in case of bonding lead damages or water ingress into link boxes. The insulation requirements of the bonding leads selected shall be equivalent to that of the joints and cables used. The general construction of a single-core bonding lead is as follows. Figure 8.9 shows an example of a single-core bonding lead. • • • •

Conductor (copper or aluminum) Water blocking inside conductor (if specified) Conductor semi-conductive layer (if specified) Insulation layer (XLPE – current technology, PE – previous technology, EPR) (if specified) • Insulation semi-conductive layer (if specified) • Oversheath layer (PE), fire protection, if required • Outer semi-conductive layer (when field testing is needed)

Fig. 8.9 Example of a singlecore bonding lead

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Fig. 8.10 Example of a co-axial (concentric) bonding lead

The general construction of a co-axial (concentric) bonding lead is as follows. Figure 8.10 shows an example of a co-axial (concentric) bonding lead. • • • • • • • • • • •

Inner conductor (copper or aluminum) Water blocking within conductor (if specified) Inner conductor semi-conductive layer (if specified) Inner insulation layer (XLPE – current technology, PE – previous technology, EPR) Inner Insulation semi-conductive layer, if specified Outer conductor (copper or aluminum) with water blocking (if specified) Outer conductor semi-conductive layer, if specified Outer insulation layer (XLPE – current technology, PE – previous technology, EPR) (if specified) Outer Insulation semi-conductive layer, if specified Over sheath layer (PE), fire protection if required Outer semi-conductive layer (when field testing is needed)

Electrical insulation is considered by the test requirements described in Sect. 8.3. Design of the bonding leads to prevent radial moisture ingress (metal foil, welded screen barrier, or other possible solutions), in addition to longitudinal moisture migration, may also be considered. Where jointing of the bonding leads is required, the joint assembly shall also meet the requirements for the bonding leads.

8.1.1.7 Safety Considerations The following two paragraphs are from IEEE 575 – Section 6.2. They are included here for completion of this document. Potentially hazardous voltages can be present on the exposed portions of the metal shields/sheaths of high-voltage cables, the outer surface of conducting cable jackets, the conductor of bonding cables, the conductor of grounding leads, across exposed shield/sheath interrupts, the SVLs, and various hardware connections within the link boxes and other equipment connected to or associated with bonded cable systems. Appropriate precautions must be taken to provide access control to these areas to ensure that safety procedures are followed in order to protect both personnel and equipment.

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Exposed portions of the metal shield, sheath, bond cable, or other conductive connections in electrical contact with the cable’s shield/sheath, or bond cable of a bonded cable system, should never be assumed to be at ground potential. The allowable shield/sheath voltage at full load varies considerably among utilities and among countries. The shield/sheath voltage will be significantly higher during system transients and short circuit conditions. As a consequence, appropriate protection and precautions must be taken to ensure that personnel who may come into contact with any of the above conductive components are familiar with the design, take adequate protection against potentially related hazards, and follow proper safety procedures. Additionally, safe touch potential and step potential studies shall also be performed for the selected earthing and bonding system. Any unsafe condition shall be mitigated and prevented by the design methodology.

8.1.2

Review of Related Literature

This section provides a review of the existing literature within the technical area covered by this Technical Brochure. Existing CIGRE publications are highlighted, along with relevant national and international standards. Finally, a review of the Technical Literature is provided, in support of the technical scope of the remainder of this document.

8.1.2.1 Existing CIGRE Publications This section summarizes the contents of existing CIGRE Technical Brochures of relevance to Sheath Voltage Limiters and Bonding Systems. It should be noted that it is not the intention of the working group to reproduce the content of these earlier documents, hence they remain a valuable source of reference in their respective topics. 8.1.2.1.1 Electra 28 and Electra 47 Electra 28 (CIGRE WG 21.07 1973) and Electra 47 (CIGRE WG 21.07 1976) comprise two parts of one document entitled “The design of specially bonded cable systems”. They represent the earliest widely published review of the design considerations associated with these systems, having been released in 1973. Although many advancements have been made in the field of bonding since this time, much of the introductory material in these papers remains relevant. Electra 28 presents the general principles behind bonding, starting from the calculation of voltage gradients. Circuit arrangements are shown for both single point and cross bonded options, with a discussion on the considerations which need to be made when choosing a bonding system. An outline discussion is presented on how the bonded circuits respond to power frequency overvoltages associated with system faults. This remains a useful introduction to the key concepts.

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Electra 47 (published in 1976) follows directly on from Electra 28 and deals primarily with transient overvoltages. It includes an overview of sheath voltages limiters and their application, although it should be noted that some of this information is now outdated as zinc-oxide-based systems were still in their infancy at the time. Some outline guidance is provided on commissioning and maintenance of bonded cable systems; however, the relevant section is brief. The guidance supplied in this document is much more comprehensive. As service experience with bonded systems began to grow, it became apparent that some revisions were necessary regarding the protection of the sheath against overvoltages. This led to the publication of Electra 128 in 1990.

8.1.2.1.2 Electra 128 Electra 128 “Guide to the protection of bonded cable systems against sheath overvoltages” reports upon the work done by Working Group 21-07 and was published in 1990 (CIGRE WG 21.07 1990). This document was intended to replace Electra 47 by providing a guide to the selection and application of SVLs and to the general insulation coordination of the system, informed by the available service experience since the publication of the prior documents. On this basis, Electra 47 should no longer be considered a definitive reference. The main body of the Electra 128 report consists of a review of the use of SVLs (including spark gaps, silicon carbide and zinc oxide devices). Qualification testing for SVLs is also reviewed, although this primarily refers to the then effective IEC 99, which has now been replaced by the IEC 60099 series of documents. The important topic of insulation coordination is reviewed, including that of the link box/pillar, bonding leads, joint sectionalizing insulation and cable jacket. Two appendices are provided, the first of which covers recommendations for testing of SVLs and the second covers the calculation of sheath overvoltages.

8.1.2.1.3 TB 283 Special Bonding of High Voltage Cables Produced by Working Group B1.18, Technical Brochure 283 was published in October 2005 (CIGRE WG B1.18 2006). The document presents a review of calculation methods appropriate to both single point bonded and cross bonded systems under both power frequency conditions and during transient overvoltage events. Recommendations are made for the appropriate ways of undertaking the calculations for practical systems, including circuit design considerations. A short discussion of insulation coordination is also presented in the context of the calculations required. In practical terms, the publication of TB 283 effectively supersedes the following previous articles: • Electra 28, “The design of specially bonded cable systems”, Section 7 • Electra 47, “The design of specially bonded cable systems: Part II” • Electra 128, “Guide to the protection of specially bonded cable systems against sheath overvoltages”

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However, it must be noted that some parts of these earlier documents do remain relevant, and that TB283 does not fully replicate all of the earlier material. For power frequency conditions, equations are provided which permit the analysis of all common fault conditions. Given the importance of understanding the limitations of each calculation method, guidance is provided on the assumptions inherent within the equations, along with factors that might influence the performance of the bonding system. The review of transient overvoltage applications provides a summary of the different calculation methods which can be used, from relatively simple formulae through to the use of EMTP (Electro-Magnetic Transient Programme) software. Two worked examples are provided which take the user through the different steps of the calculations for voltage across sectionalizing joints, exploring the influence of the bonding lead design and the effects of the sheath voltage limiter. The Technical Brochure concludes by inspecting three particular “special considerations,” namely, cross bonding without the use of SVLs, the effect of the dc component of the SVL voltage and the impact of bonding lead configurations through CTs. 8.1.2.1.4 TB 347 Earth Potential Rises in Specially Bonded Screen Systems One of the conclusions arising from the work presented in TB 283 regarding Earth Potential Rise (EPR) associated with bonded cable systems was: Where a link connecting two substations with low earth resistances is considered, EPR at the ends and at the cross-bonding locations may generally be disregarded. Conversely, for siphon systems EPR has to be taken into account since sheath to earth voltage may exceed the nominal withstand level and the SVL energy handling capability if they are star-connected with earthed neutral point. Following on from the publication of TB 283 in 2005, questions remained regarding EPR within urban underground systems, with some field experience contradicting the conclusions of TB 283. As a result, CIGRE Task Force B1.26 was set up to develop TB 347 (CIGRE WG B1.26 2008), with the specific remit to improve the design of bonded systems with regard to EPR, by providing: • More information on EPR which may occur during single phase to earth faults • Details of a calculation method based on the Complex Impedance Model (CIM). • Calculation examples, especially for typical situations. The consideration of EPR within TB 347 is different to that seen in many other reports, as instead of considering EPR from the perspective of safety (for example step and touch voltages), the focus is on the integrity of the cable sheath earthing system (including the SVLs). TB 347 provides a review of both simplified and detailed calculation methods for assessing the likely EPR. Worked examples are provided for systems of varying complexity to provide a practical reference for users.

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One of the most important issues highlighted by TB 347 concerns the modelling of circuits with both underground and overhead sections, where a simplified model will often not provide a good representation of the behavior of the system. This is compounded by the fact that the information needed to perform detailed calculations needs to cross the interface between the cable supplier and the utility, or other parties responsible for the overhead line sections. Siphon systems in particular can present issues here, meaning that a degree of collaboration between the parties will become necessary.

8.1.2.2 Technical Standards and Guides This section briefly reviews Technical Standards and Technical Guides which cover the design of, or calculations associated with, sheath bonding systems. Where there are similarities between different national specifications, these are discussed further in the Section on Service Experience. 8.1.2.2.1 IEEE 575 IEEE 575 (IEEE PES 2014) describes the methods of calculating sheath voltages and currents for common types of sheath bonding systems for three phase, single conductor cable systems. It focuses on higher voltages, with most of the information presented being related to circuits operating at 60 kV or above, but the fundamental principles could be applied to single conductor circuits at lower voltages. It should be noted that the assumed definition of sheath in this case refers to “non-magnetic metal shielding”. The bulk of the document examines either single point bonded or cross bonded systems, including a discussion of the relative merits of each. The majority of the information provided relates to power frequency conditions, including the calculation of sheath standing voltages, however some notes are also provided in relation to transient calculations. Sections of particular relevance to the scope of this report include the “informative Annex” sections Annex D (Calculation of Induced Voltages) and Annex F (Current and Voltage Distribution on cable sheaths with multiple cables per phase). 8.1.2.2.2 Engineering Recommendation C55/5 C55/5 is a technical recommendation originating in the United Kingdom, although it has also been used in other countries. The latest revision (bringing the document up to Issue 5) was published in late 2014 (Electricity Networks Association 2014). The scope of the document is the bonding and earthing of three phase systems for operation at 33 kV and above. It should be noted that the document covers both single core and three core cable systems, meaning that a brief discussion is provided in relation to solidly bonded systems, although the majority of the document considers specially bonded cable systems. Guidance is given for both sectionalized and continuous cross bonding, along with single point bonding. Section 5 of C55 covers the design and technical

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requirements of the various components in the bonding system, including SVLs, bonding leads, and link boxes/pillars. C55 is a valuable source of information regarding the design and application of link boxes and pillars, which is a topic which has not been covered in as much detail by many of the other guidance documents available to the industry. This includes a review of the standard ranges of link box designs approved for the UK market, with cross referencing to diagrams of the respective bonding system. A wide range of permitted standard bonding options are presented, which although intended for the UK market can still serve as a valuable reference for all users. C55 does not provide details of calculation methods, instead documenting appropriate test procedures and design requirements.

8.1.2.3 Relevant National Standards As part of the scope of work of this working group, a review of service experience in different countries has been undertaken. A number of countries have National Standards/Specifications which may be a useful source of information generally. It should be noted that the list below is not considered to be exhaustive and the inclusion of a document in this list does not necessary mean that it is widely available in the public domain. United Kingdom In the UK, the transmission utility National Grid maintains a separate TS (technical specification) to the widely used UK document ENA C55. National Grid TS 3.05.04 “Sheath bonding and earthing for insulated sheath power cable systems” covers requirements for single core cables at voltages above 33 kV (National Grid plc n.d.-a). Of primary interest to non-UK readers are test requirements for bonding system components. Sheath voltage limiters are dealt with in a separate document, TS 3.05.03 “Sheath Voltage Limiters,” covering performance and testing requirements (National Grid plc n.d.-b). Denmark The Danish TSO Energinet maintains a specification bonding systems and accessories, ETS-0054 and ETS-0067. The standard is for all 132–400 kV cable projects using link boxes with direct grounding, single point bonding or cross bonding. Functional, technical and design requirements are given. France The French standard concerning cable bonding systems is NF C 33–254. United States AEIC CS9-15 – Specification for Extruded Insulation Power Cables and Their Accessories Rated above 46 kV through 345 kV, is widely used (AEIC 2015). Section 5.0 of this standard addresses Sheath Bonding/Grounding Systems. IEEE 575 is referred for general considerations. Overvoltage protection between cable sheath and disclosure is required for GIS terminations. Requirements for bonding cables, link boxes, sheath voltage limiters, and ground conductors are provided. Appendix C of CS9 – Electrical Withstand and Insulation Coordination Requirements for Bonded, Insulated Metal Shield/Sheath Systems, describes bonding system insulation coordination.

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8.1.2.4 IEC Standards Although the IEC does not maintain a separate standard regarding bonded cable systems, there are some IEC documents which have relevance. The primary documents of interest form part of the IEC 60099 series. IEC 60099-4 “Surge Arresters: Part 4: Metal Oxide surge arresters without gaps for ac systems” provides a comprehensive set of requirements and test criteria for surge arresters in general, including those used on overhead line networks. It is not specific to SVLs used for cable bonding purposes, but elements of it have been widely adopted by different national standards, particularly for testing purposes. Many other IEC standards on the topic of either cable testing or current rating also have relevance to the design and analysis of sheath bonding systems. The following cable testing standards are of particular relevance: • IEC 60840 – Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um ¼ 170 kV) up to 500 kV (Um ¼ 550 kV) – Test methods and requirements • IEC 62067 – Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um ¼ 36 kV) up to 150 kV (Um ¼ 170 kV) – Test methods and requirements • IEC 62895 – High Voltage Direct Current (HVDC) power cables with extruded insulation and their accessories for rated voltages up to 320 kV for land applications - Test methods and requirements Those interested in calculating the losses associated with circulating and eddy currents in cable sheaths should refer to: • IEC 60287-1-1 – Electric cables – Calculation of the current rating – Part 1-1: Current rating equations (100% load factor) and calculation of losses – General

8.1.2.5 Cross References – Existing Standards In order to assist readers in determining which of the existing documents might provide useful background information on a particular topic, Table 8.1 draws a comparison of the main documents listed in this section. For each technical area, a reference is given to the relevant section in the published documents. In an effort to integrate this with the structure of this Technical Brochure, the topics have been grouped under the same headings. 8.1.2.6 Published Papers In addition to the standards, guides, and specifications listed thus far in this section, a number of pertinent articles are listed below. 8.1.2.6.1 Sheath Voltage Calculations The following paper specifically addresses the issue of conductor transposition, and the effect that this will have on losses.

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Table 8.1 Evolution cross-reference of existing published guidance (numbers refer to section numbering in the respective document) Electra Topic 28 General Intro (Sect. 8.1) Permissible standing voltages Guide to bonding App A system terminology Service Experience Bonding Designs (Sect. 8.2.1) Choice of bonding 5 system Arrangements for 3 single point bonding Application of earth 3.2 continuity conductor Arrangements for 4.2.1 sectionalized cross bonding Arrangements for 4.2.2 continuous cross bonding Choice of cross 5.3 bonding system Cross bonding without SVLs Multiple cables per phase Screen Protection (Sect. 8.2.2) Power frequency 7 overvoltages Description of effect of transient overvoltages Types of SVLs in use Application of SVLs Earthing of SVLs Selection of SVLs Bonding lead designs Link box, link pillar designs Insulation coordination

Electra 47

Electra 128

TB 283

TB 347

C55/5

IEEE 575 Annex C

4

3

6.1

6.7

4.4

6.3

1.2

6.3.3

4.5, 4.5.3

6.5.3, 6.5.4

4.5, 4.5.2

6.5.5

6.3

Annex F

5.1, 6.4

Annex E 8, 9, 10

4.0

11

2

7

11.2

3.1, 3.2

4.3.2

5.1

11.2.4 12 12.4

3.3 5

4.3.3

5.1.3 Annex A 7.5 5.2 7.5.2

4.3.5, 4.3.6

5.3 13

6, App 1

7.6

7.5.1

4.6 (continued)

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Table 8.1 (continued) Electra Electra Topic 28 47 Jacket withstand requirements Cable System Models (Sect. 8.2.3) Calculations of 6 sheath standing voltages Calculations of 7.3 power frequency voltages due to faults (single point) Calculations of 7.4 power frequency voltages due to faults (cross bonded) Review of calculation methods (power frequency) Earth potential rise calculations Effect of unequal 4.2.4 section lengths Testing of Bonding Systems (Sect. 8.3) Commissioning 14.1 tests Testing of bonding leads Testing of link boxes Testing on complete circuits Qualification testing of SVLs Maintenance (Sect. 8.4) Maintenance of 14.2 SVLs

Electra 128

TB 283

TB 347

C55/5

IEEE 575 Annex E

Annex D

App 2, Part 3

3.4

6.1

Annex E

App 2, Part 4

3.2, 3.3

6.2

Annex E

3.1

4

5 3.2.6

7.2 7.3 7.5 4

7.1

Mighe, P. and de Leon, F. “Parametric study of losses in cross-bonded cables: conductors transposed versus conductors non-transposed,” IEEE Transactions on Power Delivery, 28 (4), 2013. Pp2273–2281. 8.1.2.6.2 Sheath Voltage Limiters The following papers explore specific topics relating to SVLs themselves, including issues concerning design specifications and unexpected failures.

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Parmigiani, B., Quaggia, D., Elli, E. and Franchina, S. “Zinc-oxide sheath voltage limiter for HV and EHV power cable: field experience and laboratory tests,” IEEE Transactions on Power Delivery, 1 (1), 1986. Pp164–170. Nichols, P. and Yarnold, J. “A sensitivity analysis of cable parameters and their influence on design choices for minimum sheath voltage limiter specification in underground cable systems,” Australasian Universities Power Engineering Conference, Adelaide, Australia, September 2009. Ghassemi, F. “Effect of trapped charges on cable SVL failure”, Electric Power Systems Research, 115, 2014, pp18–25. Nichols, P. “Minimum Voltage Rating of Sheath Voltage Limiters in Underground Cable Systems: The Influence of Corrugated Cable Sheaths.” 47th International Universities Power Engineering Conference, September 2012, London.

8.1.2.6.3 Field Measurements While a significant number of technical papers have been written on the subject of calculating the sheath voltages and currents seen in cable circuits, relatively little published information is available from field measurements. Gustavsen et al. (1995) formed a comparison between simulations and measurements for the case of two sections of single core cable. The results obtained demonstrated the significance of the proximity effect on the transient sheath voltage profile. Kaloudas et al. (2013) examined the power frequency response of long medium voltage cable systems connecting wind farms, comparing the results of simulations to field data. Calculated sheath voltages were found to be within 10% of the measured value in most cases. Subsequent work by Gudmundsdottir et al. (2011) reports on a validation test which compared the modelled response of a cross bonded cable circuit to its physical behavior. The circuit in question has a number of cross bonding points and three grounding points. This was achieved by injecting a conventional 1.2/50 μs impulse, at a magnitude of 4.08 kV, into the cable circuit and measuring the sending end voltage and current response. The results gained suggest that the model performs well up until the first inter-sheath reflections are measured, at which point the level of agreement between the model and the experimental data decreases. The differences are attributed to the representation of proximity effects within the model, underlining the importance of fully validating simulation work with physical measurements wherever this is possible. Gustavsen, B., Sletbak, J. and Henriksen, T. “Simulation of transient sheath overvoltages in the presence of proximity effects,” IEEE Transactions on Power Delivery, vol. 10, no. 2, pp. 1066–1075, Apr. 1995. Gudmundsdottir, U., Gustavsen, B., Bak, C., Wiechowski, W. “Field test and simulation of a 400-kV cross bonded cable system,” IEEE Transactions on Power Delivery, 26 (3), 2011, pp1403–1410. Kaloudas, C., Papadopoulos, T., Gouramanis, K., Stasinos, K., Papagiannis, G. “Methodology for the selection of long medium-voltage power cable configurations”, IET Generation, Transmission & Distribution, 7 (5), pp526–536, 2013.

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8.1.2.6.4 State of the Art: Modern Bonding Methods The following papers deal with new challenges in bonding and earthing, particularly with very long cable circuits. CIRED – 21st International Conference on Electricity Distribution –Frankfurt- June 2011- Paper 0499. Chang, M., Shao, S., Ros, H. In Land Long Distance HVAC Cables, Innovative Examples at 225 kV, Application to 500 kV.” B1 – 1019 – AORC Technical Meeting 2014. Lesur, F., Mirebeau, P., Mammeri, M. and Santana, J. “Innovative insertion of very long AC cable links into the transmission network” B1-301 CIGRE Session 2014. Khamlichi, A., Denche, G., Garnacho, F., Donoso, G and Valero, A. “Location of sheath voltage limiters (SVLs) used for accessory protection to assure the insulation coordination of cable outer sheath, sectionalising joints and terminations of high voltage cable systems”, B1 – 108 CIGRE Session 2016. 8.1.2.6.5

Safe Touch and Step Potential Design Requirements for Cable System Bonding and Earthing Designs This paper provides touch and step potential case study simulations for the bonding system earth continuity conductor, joint bay earthing and link box designs, and make recommendations for safe bonding designs. Du Plessis, T., Jagau, H. and Visagie, D-L. “Evaluating step and touch potential risks on earthing systems of high voltage cable systems,” 8th CIGRE Southern Africa Regional Conference. This paper explicitly deals with the theoretical simulation of switching transients on 400 kV cable systems and the associated effect on semi-conductive outer sheaths. Schutte, P.J., van der Merwe, W.C. and van Coller, J.M., “Induced Voltage Behaviour Analysis of an Un-Grounded Outer Layer Semi-Conductive Coating of A 400 kV Power Cable System”, 20th International Symposium on High Voltage Engineering, Buenos Aires, August 2017.

8.1.3

Review of Service Experience

The following questionnaire as shown in Table 8.2 was sent to all working group members. A summary of the received information is given below and details are included in Appendix B not reproduced in this volume of the book.

8.1.3.1 Bonding Schematics Solid bonding design is typically used on Medium Voltage (MV) systems (up to 66 kV). On High Voltage (HV) systems and Extra High Voltage (EHV) systems solid

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Table 8.2 Service experience review questionnaire Bonding Schematics Solid bonding Single-point bonding Sectionalized cross-bonding Continuous cross-bonding Hybrid bonding Direct cross-bonding without link box Withstand Voltage Level Bonding Components Screen to ground impulse withstand level for joints (kVp) Screen interruption impulse withstand level for joints (kVp) Screen to ground DC withstand level for joints (kV) Screen interruption DC withstand level for joints (kV) Screen to ground AC withstand level for joints (kV) Screen interruption AC withstand level for joints (kV) Impulse withstand level for outersheath (kVp) DC withstand level for outersheath (kV) AC withstand level for outersheath (kV) Impulse withstand level for bonding cables (kVp) DC withstand level for bonding cables (kV) AC withstand level for bonding cables (kV) DC withstand level between metal screen cable and metal enclosed GIS (kVp) AC withstand level between metal screen cable and metal enclosed GIS (kVp) Impulse withstand level for post insulator (kVp) DC withstand level for post insulator (kV) AC withstand level for post insulator (kV) SVL Type of resistor (Silicon Carbide, Zinc Oxide, other) Typical rated voltage (Ur) installed Type of connection in sectionalized joints (delta connection, star connection with neutral grounded, star connection without neutral grounded) Nominal discharge current (kA) (wave 8/20 μs) Line discharge according to 60099-4 Are SVLs installed inside link boxes? Bonding Lead Cables Type of bonding cable: where single-core or concentric bonding leads are used? Maximum length criteria Type of insulation (XLPE, PVC, PE) Outersheath with semi-conductive layer or graphite layer Watertight Link Boxes Location where link boxes are installed Are the link boxes accessible? Waterproof test Internal arc test (continued)

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Table 8.2 (continued) Calculations Criteria Method used for calculating induced voltage on the sheath (i.e., CIGRE formulation, EMTP/ATP, etc.) Sheath voltage limits during normal operation SVL selection criteria during fault conditions SVL selection criteria during transient overvoltage conditions (lightning and switching) Are you considering internal cable fault conditions into selection criteria of SVL? Tests During Installation Outersheath voltage tests Bonding system connection Maintenance Test Outersheath voltage tests (line off) Bonding system connection (line off) Current by metal screens (line on) SVL tests (line off)

bonding design exists for some cable systems but is not commonly used except for a few countries and except on submarine cables where no other alternatives exist. Sectionalized Cross-Bonding design is the most used for transmission lines (HV and EHV) except on short lines where Single-Point bonding design is mostly used. The other type of cross-bonding design, e.g., continuous cross-bonding design, was rarely used. Hybrid bonding design (a mixture of 2 or more types of bonding designs) is common for longer circuits where there were a number of sections that cannot evenly be divided into major cross-bonding sections. Other uncommon bonding designs, such as, direct cross-bonding without link box were beginning to be used in some countries as a method to optimize installation and maintenance cost.

8.1.3.2 Withstand Voltage Level of Bonding Components The following withstand voltage levels were considered for the cable circuits in service: • Impulse withstand levels and dc withstand levels for joints according to IEC Standards 60840 and 62067 for HV and EHV lines. • Impulse withstand levels and dc withstand levels for outer sheath according to IEC Standard 60229. Ac withstand voltage levels for bonding components are not required except by some countries (e.g., France). Withstand voltage level for metal enclosed GIS and post insulators were not required for the cable circuits in service.

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8.1.3.3 SVLs Sheath Voltage Limiters (SVLs) were usually installed inside link boxes with a very few exceptions where the SVLs were installed in air (for example, between baseplate of terminations and steel structures and between each side of sectionalized joints). The most common type of SVLs used were zinc oxide. Their rated voltage was in the range from 3 to 15 kV depending on specified short circuit currents and length of cable minor sections. Nominal discharge current was 10 kA and line discharge class was 1 or 2 in accordance with IEC Standard 60099-4. The sectionalized cross-bonding bonding scheme is used in the majority of the cable circuits in service. The type of connection in sectionalized joints was star connection with neutral grounded. 8.1.3.4 Bonding Lead Cables Concentric or coaxial bonding lead cables were usually used on joints and singlecore bonding lead cables on terminations. Bonding cables generally did not have an outer semi-conductive layer or graphite coating. Watertight properties were not generally required, although it should be noted that water blocking can be important in cases where the link box may be submerged in ground water. All countries considered the criterion of 10 m as the maximum bonding lead cable length for connections between SVLs and accessories. 8.1.3.5 Link Boxes Link boxes were mainly located in dedicated pits close to joint manholes. In the case of outdoor terminations, link boxes were installed on structures above ground. All link boxes were accessible to permit maintenance activities. The latest generation of link boxes were waterproofed according to IEC Standard 60259 or NEMA (Protection Grade IP 68 or equivalent NEMA is recommended). 8.1.3.6 Calculation Criteria Methods used for calculating induced sheath voltages were mostly based on CIGRE documents. EMTP/ATP was used in some cases. In some countries, the sheath induced voltage during normal operations was limited. The maximum value depended on utility company specific criteria although it did not usually exceed 600 V. During fault conditions, SVLs should not be activated by induced power frequency voltages. Therefore, the SVLs should withstand the temporary overvoltage resulting from the system faults. There were not clear criteria for SVL selection during transient overvoltage conditions (lightning and switching). Traditionally, the maximum value of discharge voltages was limited by utility and cable manufacture experience. In any case internal cable fault conditions have not been considered to specify SVLs.

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8.1.3.7 Tests During Installation The following after installation tests were carried out on the majority of lines in service: • Outer sheath voltage tests according to IEC60229 (maximum 10 kV dc) • Visual inspection of bonding system connections. • Measurements of contact resistance (only in some countries).

8.1.3.8 Maintenance Test Off-line maintenance tests were mostly carried out. In recent years, some countries began to perform on-line measurements, such as, measurements of metal sheath currents. The following maintenance tests were carried out by a majority of the countries: • Outersheath voltage tests according to IEC60229 but at a reduced (typical 50%) voltage. • Visual inspection of bonding system connections

8.2

Bonding System Design and Protection

8.2.1

Bonding Designs

This section discusses the sheath bonding designs which are commonly used in transmission systems. The following clauses cover the practical and theoretical aspects of different bonding configurations. It is the intention that the reader will take common practical issues into account when designing the sheath bonding system. In the design of a sheath bonding arrangement, consideration must be given to: (a) Choice of sheath bonding systems. (b) Cable sheaths are usually expected to be nominally at earth potential. In some schemes, the sheaths may reach an appreciable voltage to earth along the cable system. Metal sheaths must therefore be provided with adequate insulation. (c) Complete suppression of circulating currents may not always be possible in practice. The residual sheath currents should be calculated to assess their effect on cable rating. (d) Sheath overvoltages during system transients and faults. Sheath voltage limiting devices may be needed with technical features to be coordinated with sheath insulation level and expected overvoltages. (e) Failure of a part of the sheath insulation or of a Sheath Voltage Limiter (SVL) may result in higher sheath currents which may overheat the cables. A prudent circuit design requires that consideration be given to the duty imposed on the SVL device and to periodic monitoring and maintenance of the complete system during operation.

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Some bonding options include: • • • • • • • •

Solid or multi-point bonding, see Sect. 8.2.1.1 Single point bonding, see Sect. 8.2.1.2 Mid-point bonding, see Sect. 8.2.1.3 Cross-bonding, see Sect. 8.2.1.4 Cross-bonding in tunnel installation, see Sect. 8.2.1.5 Impedance bonding, see Sect. 8.2.1.6 Siphon lines, see Sect. 8.2.1.7 Bonding for special cable systems, see Sect. 8.2.1.8

Any variations from the bonding configurations discussed in the document should be studied individually to ensure they meet performance requirements.

8.2.1.1 Solid or Multi-point Bonding Metal sheaths are directly grounded at both ends (substation, tower) of the underground link (See Fig. 8.11) and, sometimes, at defined intermediate points, as shown in Fig. 8.12. The solid bonding system uses bonding leads at both ends and at intermediate points of a cable circuit. It is a simple and low cost option with minimum maintenance requirements. Cable conductor current will induce circulating currents on the metal sheaths. The magnitude of the induced currents can be high, e.g., up to 80% of the conductor current for a 225 kV cable circuit (See Sect. 8.2.1.9). The induced currents produce Joule losses, whose influences on cable circuit current rating can be significant. As a result, the cross-section of the cable conductor needs to be increased to maintain the circuit ratings due to the circulating current losses of the sheath. It is noted that the magnitude of the induced current is independent of the length of the underground cable line. Cable end

Metallic sheath Core conductor

A

Fig. 8.11 Solid bonding system without intermediate grounding points

B

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Joint with grounding

Joint with grounding

Groun ding point

Groud ing point

A

D B

C

Fig. 8.12 Solid bonding system with intermediate grounding points

The voltage induced on the metal sheaths by phase conductor current is proportional to the length of the underground cable line. In the case of a solid bonding, metal sheaths are considered at earth potential at every point of the link. Solid bonding is commonly used for low and medium voltage systems. Actual sheath voltage profile of the link depends on grounding resistances at both ends. If a fault occurs on the cable, solidly bonded metal sheaths are useful to evacuate zero-sequence current. Bonding leads should be designed to withstand this current. Intermediate grounding points can be inserted on the cable, commonly at jointing locations, to prevent any damage of the outer sheath in case of disconnection of a solid grounding point at the end of the cable (Fig. 8.12). When the link is too long, such a disconnection can generate induced voltage on the metal sheath greater than its maximum allowable sheath voltage. This design is commonly used with up to two intermediate grounding points, considering that intermediate points cannot be accidentally disconnected. The distance between an intermediate grounding point and the end of the cable must be considered to control the induced voltage within the design limit. Grounding every joint may reduce the induced voltage to a minimum. With solid or multi-point bonding, the magnetic field external to the cable is relatively low due to the opposing sheath current to the cable phase conductor current. This bonding configuration was widely used over the previous decades, and tends to be abandoned for new installations at transmission voltages, due to the advantages of other bonding configurations. It remains a solution for short links with low current rating requirements, low or medium voltage level systems, and submarine cables. For effective solid bonding, it may be a good practice to use two independent, parallel earth bonding leads at each connection to minimize the effect of a disconnection or bad connection of one of the two leads.

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8.2.1.2 Single Point Bonding For single point bonding configuration, only one end of the cable metal sheath is directly grounded to the earth link at, e.g., substation or tower. The other end of cable metal sheath is open with a sheath voltage limiter (SVL) typically connected between the open end and the local earth link. The SVL is to protect the cable outer protection at the open end from electromagnetic transient. An example of such a configuration is shown in Fig. 8.13. An earth continuity conductor (ECC) is installed in parallel with the power cable for single point bonded systems except when the cable terminals share the common earthing system. As shown in Fig. 8.13, the ECC should be transposed in the middle of cable section in order to minimize the circulating current induced in the ECC by the three phase currents while an effective earth return path is provided in the proximity of power cables. Multiple transposing locations may be used. Relative locations of the ECC to the phase cables are also a factor that can be evaluated using available engineering tools. Single point bonding is considered less complicated for managing losses for rating purposes. It provides improved cable current carrying capacity by eliminating the circuiting current losses in the metal sheath. Single point bonding can be applied to a single section of cable between substations and/or overhead towers. It can also be applied at the ends or in the middle of an underground cable circuit if one or two extra cable section(s) exist in addition to major cross-bonding sections. Single point bonding is insensitive to balanced adjacent section lengths compared to cross-bonding configurations. Single point bonding can also be used in a sectionalized scheme where long cable systems consists of multiple individual single point bonding sections (sectionalized), Fig. 8.14. A sectionalized single point bonding system is a way to increase the maximum cable system length while maintaining low losses (cross-bonding also fulfils these requirements). All minor cable sections between joints have one end connected solidly to ground, and one end connected across SVLs. Similar to single Cable end Metal sheath

Sheath voltage limiter Earth continuity conductor

Fig. 8.13 Single point bonding system

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SVLs

Joint

ECC

SVLs

Joint

SVLs

Fig. 8.14 Sectionalized single point bonding system

point bonding, in addition, sectionalized single point bonded systems allows for longer cable system lengths with reduced screen voltages, while maintaining low screen losses. Similar to single point bonding, it is especially noted that the zero sequence impedance of the sectionalized single point bonded systems may be high and that the induced screen voltages may be higher than for cross bonded systems. Sectionalized single point bonded systems are simple by design, compared to crossbonding, but may experience increased losses due to circulating currents in the ECC. Single point bonding in general is insensitive to balanced adjacent section lengths compared to cross-bonding configurations. The voltage induced on the metal sheaths by phase conductor currents is proportional to the length of the underground cable section. Therefore, depending on the limitation of standing sheath voltages, the applicable cable length can be limited. Standing voltage limits are typically 50 to 400 V, but may be higher depending on requirements from different countries. For some countries, if the voltage is higher than 50 V, the live component should be shielded for safety reasons. If a fault occurs on the circuit, the sheath induced voltage could be the highest among all bonding configurations due to the high zero sequence impedance. Generally, the bonding system insulation must withstand the induced ac voltage for the entire lifetime, even under conditions of chemical, water, or other possible environment stresses. Using an additional earth return path such as the earth continuity conductor (ECC) or local common earth is necessary to reduce the sheath induced voltage and the interference to other electrical equipment (e.g., communication cables). To ensure the efficiency of the ECC in the fault condition, it is desirable to install ECC close enough to the three power cables, but yet the ECC should not be derating the power cable as a result of the circulating current in ECC in the operating condition. ECC is required to withstand the earth fault current and withstand attendant voltage rise from the earth. It is worth mentioning that to ensure the efficiency of SVLs in transient conditions, lower rated voltage SVL is desirable in terms of low residual voltage but SVL should not be damaged by power frequency induced voltages in fault conditions.

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In case that both single point bonding and cross-bonding are applicable, and if crossbonding is more economical than single point bonding, cross-bonding is recommended due to its known advantages: generally, no ECC required, lower zero sequence impedance, lower sheath induced voltage, and lower earth potential rise.

8.2.1.3 Mid-point Bonding Mid-point bonding system consists of two single point bonding systems. Both ends of the cable metal sheath are open and the mid-point is grounded through the parallel earth continuity conductor. SVLs are typically connected between metal sheath and the local earth at the open ends (e.g., in substations, or at transition towers). Figure 8.15 is a typical example of such bonding configuration. Mid-point bonding is used to reduce the sheath induced voltage to about half of the single point bonding of the entire cable length. One configuration of mid-point bonding is to use two minor sections of the cable sections by adding one earth joint in the middle of the cable route. This configuration bonding can be applied either by a sectionalized joint with both sides of shielding interrupts grounded or by connecting three cable metal sheaths together (star connection) at the midpoint to the earth without a sectionalized joint if it is applicable to the cable design. Another configuration of the mid-point bonding is to have the open ends and SVLs in the middle and connect the cable ends in substations or at transition poles to earth. This configuration may result in doubling the voltage at the joint interrupt in the middle, but improving safety concerns at the cable ends in substations or at transition poles. The same considerations for the single point bonding can be taken to ensure efficiency of ECC and SVLs. Especially, if either end of the mid-point bonding system is not at the termination of the cable route, but connected to the sectionalized cable joint. Special care must be taken to protect screen interrupts from electromagnetic transients. Cable end Metal sheath

Sheath voltage limiter

Earth continuity conductor

Fig. 8.15 Mid-point bonding system

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Screen voltage

Distance

Fig. 8.16 Typical cross-bonding system

8.2.1.4 Cross-Bonding Figure 8.16 shows a configuration of a cross-bonding system. The sheath continuity is interrupted at regular minor section length by cross-bonding joints. Connections are made between the sheaths so that each sheath circuit connects the three phase conductors successively. In this way, induced voltages in the screen circuits are reduced (in the ideal case, three voltages offset by 120 are added up), and thus the sheath circulating currents are reduced. 8.2.1.4.1 Continuous Cross-Bonding In order to protect screen interruptions from electromagnetic transients, sheath voltage limiters (SVL) are installed at cross-bonding points, see Fig. 8.17. Compared to single-point bonding, this configuration has the advantage of not limiting the length of the cable system. Terminations

Cross-bonding joints

Fig. 8.17 Continuous cross-bonding system

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The sheaths constitute a return path for zero-sequence fault currents. The screening effect reduces the induced voltages in parallel conductors (such as telecommunication cables) more efficiently than the screening offered by the earth continuity conductor in case of single-point bonding. Continuous cross-bonding has the major advantage that dissimilar minor section lengths are evened out over a larger number of minor sections than sectionalized cross-bonding. Besides, if a residual voltage is allowed, the number of minor sections does not need to be a multiple of three. Generally, sheath induced voltages and circulating currents decrease when the number of sections increases. On the other hand, a complete compensation may never be achieved. It is essential to consider this possibility when determining the current rating of the circuit, rather than simply assuming that the sheath circulating current will be zero.

8.2.1.4.2 Sectionalized Cross-Bonding The sectionalized cross-bonding configuration consists of multiple major sections along a cable circuit. A major section consists of three minor sections. Figure 8.18 is a typical example of such configuration. Compared to the continuous cross-bonding, the sheaths of the sectionalized crossbonding are connected to the ground at the ends of the major sections to complete one section (sectionalized). Dissimilar minor section lengths may cause sheath circulating currents. The circulating current may reduce the circuit rating. For example, an imbalance of about 30% in minor section length for a touching trefoil laying or an imbalance of about 25% in minor section length for a trefoil laying in ducts may result in a reduction of 1% in circuit ampacity. For a flat formation with 40 cm spacing between phase cables, the same 1% reduction is obtained with an imbalance of about 15% in minor section length. The imbalance here refers to the length difference between two minor sections and the third one is the average of the other two.

Terminations

Cross-bonding joints

Earthing joints

Minor section Major section

Fig. 8.18 Sectionalized cross-bonding system

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Compared to continuous cross-bonding, sectionalized cross-bonding has two advantages: it requires a smaller number of SVLs, and the more frequent grounding leads to the reduction of transient overvoltages travelling along the circuit. The drawback, compared with continuous cross bonding, is that it may be more difficult to perform sheath jacket integrity tests. For continuous cross-bonding, the jacket test can be performed from one termination only after disconnecting the grounding connections at both terminations. For circuits without a multiple of three minor sections, a combination of bonding configurations may be applied, e.g., cross-bonding and single point bonding.

8.2.1.4.3 Cross-Bonding and Transposition In order to reduce the induced voltages and sheath circulating currents by cable phase conductors, cables can be transposed, e.g., at each joint pit/chamber. This way, the mean geometric distances between parallel cables are equal. The induced voltage in the sheath is then near zero when the circuit configuration is unchanged. It is worth mentioning that, even for a trefoil laying, transposition of the cables is recommended to limit the induced voltages by nearby conductors. Figures 8.19 and 8.20 show the cable transposition concept. It must be acknowledged that perfect cross-bonding, and thus total cancellation of circulating currents, is only achieved when the cable mutual impedance is equal between different minor lengths. This is especially important when one minor section has a different laying configuration than the other two of that major section, which may be the case for long horizontal directional drillings (HDDs), etc. For such installations special attention must be given to ensuring equal mutual impedance between the cables.

Fig. 8.19 Cable transposition

Parallel conductor Transposed cables

Apparent distance between cables and parallel conductor:

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Terminations

Cross-bonding joints

Earthing joints

Minor section Major section

Fig. 8.20 Sectionalized cross-bonding system with cable transposition typically near joints

8.2.1.4.4 Direct Cross-Bonding Direct cross-bonding is a method where the screens are transposed directly (without the need for link boxes). Direct cross-bonding is a simple scheme that allows for fewer accessories (link boxes and SVLs) than for other cross bonding methods, Fig. 8.21. In direct cross-bonding, shorter single core bonding leads can be used, as the leads do not need go to a link box, but may go directly from one joint to the next. The highest transient overvoltages occur in sections closest to the terminations. Therefore, it is conceivable to limit the protection of screen interruptions to major sections located at both ends of the circuit. At the other cross-bonding points, cross-bonding of the screens is then performed “directly” by jointing single-core bonding leads without SVLs. In some cases, when the overvoltages which are likely to stress the materials are deemed acceptable, it is possible to design circuits without any SVLs. The simplicity of direct cross bonding reduces the number of accessories to install and therefore reduces possibility of failures and maintenance requirements. As no link boxes are used, disconnection of the cable screens is not straight-forward. For jacket testing and fault location, it may therefore be necessary to cut the bonding cables in order to perform some bonding system measurements.

Fig. 8.21 Direct cross bonding – Middle major section is directly cross bonded

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Terminations

Cross-bonding joints

Earthing joints

Minor section Major section

Fig. 8.22 Direct sectionalized cross-bonding system without SVLs

Direct Sectionalized Cross-Bonding The highest transient overvoltages appear in the sections closest to the terminations, if the transient voltages are caused by lightning or switching surges originated from the substations or transition poles where the terminations are located. Based on this assumption, transient voltage protection for the sheath insulation jacket and sheath joint interrupts is only located at the termination ends of the circuit. At the other cross-bonding points of the circuit, cross-bonding of the screens is then performed “directly” by jointing single-core bonding leads, without SVLs. In some cases, when the overvoltages which are likely to stress the materials are deemed acceptable, it is even possible to do without any SVL on the whole link (Fig. 8.22). 8.2.1.4.5 Cross-Bonding of Short Lines Some cable circuits may be too long for single point bonding due to standing voltage limits, and practical issues may make it difficult for cross-bonding with three minor sections. For this case, cross-bonding with only two minor sections may be applied. This solution is not optimal, but the circulating currents can be still reduced, compared to solid bonding. It can be shown that the circulating currents for cross-bonding with two minor sections are half of the circulating currents for solid bonding, Fig. 8.23. Terminations

Cross-bonding joints

Fig. 8.23 Cross-bonding system of short lines with two minor sections

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Fig. 8.24 Direct cross bonding with SVLs in tunnels (direct grounding at both ends not shown)

8.2.1.5 Cross-Bonding in Tunnel Installations Special attention must be given to cross bonded systems installed in tunnels. Generally, in tunnels, all joints and the bonding system are accessible for maintenance, while local grounding locations are often limited or prohibited inside the tunnel due to constraints by the tunnel construction (concern of water seal or cracking, etc.). In order to take advantage of the accessibility to the joints in tunnels, SVLs are generally connected with the shortest possible leads across the sheath interruptions. A direct cross bonded system is normally used in tunnels as shown in Fig. 8.24. With this arrangement, the cross bonding leads connecting the sheaths of different phases are not required to carry surge current and hence their length and inductance are not of importance. However, the leads must be of adequate cross section to carry system short circuit currents. This cross bonding scheme does not require link boxes. Grounding point is also not required at the sheath sectionalized joints. Sheath interruption of joints are protected by SVLs installed with a delta-connection between three phases of bonding leads, comparing with regular cross bonding link box that uses a star-connection with neutral point grounded. The effectiveness of delta connection of SVLs is described in CIGRE Electra 128 and the shortest bonding lead connection of SVLs can provide more effective protection for the sheath interrupter of joints. SVLs and their bonding leads to joints shall be protected from moisture ingress by suitable insulation thus there is no easy way for temporary disconnection of SVLs from the particular joints. Higher rated voltage (usually two times) is required for SVLs than for star-connected SVLs in regular cross bonding link box because of the higher induced voltage appearing across sheath interruptions under normal and transient conditions. 8.2.1.6 Impedance Bonding Impedance bonding is a form of solid bonding but with three-phase sheath bonding transformers. The system configuration is described in IEEE 575. The primary advantage of the shield/sheath bonding transformer scheme is that it is effective in limiting induced shield/sheath currents regardless of whether or not the distances between cable joint bays are equal or unequal. It is noted that the use of the impedance bonding system is limited. The primary disadvantage of the shield/sheath bonding transformer scheme is that additional space is required in the joint vaults to

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accommodate the additional components (compared to other screen bonding methods). The cost of the equipment for implementing transformer bonding is also generally higher than that for single-point or cross bonding schemes. Impedance bonding is not further discussed in the present document.

8.2.1.7 Siphon Lines Circuits connecting overhead lines and underground cables (so-called siphon lines) require additional analyses in order to establish a safe and optimum cable sheath bonding system. At substations, the sheath can be grounded through a well-established earthing method. However, outside of substations, ideal grounding may not always be available. Due to the exposure of the sheath when going from overhead line to underground cable, high voltages on the sheath and on the sheath interruption at cross-bonded joints may be experienced during faults or lightning strikes. The approach to designing the bonding system of a siphon line is similar to a regular cable system. However, the designer must be especially aware that the grounding resistance at the transition pole may be larger than in a substation. Therefore, the overvoltages during faults and lightning strikes may be significantly higher than in a substation. The design requirement of SVLs, cable jacket, and sheath interruption for cross-bonding joints must consider these factors. 8.2.1.8 Bonding of Special Cable System Designs 8.2.1.8.1 Parallel Cable Systems Special attention should be given to situations where two cable systems are installed in parallel or in close proximity of each other. In relation to the bonding schemes, it must be noted that the mutual coupling between the cable phase conductors of the first circuit to the screens of the second circuit must be properly considered because the otherwise balanced bonding system may become unbalanced due to the effect of the adjacent circuit. In general, it may be recommended to transpose the phase conductors in order to obtain maximum balance of the system. The losses in parallel cable systems must also be considered very carefully. Some additional guidance is available for parallel solidly bonded cable systems in, for example, IEC 60287-1-2 for the eddy loss factors of parallel circuits in flat formation (International Electrotechnical Commission 1993). 8.2.1.8.2 Multiple Cables per Phase The ampacity requirement for some cable projects may lead to the use of more than one cable conductor per phase. In general, this system design should be handled in a way similar to cable systems with circuits in parallel, and thus the special considerations are also similar. 8.2.1.8.3 Cable Systems with a Fourth Conductor For some cable systems, it may be beneficial to install four cables per circuit instead of three. The “fourth phase” can be used as a spare in case of a fault on

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one of the three operating phases to minimize repair time. For all bonding schemes, it is noted that the fourth phase can cause unbalance to the system due to the interphase distance change. The analysis of this unbalance should be made for each cable project in order to optimize the design of the cable and bonding system.

8.2.1.9 Example of Induced Voltage Calculations of a Single Point Bonded System

E1 E2 Sheath Voltage Limiter

α¼e

1

j2π 3

D¼

2e2 γ

ωμ ρsoil

γ ¼ e0,577

The following notations are used. • Rs: Metal sheath resistance • rs: Metal sheath mean radius • dij: Distance between phases Describe or define all symbols (e.g., R1, R2, D, etc.) The metal sheath self-impedance is: Zs ¼

ωμ ωμ D þ Rs þ j ln 8 2π rs

The mutual impedance between core conductor and metal sheath is: Zm ¼

ωμ ωμ D þj ln 8 2π rs

The mutual impedance between phases is: Z ij ¼

ωμ ωμ D þj ln 8 2π dij

E3

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(1) Normal operating condition and three phase symmetrical fault Assuming that the current flowing in the earth continuity conductor are negligible, the sheath voltage at open end may be derived: E1 ¼ Z m I 1 þ Z 12 I 2 þ Z13 I 3 Assuming three phase symmetrical currents, p p 3 1 1 3 I 1 ¼ ðI, 0Þ, I 2 ¼ I  ,  , I3 ¼ I  , 2 2 2 2 Real part of the mutual impedance is cancelled, thus p p p d 12 d 13 3 ωμ D d D E1 ¼ j ln 12   I  ln  p  p þj 2 2π rs d D 13 D D p 3 ωμ 1 d d d ¼j ln 12 I ln 12 2 13 þ j 2 2π 2 d13 rs For a trefoil formation, s ¼ d12 ¼ d13 ¼ d23, where s ¼ phase spacing E1 ¼ j

ωμ s  I  ln 2π rs

(2) Single phase earth fault external to cables (solidly earthed neutral) It is assumed the single phase short circuit return current flows entirely in the earth continuity conductor and that the phase currents in the non-faulted phases are negligible. The sheath voltage to local earth may be derived: EF ¼ Z if I f þ Z ic I c where, If ¼ Earth fault current in conductor Ic ¼ Earth fault return current in ECC The mutual impedance between fault conductor and metal sheath i is Z if ¼

ωμ ωμ D þj ln 8 2π sif

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The mutual impedance between ECC and metal sheath i is: Z ic ¼

ωμ ωμ D þj ln 8 2π sic

The self-impedance of ECC is: Z c ¼ Rc þ j

ωμ D ln 2π γc

Assuming If ¼ Ic, the real part of impedance is cancelled, thus the sheath induced voltage is expressed by: Ef ¼ j

ωμ s  I  ln ic 2π f sif

where, scf: spacing between the ECC and the faulty cable sif: spacing between screen of cable I and the fault cable sic: spacing between screen of cable and the ECC Note that Ef is the voltage to the earth at the current injection point, not to the local earth at remote end. As the biggest concern for the cable outer protection is normally the voltage between the cable metal sheath and the local earth, Earth Potential Rise (EPR) is taken into account which is expressed by: EEPR ¼ Zc  I c þ Zcf  I f Therefore, the voltage from the screen to the local earth is expressed by E f  EEPR ¼ Z if I f þ Zic I c  Z c I c  Z cf I f ¼j

scf ωμ ωμ sic  I  ln ln  I c Rc þ j 2π f 2π sif γc

Assuming Ic ¼ If, the screen to local earth voltage of the faulty cable is derived: 2

E ¼ Rc þ j

Scf ωμ  ln If 2π rs  γ c

½V=m

According to Electra 128 and CIGRE TB 283, this assumption is normally true and leads to sheath overvoltages which are slightly higher than those observed in practice.

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8.2.1.10 Example of Circulating Current Calculations for a Solid Bonded System

α¼e

j2π 3

R¼

R1 þ R2 L

1

D¼

2e2 γ

ωμ ρsoil

γ ¼ e0,577

The following notations are used: • Rs: Metal sheath resistance • rs: Metal sheath mean radius • dij: Distance between phases The metal sheath self-impedance is: Zs ¼

ωμ ωμ D þ Rs þ j ln 8 2π rs

The mutual impedance between core conductor and metal sheath is: Zm ¼

ωμ ωμ D þj ln 8 2π rs

The mutual impedance between phases is: Z ij ¼

ωμ ωμ D þj ln 8 2π dij

Assuming a trefoil laying configuration with a spacing between phase conductors S and assuming: Z12 ¼ Z13 ¼ Z23 ¼ Zc

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Through Kirchhoff’s laws, the following equation is derived: R1 R ðI þ Is2 þ Is3 Þ þ 2 ðIs1 þ Is2 þ I s3 Þ ¼ 0 L s1 L R1 R2 Zs Is2 þ Zm Ic2 þ Zc ðI c1 þ Is1 þ Ic3 þ Is3 Þ þ ðIs1 þ Is2 þ Is3 Þ þ ðIs1 þ Is2 þ I s3 Þ ¼ 0 L L R1 R2 Zs Is3 þ Zm Ic3 þ Zc ðI c1 þ Is1 þ Ic2 þ Is2 Þ þ ðIs1 þ Is2 þ Is3 Þ þ ðIs1 þ Is2 þ I s3 Þ ¼ 0 L L Zs Is1 þ Zm Ic1 þ Zc ðI c2 þ Is2 þ Ic3 þ Is3 Þ þ

Thus: ðZ s þ RÞI s1 þ ðZ c þ RÞI s2 þ ðZ c þ RÞI s3 þ ðZ m  Zc ÞI ¼ 0 ðZs þ RÞI s2 þ ðZ c þ RÞI s1 þ ðZ c þ RÞI s3 þ ðZ m  Zc Þα² I ¼ 0 ðZs þ RÞI s3 þ ðZ c þ RÞI s1 þ ðZ c þ RÞI s2 þ ðZ m  Zc ÞαI ¼ 0 With a ¼ Zs þ R and b ¼ Zc þ R, then:

with A ¼

a

b

b

I s1

b b

a b

b a

I s2 I s3

a

b b

b b

a b b a

1 ¼

α² α

ðZ m  Zc ÞI

1 t comA: and A1 ¼ detA

det A ¼ a3  3ab2 þ 2b3 com A ¼

a2  b²

b2  ab

b2  ab

b2  ab b2  ab

a2  b² b2  ab

b2  ab a2  b²

Hence: I s1 I s2 I s3 I s1 I s2 I s3

1 ¼ 3 a  3ab2 þ 2b3

a2  b2 2

2

2

2

b  ab a  b b  ab b2  ab b2  ab a2  b2

1 ¼ ða  bÞ a2 þ ab  2b2 I s1 I s2 I s3

b2  ab b2  ab

¼

1 α2 α

ðZ m  Z c ÞI

a2  b2  b2 þ ab 2

2

2

a  b  b þ ab a2  b2  b2 þ ab

1 ðZ  Z c Þ ab m

I α2 I αI

I ðZ m  Z c Þ

α2 I αI

530

T. Zhao

I s1 ¼ 

Zm  Zc Z  Zc ² Z  Zc I; I s2 ¼  m α I; I s3 ¼  m αI; Zs  Zc Zs  Zc Zs  Zc

Thus, the metal sheath current to core conductor current ratio is: η¼

I si Z  Zc ¼ ¼ m I Zs  Zc

ωμ 8

η¼

ωμ 8

þ j ωμ 2π ln

D rs

þ Rs þ j ωμ 2π ln j ωμ 2π ln

S rs

Rs þ j ωμ 2π ln ωμ 2π

η¼

R2s þ

ωμ  ωμ 8  j 2π ln D rs

D S

ωμ  ωμ 8  j 2π ln

D S

S rs

S rs

ln ωμ 2π

ln

S rs

2

A numerical application with a 225 kV cable commonly used in France gives the following table: 630 Al 2rs (mm) 82.6 Rs (Ω/km) 9.12E02 S (mm) 200 η 74%

1200 Al

1600 Al

2000 Al

2500 Al

1200 Cu

1600 Cu

2000 Cu

2500 Cu

95.2 9.50E02 240 73%

102.4 1.10E01 240 66%

109 1.04E01 240 67%

117 9.66E02 290 72%

96.3 9.39E02 240 73%

103.3 1.09E01 240 66%

109 1.04E01 240 67%

117 9.66E02 290 72%

8.2.1.11 Example of Circulating Current Calculations for a Cross-Bonded System with Two Minor Sections

Following the same approach as for solid bonding (see Sect. 8.2.1.9), Kirchhoff’s laws yield: Zs þ R Zc þ R

Zc þ R Zs þ R

Zc þ R Zc þ R

I s1 I s2

Zc þ R

Zc þ R

Zs þ R

I s3

Z  Zc ¼ m I 2

α 1 α2

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Sheath Bonding Equipment for AC Transmission Cable Systems

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where, R¼

R1 þ R2 2L

After inversion of the matrix, the following equation is derived: I s1 I s2 I s3

¼

1 Zm  Zc I 2 Zs  Zc

α 1 α2

The equation shows that circulating currents are half of the circulating currents of the solid bonded system.

8.2.2

Sheath Voltage Limiter Selection and Application

8.2.2.1 Sheath Voltage Limiters Standard surge arresters at power system voltage levels are generally used at the cable terminals (e.g., substations or transition poles) to protect the primary insulation of the cable systems. Sheath voltage limiters are used to protect the sheath bonding system insulation from transient overvoltage events due to lightning strikes and switching surges. The designed insulation level of the sheath insulation and bonding system should also consider overvoltages in the event of cable faults or fault currents running in the cable system. The sheath voltage limiter is usually rated for distribution voltage levels. The selection of a sheath voltage limiter (SVL) is important. Without some means to limit the transient overvoltages, the excessive voltage may cause an electrical breakdown of the sheath insulating jacket, sheath interrupts in sectionalizing joints, bonding cables, the termination mounting insulation at the cable terminals, or other components as part of the sheath bonding systems. For example, the damage to the insulating jacket may make the metal sheath susceptible to corrosion and can result in unanticipated sheath circulating currents that may increase losses of the cable systems and cause hot spots along the cable route. To protect the cable insulating jacket and other components of the bonding systems from transient overvoltages, sheath voltage limiters must be applied to limit the overvoltage across the insulation to prevent insulation breakdown. Industry standards (e.g., IEC 60229 as referred by both IEC 60840 and IEC 62067) require that the insulating jackets withstand the nominal ac voltage and impulse voltages. The magnitudes of power frequency overvoltages depend on rated system voltages, cable section lengths and the magnitude of cable fault currents. Both longer cable section lengths and greater fault currents contribute to greater magnitude of power frequency overvoltages occurring between the metal sheath and the earth.

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Sheath voltage limiters (SVLs) are generally defined as surge arresters with metal oxide varistors (MOV) in the protective housing but without spark gaps. SVLs are generally designed and tested in accordance with IEC 60099-4, “Part 4: Metal-oxide surge arresters without gaps for ac systems” (International Electrotechnical Commission 2014). Their characteristics are selected for operation in the event of transient overvoltage that will exceed the insulation withstand range for the cable metal sheath of the extruded dielectric or low-pressure oil-filled cables. Some utilities still use spark gaps, including the specialized “ring gaps,” independently or in series with SVLs. A few utilities retain these devices in their specifications. The spark gaps are not subjected to deterioration in the manner of non-linear devices, and they can be left in the system during maintenance testing and fault location without adverse effects. However, this brochure is focused on the application of metal oxide varistor surge arrestors only. The selection of appropriate SVLs must be determined based on the anticipated ac voltage under normal and fault conditions and the required discharge voltages to protect the bonding system insulation from transient overvoltages due to lightning strikes, switching surges or cable system faults. The SVL is designed to withstand the power frequency voltage appearing during normal system conditions and during system faults and to protect the bonding system insulation from transient overvoltages, considering the effect of voltage drop of the bonding leads and connection configurations. The SVL is not designed to mitigate the power frequency voltages due to system faults. The maximum magnitude of fault currents is usually determined by system planners based upon power system studies at various possible system faults, e.g., three-phase-to-earth fault, phase-to-phase fault, and single-phase-to-earth fault. This fault current magnitude combined with knowledge of the cable construction and trench geometry can determine the extent of induced voltages on the cable metal sheath layer during the fault events. Electra 28 (CIGRE WG 21.07 1973) Electra 128 (CIGRE WG 21.07 1990), TB 283 (CIGRE WG B1.18 2006), and IEEE 575 (IEEE PES 2014) provide guidance for the calculations. Internal cable faults create the highest induced sheath voltage, and the SVLs are not designed to protect such overvoltages, and will fail at such conditions if not correctly designed and selected. Usually, the highest induced sheath voltage occurs during a singlephase-to-ground fault for a single-point bonded system, and three-phase fault for a cross-bonded system. Earth potential rises should be considered, especially if the SVLs are star-connected to earth [see TB 347 (CIGRE WG B1.26 2008)]. These parameters, along with the insulation protection levels for transient overvoltages, provide guidance to selecting the protective properties of the sheath voltage limiters. A general practice of many countries is that the physical selection of the SVL is done by the cable material supplier in response to the user’s specifications. Users specify the SVL requirements by providing fault current levels of the cable systems, the associated maximum induced voltages, and parameters for the transient

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overvoltage calculations and simulations. The supplier then selects particular models of SVLs and a link box enclosure.

8.2.2.2 Selection of Sheath Voltage Limiters Typical characteristics of SVLs include: • • • • • • • • • •

Rated voltage Ur Maximum continuous operating voltage Uc Nominal discharge current High current impulse withstand Long duration current impulse withstand Short circuit withstand Maximum residual voltage, Ures Nominal creepage distance Typical temporary overvoltage curve Energy rating

The general procedure to select sheath voltage limiters includes the following. C55 (Electricity Networks Association 2014), Annex A, and Electra 128 (CIGRE WG 21.07 1990) describe the Design Guide for SVL selection and provide application examples. The procedure is further refined as below: 1. Calculate the sheath power frequency overvoltage during a fault at a specific fault duration, based on provided cable system information. 2. Compare the calculated power frequency overvoltage with the temporary overvoltage-versus-time (TOV) characteristics of a selected SVL. The calculated overvoltage shall be less than the temporary overvoltage value at a specific duration with a typical 5% to 25% protection margin. This is the minimum performance criteria for SVL selection. This selection approach requires that the SVL power frequency temporary overvoltage-versus-time characteristics be given. 3. If the TOV characteristics of the SVL are not available, the SVL can be selected based on its Maximum Continuous Operating Voltage, Uc. Uc should be higher than the calculated power frequency overvoltage. An inherent safety margin is included by the difference between the Maximum Continuous Operating Voltage, Uc, and the Rated Voltage, Ur. 4. Select the Rated Voltage, Ur, from the manufacturer’s SVL data sheet based on TOV comparison or selected Uc. The typical value of Ur is between 3 and 12.5 kV. A value of 3 kV is usually considered minimum. Note that Ur is 15–25% greater than Uc on published manufacturer’s data sheets. 5. Consider the residual Voltage, Ures, of the selected SVL. The voltage is the maximum arrester voltage tested at, e.g., 8/20 μs and 10 kA current impulse. This value should be less than the transient overvoltage withstand level of the

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T. Zhao

insulating components (cable jacket, sheath/screen interrupts in joint bodies, etc.). This evaluation of the residual voltage should also consider the length and type of bonding cables that can result in a greater voltage appearing at the components [see TB 283 (CIGRE WG B1.18 2006) and Paper B1-108 (Khamlichi et al. 2016]. In comparing the residual voltage to the BIL, the reader should be aware that the wave shapes are different (BIL is 1.2/50 μs). The margin of protection for the residual voltage over the component capability should be selected. A typical safety margin of 15 to 25% is used, with consideration of deterioration of the component respective insulating strength over the life of the components. The selection of SVLs is often done based on a 10 kA impulse current characteristic as this is often the nominal discharge current for a given surge pulse. 6. Verify the energy absorption capability of the SVL to withstand the maximum energy by the dissipated transient surge currents. The energy absorption capacity is determined as a function of the current duration and magnitude dissipated through the SVL. The amount of energy from the surge current is determined from a transient analysis study and compared to the manufacturer’s SVL characteristics. In most cases, this is not a determining factor in the selection of the SVL as the capability often exceeds the surge energy. Internal cable faults cause significant overvoltages at power frequency. If the SVL temporary overvoltage capability cannot withstand the overvoltage caused by the cable internal fault, the SVL often cannot withstand this energy level and may fail, which leads to the necessity to inspect at least the SVLs adjacent to the fault location after the fault event and to ensure designs with a correctly rated SVL selected for the bonding system. Applications of the primary arresters at the terminals of the cable circuits significantly limit the energy absorption requirements of the SVL. The SVL should not absorb energy at power frequency voltage during a fault. However, it will absorb energy during lightning and switching surges. The energy absorption can be evaluated at 10 kA with a standard current wave form for lightning impulse current, although the energy from the lightning impulses may not be the critical determining factor. Longer term events and associated conductive period such as switching surges and power frequency follow-up currents should also be considered. An EMTP study may be needed for this evaluation (see Sect. 8.2.3). The arrester devices are available in different classes based on different energy absorption capacity. IEC 60099 provides additional details on selecting the class of SVLs if this is a factor that requires further evaluation. Generally, the class designates the extent of the durability of the respective arrester. In lightning protection applications, a Class 1 surge protection device is used with a Class 2 for switching surge protection. Calculation procedures as described in CIGRE TB 283 (CIGRE WG B1.18 2006) and EMTP can be used for the evaluation. (Note: Classes 1 to 5 are replaced in IEC 60099-4:2014 using arrester classes of Station and Distribution. For each class, duties of Low, Medium and High are used. As such, the classes are designated as SH, SM, SL and DH, DM, DL.) In general, the SVLs are always designed to withstand (not to protect) temporary ac overvoltages induced for the maximum external cable fault durations. The SVLs

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may however not be able to withstand the temporary ac overvoltages caused by cable internal faults. If a cable system experiences a cable internal fault, the SVLs should be inspected before continuing use (see Sect. 8.3). The type and length of bonding lead between the cable sheath connections to the link box connection or earth connection affects the protection level of the sheath voltage limiter. Two types of bonding leads are used: single conductor or concentric construction. Selection of the type depends on the characteristic impedance (inductance) of the bonding leads; the link box must be configured for the selected bonding cable type. Single phase link boxes on some riser structures are required to closely position the bonding leads to the individual termination supports (usually within 10 m). The induced ac overvoltages caused by a fault can be a function of the type of cable sheath, such as helically or annularly corrugated sheath (Nichols 2012).

8.2.2.3 SVL Connection Configurations The voltage across the SVLs is a function of connection configurations and mounting schemes. The following connection configurations are used: • • • •

Star formation with the star point connected to earth continuity conductors Star formation without the star point connected to earth Delta connection Direct placement crossing sheath interrupt – using one SVL – higher voltage rating • Direct placement crossing sheath interrupt – using two SVLs and earth connection between the two SVLs Both single core bonding leads (with sheath grounded) and coaxial cable leads are used.

8.2.2.4 SVL Installations SVLs can be installed in a specially designed enclosure or link box. They can also be covered by other protection materials, such as, heat shrinkable insulation tubes. The number of SVLs used along the cable circuit and locations for SVL installation may be optimized through system study. In this optimized design, energy sharing among SVLs should be considered to reduce SVL failures due to excessive energy from internal cable faults. A general guide for the locations and number of sheath voltage limiter usages is listed below. An optimized decision must be made if some criteria are in conflict. • Installed in a protected location, such as, a substation, to prevent from explosive events or other safety concerns • Installed at the open end of single point bonding systems, with the grounded end of the single point bonding preferably at the end more subjected to lightning or switching impulses, or the end with the lower grounding resistance • Installed at locations more accessible for maintenance

536

T. Zhao

For single-point bonded cable systems, factors to consider in selecting the location of sheath voltage limiters include: • Accessibility of link boxes for inspection of SVLs following fault events. • The SVL should be located at the terminal end of the circuit that will experience the highest incoming transient voltage. An evaluation of switching surges and lightning impulse would both need to be considered. A GIS substation may have additional considerations where SVL shunts may be applied between the GIS flange and ground in the station. • The earthing point should ideally be selected at the terminal with the lowest earthing impedance. • Cable connected to certain equipment (e.g., metal clad switchgear) may see a steeper voltage rise, so this would be a preferable location for grounding the sheath.

8.2.3

Cable System Models for Overvoltage Calculations

The objective of this section is to provide guidance to assess the overvoltages which are likely to stress an underground cable circuit. Recommendations are given on modelling and calculation methods. Figure 8.25 shows an overview of the modelling and calculations. Cable impedances have been established through solving Maxwell’s equations of cable circuits for a defined installation environment. These impedances appear in the Telegrapher’s equations, which are the basis of cable modelling for transient studies. These models, which are implemented in some transient analysis software, are used to compute overvoltages stressing the underground cables subjected to lightning or switching impulses. Simplifications are obtained at power frequency. Easy to handle formulae can then be used to assess voltages and currents in both normal operations and faults. These studies do not require transient analysis software. Ready-made formulae are available in various documents and standards. When precision is needed, or to deal with particular configurations, methods exist which allow calculations almost by hand, for example: CIM (Complex Impedance Matrix), NV (Node Voltage), symmetrical component analysis. CABLE IMPEDANCES Schelkunoff Wedepohl Wilcox Simplified formulae at power frequency

TRANSIENTS CP, FDQ, Wideband implemented in EMT software

SVL POWER FREQUENCY CIM, NV, symmetrical components, formulae in standards

Fig. 8.25 Modelling for overvoltage calculations

Bonding lead OHL Grounding

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Sheath Bonding Equipment for AC Transmission Cable Systems

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Guidance is also given on the modelling of other components which have a significant impact on sheath bonding studies: SVL, bonding lead, grounding, and overhead lines. Some case studies are given as illustrations.

8.2.3.1 Cable Impedances and Admittances One modelling method is based on works by Schelkunoff (1934) for the internal impedances of single-core cables, and on works by Pollaczek (1931) for the mutual impedances between cables and for the ground. The Pollaczek formulae are quite complex, as these models involve Bessel functions with frequency-dependent argument. The integral for finding an analytical approximation is difficult, which makes it difficult to compute numerically because its integrand is highly oscillatory. On the basis of these above works, Wedepohl and Wilcox (1973) developed a model using numerical computation by replacing the Bessel functions using hyperbolic functions, with accuracy in a broad frequency range (up to about 100 kHz), for common cable technologies. In 1979, Ametani (1980) synthetized all the works previously mentioned, leading to a general formulation of the impedances and admittances of single-core and threecore cables. The work was implemented into EMT software. At power frequency, simple formulae can be derived, as shown in Fig. 8.26. TB 531 (CIGRE WG B1.30 2013) provides discussion on the current modelling and limitations. Besides analytical formulae, cable impedances can also be calculated through numerical computational methods such as Finite Element Analysis or Boundary Element Analysis. These methods are generally used for evaluation of cable systems with complicated cable geometry or arrangement that is not covered by existing analytical formulae.

Fig. 8.26 Simple formulae for overvoltage calculations (TB 531)

538 Fig. 8.27 CIM method for overvoltage calculations (TB 283)

T. Zhao

V1 Conductor 1

I1

R1

I2

R2

L1 V2

Conductor 2

L2

…

Zij Vn

Conductor n

In

Rn

Ln

8.2.3.2 Power Frequency Studies 8.2.3.2.1 CIM Method The Complex Impedance Matrix (CIM) method is illustrated in Fig. 8.27 (see CIGRE TB 283). Capacitance is neglected for the calculations of 50/60 Hz currents and voltages. The CIM method consists of using Kirchhoff’s laws for the system composed by all the conductors (cores, screens, earth, etc.), including all the (linear) equations under the form of: AX ¼ B where A is a matrix containing impedances and boundary conditions (e.g., grounding of the screens), X is a vector containing unknown voltages and currents and B is a vector containing known voltages and currents. Solving is simply done by inverting the matrix A. 8.2.3.2.2 NV Method The Node Voltage (NV) method is the similar to the CIM method, but it uses admittances instead of impedances for the calculations. The CIM method may be preferable to the NV method, because inverting empty matrices may lead to numerical errors for some cases. TB 347 discusses both methods and indicates that “The NV method is common for calculation of voltages in electrical networks by means of computer programs because the rules to establish the equation system can be formalized quite well.” “The NV method may be more attractive than CIM method, if multiple earthing points are to be considered (i.e., intermediate earthing in cross-bonded circuits).” Also, the NV method is more convenient for considering several links in parallel. 8.2.3.2.3 Symmetrical Component Analysis Symmetrical component analysis is discussed in many documents and is largely used for power frequency concerns, such as load flow and short-circuit calculations. The method can be used to calculate voltages and currents in phase conductors by assuming that the metal screen is at zero voltage. It is a helpful way to provide quick answers and get a good understanding of the system behavior. Figure 8.28 includes a summary of this

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Sheath Bonding Equipment for AC Transmission Cable Systems

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FORTESCUE SEQUENCES Positive sequence

Positive sequence The phase conductor currents are equal in magnitude and 120° out of phase. Representative of normal operation conditions.

I1

I

I2

D 2 .I

I3

I3

D .I

I1

w Vi wz



z  m .I i

z d .I i I2

zd is the positive sequence impedance Negative sequence

Negative sequence

I1

As the positive sequence, except that the phase sequence is reversed.



I

w Vi wz

I2

D .I

z  m .I i

I2

D 2 .I

I3

I1

z i .I i

I3

zi is the negative sequence impedance Zero sequence

Zero sequence

I1

The phase conductor currents are equal in magnitude and phase.

I

w  Vi wz

I2

I

I3

z  2.m .I i

I

I2 I1

z h .I i

I3

zh is the zero sequence impedance.

SYMMETRICAL COMPONENTS BACKGROUND Diagonalization of the impedance matrix

Z zm

zd

Eigenvalues:

ª z m mº «m z m» « » «¬m m z »¼ zi

zm

z  2.m

zh

Possible eigenvectors: Fd

ª1 º «D 2 » « » «¬ D »¼

Fi

Fortescue matrix and its inverse:

ª1 º «D » « » «¬D 2 »¼

F

Fh

ª1º «1» «» «¬1»¼

1 1º ª1 «D 2 D 1» « » «¬ D D 2 1»¼

Fig. 8.28 Symmetrical component analysis (TB 531)

D

1 3   j. 2 2

F

1

D2

1 3   j. 2 2

ª1 D D 2 º » 1« .«1 D 2 D » 3« 1 »» «¬1 1 ¼

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T. Zhao

Fig. 8.29 General approach with modal analysis

method. A more general approach can be done with modal analysis. This cannot be used to evaluate metal screen voltages since the voltages are assumed at zero potential. A more general approach can be done with modal analysis, even though this approach is used mostly for transient studies (Fig. 8.29). Single-phase to earth fault is the superposition of positive, negative, and zero sequences. In each of these sequences, the current is 1/3 of the single-phase short-circuit current. When earth resistances are nil at both ends, zero sequence screen potentials are nil, because the return current in the screens generates a voltage equal to the opposite of the voltage induced by the cores. Therefore, screen potential rises are only due to the positive and negative sequences, and is given by: I cc,single 2 V single ¼ V three 3 I cc,three

8.2.3.3 Transient Studies Extensive works exist on the topic of cable modelling for transient studies. The starting point is the Telegrapher’s equations: 

@V ¼ ZI @z



@I ¼ YV @z

where Z is the matrix of series impedances and Y the matrix of shunt impedance, or admittance.

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The usual approach to solve these equations is through modal analysis: transformation (diagonalization) matrices are used to change voltages and currents into independent variables, called modal voltages and modal currents. More details about the phase domain/modal domain is given in TB 531 (CIGRE WG B1.30 2013). The CP (Constant Parameters) model assumes that cable parameters and transformation matrices are constant. The FD (Frequency Dependent) model takes the variation of cable parameters with frequency into account. It should not be used for power frequency simulations. The FDQ model also takes the variation of transformation matrices (Q) with frequency into account. Following a different approach, another model, the wideband model, at least as accurate as the FDQ model, has been developed. However, some problems have been discovered with this model. Both the FDQ and wideband models are specific to EMTP and are implemented in EMT software programs. It was noted that sheath overvoltage calculations may be less accurate than those for core overvoltages. In EMTP’s CP model, the losses are included through lumped resistances. The more sophisticated models, i.e., FDQ and Wideband, use a different representation which takes into account the distributed nature of all parameters (EMTP 1995). In the CP model, all conductors (core, metal screen, pipe) are modelled the same way. The lumped resistances are used for the core and screen calculations as well. Table 8.3 lists the models actually implemented in EMT software programs. In EMTP CP model, losses are included through lumped resistances. But the models, i.e., FDQ and Wideband, use a different representation that takes into account the distributed nature of the parameters. In the CP model, all conductors (cores, metal screen, pipes. . .) are modelled as metal conductors. The models also use modelling of earth or cable environment mostly through estimation. Table 8.3 List of models implemented in EMT software programs Model CP

Characteristics Parameters of the π circuit calculated at a given frequency Real and constant transformation matrix

Frequency Fixed

FD

Parameters of the π circuit are frequency dependent Real and constant transformation matrix

HF beyond kHz

FDQ WB

Parameters of the π circuit and transformation matrix are frequency dependent

LF and HF

Advantages Simple

Drawbacks Frequency to choose depending on the study

Short computation time Allows verification of the data Stability More precise than CP

Underestimates damping at HF

Accuracy

Not recommended for computation of outer-sheath overvoltages (which involve low velocity modes, requiring accurate LF modelling) Longer computation time

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Fig. 8.30 Example SVL model as non-linear resistance

8.2.3.4 Modelling of Other Components References: CIGRE TB 283 and IEC TR 60071-4 8.2.3.4.1 SVLs If the study does not include overvoltages exceeding the rated voltage of SVLs, the SVLs can be modelled as open circuits. Otherwise, SVLs are modelled as non-linear resistances. A typical curve is shown in Fig. 8.30. The characteristics of the SVLs depends on the wave shape (e.g., 8/20 μs) of the tested voltage. 8.2.3.4.2 Bonding Leads Bonding leads are used to connect cable sheaths to the ground or to SVLs and the bonding leads are generally not included in power frequency studies. For transient studies, impedance of the bonding leads should be included. A voltage drop appears along the leads due to the inductance of the bonding leads at high frequency. v¼L

di dt

Both single-phase and coaxial bonding leads can be represented by inductance. The value of the inductance is given per unit length: L0 ¼

μ0 ln 2π

l þ r

1þ

l r

2

r þ  l

1þ

r l

2

8.2.3.4.3 Grounding Grounding is modelled by a resistance as shown in Fig. 8.31. Typical values of the resistance are 0.1 to 1 Ω in a substation; 8 to 10 Ω on a transition tower between an underground cable and an overhead line, 10 to 20 Ω on a regular tower, and 5 to 10 Ω at a joint pit. Different resistance values may be observed from different regions. Measurements are recommended to determine the actual values.

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Single-point bonding

Fig. 8.31 Modelling of grounding Ifault

VSVL Ifault

ecc

EPR

Earth potential EPR

Usually, the ECC is insulated as recommended. If the ECC is not insulated, the ECC is included as an earth electrode. When the current flows through this resistance, an earth potential rise (EPR) is observed. The earth potential decreases when the distance from the grounding increases. EPR may damage cable oversheaths, joint coverings, and SVLs. Therefore, EPR should be taken into account in the design of the link. 8.2.3.4.4

Overhead Lines

Power Frequency Studies If overhead lines (OHL) are included in the studies, the fault current return path involves the skywire(s), towers, and earth. In every span of the OHL, an induced voltage is generated due to the phase conductor/skywire coupling. This effect can be modelled as a voltage source resulting in a current flowing in the skywire, returning to the source, with magnitude μ  Isc, where μ is the coupling factor and Isc the short-circuit current. μ¼

Zmsw Z sw

Zsw is the self-impedance of the skywire and Zmsw is the mutual impedance between the faulted phase and the skywire.

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T. Zhao

Fig. 8.32 Impedance of long overhead lines

This flowing current is considered constant along the skywire. There is no current flowing through the towers. The current flowing to the earth through the skywire and the towers is (1  μ) ∙ Isc. The impedance of the return path looking from the fault terminals is the impedance of a ladder network, involving the self-impedance of the skywire and the resistances of the tower footings. This impedance may be estimated for long lines, with constant tower footing resistances as shown in Fig. 8.32. IEC 60909-3:2010 (part 3.11) provides more information on this topic. Z nþ1 ¼ Zsw L þ

RZ n R þ Zn

where R is the tower footing impedance and L is the span length. For an infinite number of spans: Z1 ¼ Zsw L þ

Z1 ¼

Z sw L þ

RZ 1 R þ Z1

ðZ sw LÞ2 þ 4RZ sw L  2

RZ sw L

Transient Studies For transient studies, the overhead conductors and skywires can be modelled by the FD model and the towers by the CP model with footing resistance and spark-gap. Special care should be given to the modelling of the transition tower since the surge arresters and bonding leads should be taken into account.

8.2.4

Insulation Coordination of Bonding Systems

8.2.4.1 Sheath Bonding System Insulation A cable sheath bonding system consists of components as listed: • Insulating cable jacket for metal sheaths • Sheath sectionalizing insulators and outer covering with sectionalized joints

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• • • •

Bonding cables from sectionalized joints to link boxes Internal insulating components of link boxes Earth connection conductor Mounting insulators for terminations

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Insulation coordination addresses assessment of overvoltages subjected to the system, insulation requirements of the components as a system, and effective application of protective devices. The overvoltages subjected to the bonding system include overvoltages caused by lightning strikes traveling mostly from the cable circuit terminals (substations and transition poles), switching surges traveling from the cable terminals, and external or internal faults. The overvoltages caused by the faults include power frequency temporary overvoltages with limited magnitude and duration and high frequency overvoltage especially at the front of the fault duration. For insulation coordination of a cable system, instead of considering the overvoltages and insulation strength in a statistical nature as for outdoor in-air insulation, the insulation of cable is not self-restoring and is assumed to fail if the overvoltage exceeds the insulation level. Insulation and protection levels of the bonding system shall be designed as a system. The insulation requirements of the system include: • Power frequency currents and voltages under normal operations due to phase conductor currents (sheath standing voltage) or external or internal cable faults (ac sheath temporary overvoltage) • Impulse voltages or transient overvoltage due to disconnector operations in GIS or lightning strikes and switching surges at cable terminals.

8.2.4.2 Sheath Bonding System and Component Requirements • Insulating jacket for metal sheath. Examples of requirements include the ones by IEC 60840, IEC 62067, and French Standard NF C 33-254. • Sheath sectionalizing insulators and outer covering with sectionalized joints with the same requirements as for the insulating jacket for metal sheath. • Bonding leads from sectionalized joints to link boxes with the similar requirements to for the insulating jacket for metal sheath. • Internal insulation of link boxes with specified insulation withstand capability of dc, ac, impulse voltages, fault current, and emergency loading requirements. • Earth connection conductor with fault current withstand capability • Mounting insulators for terminations with additional requirements for the specific installation. Details of the testing requirements are discussed in Sect. 8.1.3, Testing of Bonding Systems.

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Special Protection on GIS Cable Terminations Against High Frequency Transient Overvoltage

According with CIGRE WG 23-10: ELECTRA 151, 1993, high frequency transient enclosure voltage (TEV) is caused by lightning surges, operations of lightning arresters, phase-to-earth fault currents, or switching surge discharges between contacts. The high frequency transient currents cause localized transient overvoltages because of the relatively high reactance of earth connections. The high frequency transient overvoltages are generally confined to the inside of the screening provided by GIS enclosures. The GIS enclosures are designed to withstand such electrical stresses. The GIS enclosures also include discontinuities. The discontinuities may allow the high frequency effects transferred to the exterior of the GIS enclosures as it is the case for HV cable terminations according to IEEE Std. 1300-2011 (2012). The GIS cable terminations should be mounted with sheath sectionalizing insulators between the components electrically connected to the GIS enclosure and the cable sheath. Two main options are used to protect the system from the high frequency transient overvoltages at the discontinuities between the GIS enclosures and cable terminations. 1. Install a metallic earth connection between the GIS enclosure flange and cable sheath (see Fig. 8.33). This connection has the advantage of avoiding overvoltage between the GIS enclosure and the cable sheath. The disadvantage is that it causes permanent

Fig. 8.33 Example of earth connection between GIS enclosure and cable sheath

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Fig. 8.34 Scheme of typical earth connection on GIS cable termination. (A) Cable sheath connected to local earth by single-core bonded lead. (B) Earth connection between GIS enclosure and local earth. (C) Earth connection between GIS enclosure and cable sheath

circulation of current in a closed loop formed by the multiple connections to ground (see Fig. 8.34). This solution would not be convenient as the effects derived from the circulating currents between the grounding system of both cable and GIS may not be considered in design, especially if the GIS and the cable termination are supplied by different suppliers. 2. Install a nonlinear resistor (or bypass SVLs) across the sheath sectionalizing insulator to limit the overvoltage under transient conditions between the components electrically connected to the GIS enclosure and the cable sheath. The SVLs need to be mounted close to the gap to be protected and connected by short low-impedance leads (see Fig. 8.35). IEEE Standard 1300-2011 (2012) and IEC 62271-209 (2007) indicated that the number of nonlinear resistors (bypass SVLs) to use and their characteristics shall be determined by the cable termination manufacturer, taking into consideration of user and the switchgear manufacturer requirements. Further details as guidance to install properly bypass SVLs can be found in (Khamlichi et al. 2016). In the case of single-point bonding connection, where there are sheath voltage limiters (SVLs) installed on the GIS side (see Fig. 8.36), the sheath temporary overvoltage that appears between cable sheath and earth when a phase-to-ground fault occurs in the power grid is seen by both limiters: the sheath voltage limiter

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Fig. 8.35 Typical physical location of bypass SVLs: 1 – Nonlinear resistor, 2 – GIS enclosure, 3 – Cable sheath, 4 – Sheath sectionalizing insulator

Fig. 8.36 Single-point bonding connection where there are sheath voltage limiters installed on the GIS side

which protects the cable sheath, and the bypass sheath voltage limiter located between the cable sheath and the GIS enclosure. Therefore, the bypass SVL’s rated voltage, Ur, should be equal or higher than the sheath voltage limiter rated voltage, Ursheath, or Ur  U sheath , in order to ensure the integrity of the bypass SVLs r in case of phase-to-ground fault.

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8.3

Testing of Bonding Systems

8.3.1

Introduction and Section Scope

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Cable sheath bonding systems consist of components that are subjected to overvoltages and excessive currents. The systems and their components shall be properly designed and tested. There is no internationally recognized standard that targets specifically the testing of the sheath bonding system components or the bonding system as a whole after installation, for system commissioning or for maintenance inspection. The main components of the cable sheath bonding systems are defined in Sect. 8.2.4.1 and are also listed below. • • • • • •

Insulating cable jacket for metal sheaths Sheath sectionalizing insulators and outer covering with sectionalized joints Bonding cables from sectionalized joints to link boxes Internal insulating components of link boxes Earth connection conductor Mounting insulators for terminations

Some medium voltage cable systems utilize unjacketed concentric neutral type cables. The exposed concentric neutral conductor may become an extension of the substation grounding system and as such it is not included as part of the bonding systems addressed in this document. It is noted that the installation of such unjacketed concentric neutral type cables in the insulated ducts does not prevent corrosion. It is not the intent of this document to replace any existing applicable standards, regulations, or country-specific legislations. This document does not intend to provide guidance for testing safety. Engineering knowledge and judgment should therefore always be employed to achieve satisfactory results.

8.3.2

Testing of System Components

8.3.2.1 Cable Sheath Insulating Jacket The cable sheath insulating jacket is used to insulate the cable metal sheath from earth for sheath bonding and to improve protection of the metal sheath from corrosion. Testing requirements of the jacket are described in cable Standards IEC 60840, IEC 62067, and IEC 60229, as shown in Tables 8.4 and 8.5. The impulse voltage test level of these components depends on the impulse voltage of the main insulation of the power cables as well as the length of the bonding leads.

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Table 8.4 Metal shield/sheath insulating covering impulse withstand voltage versus BIL (IEC 60840, IEC 62067 and AEIC CS9-2015 Table 4.2-1)

Rated BIL for main insulation (kV) 250–325 550–750 1050 1175–1425 1550

Impulse test level (1.2  50 μs) Between parts Bonding cable Bonding cable length length 3 m 10 m 3 m (kV) (kV) 60 60 60 75 60 95 75 125 75 145

Each part to ground Bonding Bonding cable cable length length 3 m 10 m 3 m (kV) (kV) 30 30 30 37.5 30 47.5 37.5 62.5 37.5 72.5

Table 8.5 Impulse type test voltage values as specified by IEC 60229 for cable sheath insulating jacket Rated lightning impulse withstand voltage of main insulation voltage (kV peak) V < 325 325 < V 750 750 < V < 1175 1175 V < 1550 V  1550

Impulse test voltage of cable sheath insulating jacket (kV peak) 30 37.5 47.5 62.5 72.5

Routine electrical tests on non-metal sheath or jacket are a conditional test in accordance with IEC 60840 and IEC 62067 upon specifications in a contract or order. In most cases, only withstand voltage tests are performed. IEC 60229 provides details of the factory routine tests, product type tests, and after installation tests from the insulating material perspective. As part of the routine tests, a dc voltage test is conducted when the jacket is covered by a conductive layer. In this test, a dc voltage of 8 kV/mm of insulating jacket thickness is applied for 1 min, with a maximum of 25 kV. The type tests include abrasion test, corrosion spread for aluminum sheath, and impulse voltage test. The impulse type test voltage values specified by IEC 60229 are shown in Table 8.5. In addition to impulse voltage values, ac voltage withstand levels are also required by French Standard NF C 33-254 as shown in Table 8.6.

8.3.2.2 Sheath Interruption Insulators and Joint Casings The sheath interruption insulators are parts of the cable sectionalizing joints. In the metal sheath bonding systems, the insulators separate two adjacent sections of the cable sheath. During system disturbances, the insulators are subjected to ac and transient overvoltages. IEC 62067 and IEC 60840 provide the test requirements for equipment designed in accordance with these standards, the same as for cable sheath insulating jacket (see Tables 8.4 and 8.6).

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Table 8.6 Metal shield/sheath insulating covering withstand voltage (NF C 33-254) Nominal voltage (kV) Lightning impulse voltage for main insulation (kVc) Screen to ground impulse withstand level (kVc) Screen interruption impulse withstand level (kVc) Screen to ground AC withstand level (kV) Screen interruption AC withstand level (kV)

36/63 (72.5) 325

52/ 90 (100) 450

130/ 225 (245) 1050

230/ 400 (420) 1425

50

50

50

62.5

80

80

100

125

20

20

20

20

25

25

25

35

8.3.2.3 Bonding Leads The cable leads or connections between the cable sheath and link boxes should use proper insulation requirements as for the cable sheath insulation jacket. Generally, the bonding cable insulation test level is also related to the impulse test level of the power cable main insulation. It is noted, however, that commodity cables are usually applied for the bonding leads and are usually not manufactured to a specific system. The voltage peak value should be in accordance with IEC 60229 as for cable sheath insulating jacket (Table 8.2) as a minimum. The suggested BIL level for bonding leads can also be found in Electra 128 and IEEE 575. The impulse test procedure should follow IEC 60502-2 clause 18.1.7. In the case of the concentric neutral cables, the impulse value for the type test should apply to the test between internal and external conductor as well as between external conductor and earth. This is also in agreement with requirements for the accessory testing specified in the IEC 60840 and 62067, Annex G. In addition to the standard tests, the dc voltage withstand type test for the outer covering and sheath/screen sectionalizing insulation of 25 kVdc, as specified by IEC 60229, should also be applied. The leads should also be tested for short-circuit conditions. The cable leads are installed in free air or submerged. Their external surface may be covered with either graphite or extruded semi-conductive layer to facilitate field testing. If the semi-conductive layer is applied, proper earthing of the layer must be ensured. Bonding leads that are intended to be used as a link to earth connection can be tested as per IEC 60502-1. For leads without outer semi-conductive jacket covering, the spark test method as described in the IEC 62230 – Electric cables – Spark-test method, could be used in determining if the outer jacket of a coaxial cable withstands a specified voltage. A spark tester includes a voltage source capable of maintaining the test voltage and a means of grounding of the conductor and sheath. The external electrode (bead or link) should be capable of making a good contact with the external part of the cable. The center and outer conductors should be securely connected to the ground, making a low impedance path for the current. The jacket should pass through the external electrode at a rate calculated as per relevant standards.

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If the concentric bonding leads used in cross-bonding systems are equipped with swelling tapes or other means that restricts the moisture migration, the cable should be tested as per relevant cable standards to ensure that the water will not migrate to the inside of a joint casing or under other coverings. If the cables used for bonding purposes are regular single conductor cables, the ingress of water under insulation should be restricted. The limit of the bonding lead length of 10 m cannot always be met. In case that the terminations are installed on a tower, which is the case for siphon systems, the bonding leads can be in the range of 15 to 20 m. In this case, a larger conductor cable can be used to reduce the system impedance. Also in some countries, the maximum length of the bonding connections employing 1000-V cable is established as 5 m. In any installation, the bonding leads should be installed as close to each other as possible. A trefoil arrangement is preferable. During a ground fault of the electrical systems, zero sequence current returns to the source through any available path. The current returning by the earth path can cause the ground potential rise to be hazardous to the personnel and equipment. In this case, the ECC should be insulated. In case of single-point bonding (and sometimes cross-bonding), the earth continuity conductor installed parallel to the power cables is used to provide low impedance path for the fault current. Because of the above and to protect the ECC cable, the cable should be insulated to the 1000 V minimum level. Some utilities require the minimum thickness level of insulation to be 3.3 mm. In certain systems, it may be advisable to calculate induced voltage in the ECC and adjust the insulation requirements.

8.3.2.4 Sheath Voltage Limiters Sheath voltage limiters (SVLs) are critical components of the cable bonding system to protect the system insulation from transient overvoltages. Selection of SVLs is an important part of the entire bonding scheme and grounding coordination. It is noted that the sheath voltage limiters are not designed to carry excessive current that may appear during a short circuit event. Non-linear metal-oxide varistor type surge arresters are the most widely used type of SVLs. These arresters are tested in accordance with IEC 60099-4 and other applicable standards. The arresters are also generally factory tested for the purpose of the surge energy dissipation requirements. The SVLs are also tested as part of routine factory tests. The zinc oxide units can be tested by applying a dc test voltage to achieve reference current flow. The test is performed in forward and reversed directions and an average value is calculated for future reference. As the temperature is an important factor, the ambient test temperature is recorded. It is recommended that the voltage be corrected (decreased or increased) to a common temperature value. 8.3.2.5 Link Box or Enclosures Link boxes or enclosures are used to contain SVLs, link connections, earth cable terminals, sockets for bonding lead entry. Stainless steel, fiberglass, or cast iron is used for the link box housing. All designs of the link boxes must take potential

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corrosion into account. Requirements for water tightness and extent of sealing must be specified, considering interface transitions, such as, connecting cable lead entries, link box opening seals, and grounding terminals. Link boxes should withstand the mechanical forces and electrical currents expected during short circuit event, transient overvoltages during lightning, switching and fault events, and water ingress especially when installed in submerging environments. (a) Electrical tests Electrical tests include impulse voltage withstand tests, fault current withstand tests, and ac and dc voltage withstand tests. Impulse withstand voltage should not be less than that specified for the maximum system voltage given in Table 8.1. The fault current withstand test is recommended to prove that the enclosure will survive the flow of the short circuit current of specified magnitude and duration. In addition, dc withstand tests of 25 kVdc with 5 min duration should be performed between links and grounded metal parts of the enclosures. (b) Environmental tests From the installation point of view, the enclosures can be mounted above or below ground surface. The link boxes or enclosures shall be tested for water tightness, otherwise known as moisture ingress protection (IP). The ingress protection degree and testing requirements are included in IEC Standard 60529 and NEMA 250. The ratings are not directly equivalent between these two standards. In the case that the link boxes are installed in a hazardous, otherwise known as classified, location, the construction of the link boxes should adhere to the regulations required for those locations. In many cases, such devices are called “intrinsically safe” products. The regulations are different from country to country for the intrinsically safe or explosion proof devices. They can be found in the standards, such as: • Europe: EN60079 (IEC 60079), EN 61241 (IEC61241), Directive 79/196/EEC, and Directive 2006/95/EC. • United States: Factory Mutual – FM3610, NEC/CEC, and NEMA ICS6 • Canada: CSA C22.2 NO 157.92-CAN/CSA Some utilities require that the enclosure be arc-resistant. In this case, the enclosure should be tested by initiating an internal arc by passing a maximum rated short circuit current for a period of twice the expected circuit breaker arc clearance duration, i.e., 10 cycles. To pass the test, the enclosure should not be ruptured or burst open and no debris could be ejected.

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(c) Endurance tests The enclosures used in the bonding systems are intended to work for many years under exposure to the environmental conditions. Their water tightness depends mostly on the seal. Seals comprised of elastomeric material should be tested for decay of elasticity over years of compression. The endurance test can be conducted based on standards ASTM – D6147, ISO 3384, ISO 188, and ISO 132. (d) Explosion requirements The link boxes must be explosion proof. Explosion within the link boxes may occur due to ignition of combustible inner component parts, if any, or due to earth gas entered the link boxes. The explosion could be triggered by a failure of SVLs, or by flashover or sparking of high contact resistance at the interface of links with studs or any other connections. All component parts of link boxes should be made of non-flammable materials. SVLs should also be encased in non-flammable casings/envelopes. Some users specify that all types of link boxes should withstand an inner explosion pressure of 250 kPa. Generally, the test is not specifically included in any particular standard. The testing protocols have been developed and included in some technical specifications for related cable projects. It is noted that the static test does not replicate the possible event as the explosion inside the enclosure is dynamic. It is advisable that the enclosure test includes an internal arc resistance test. Such a test should prove that in case of an internal fault the enclosure remains intact. The test magnitude and duration should cover the expected short circuit current at operational frequency and circuit breaker clearing time.

8.3.2.6 Mounting Insulators (Standoff Insulators) and GIS Insulation Flange for Terminations Insulation coordination requires that the components insulating the current carrying parts from the ground be subjected to electrical, mechanical, and environmental tests. The electrical test values should take into consideration all other parts of the bonding system. The mechanical test values depend on the weight and installation position of the terminations. The GIS insulation flanges should be tested to at least the same values as the standoff insulators. Additional tests should be carried out to prove the seal and gas leakage. The standoff insulators used for the bonding systems should be tested to the following standards: • IEC 60168 – Tests on indoor and outdoor post insulators of ceramic material or glass for systems with nominal voltages greater than 1000 V • IEC 60273:1990 – Characteristic of indoor and outdoor post insulators for systems with nominal voltages greater than 1000 V

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Many utilities standardize on using 7.5-kV standoff insulators in supporting the cable terminations. In some cases, especially in single-point bonding systems, these insulators may not be sufficient to protect the bonding system from unexpected transient voltages. In any case, their testing values should be comparable to those specified for the bonding leads. This requirement applies to standoff insulators as well as to GIS insulating flanges. It is noted that the termination standoff insulators should not fail during the following occurrences: • Maximum expected travelling wave voltage • Voltage induced during short circuit current flow • Jacket voltage test The values in Table 8.1 should be used as minimum electrical requirements. Compression and seismic characteristics should be considered for mechanical requirements. Contamination performance should be considered for outdoor environment applications.

8.3.3

System/Commissioning Tests

To ensure performance of the bonding system insulation, several commissioning tests are applied. There are no commonly recognized sheath bonding system commissioning tests. In the recent years, there are attempts by some users to specify a set of after installation tests to prove that the system is designed and built to the requirements. There are a few tests that may assist in proving the system installation.

8.3.3.1 Induced Voltage and Bonding Test The test is described in Electra 47. It requires applying a low voltage to the main conductors star-connected at the remote end and regulating the current to a predefined value, i.e., 100 A. A portable three phase generator with voltage regulation is necessary. Measuring the voltage magnitude at the bonding points and comparing results with calculated values may assist in proving correctness of system designs and connections. However, the test results may be influenced by the induction coming from energized nearby lines or equipment. 8.3.3.2 Sheath Jacket Integrity Test This test is a commonly used dc test on the oversheath of the power cables. The test can also be a part of test before installation, installation check for each installed cable section or joint, system commissioning, and maintenance. If necessary, leakage current can be used as a benchmark for future tests comparison. It is noted that the leakage current depends also on factors external to the system, such as, temperature, air humidity and cleanliness of the connections. The test includes a dc voltage of 4 kV/mm of jacket thickness with a maximum of 10 kV dc for 1 min, with all metal layers connecting with

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the sheath connected together. This test requires a conductive layer outside the insulating jacket or using moist backfill as the conductive layer (See IEC 60229).

8.3.3.3 Contact Resistance Test Since the system contains a significant number of the connection points, their resistance could be detrimental to the bonding performance. The contact resistance test assures that the connections do not create a bottleneck for the passage of short circuit current. The approval value of such can be arbitrarily assigned or a laboratory test conducted. In practice, a value of 20 μΩ is used and accepted by some users. 8.3.3.4 Others Other tests such as, ECC continuity test, SVL integrity tests, and visual verification of connections are also carried out by some users.

8.4

Maintenance of Bonding Systems

This section discusses the issues related to maintenance of bonding systems. It is the intention of the following clauses to suggest good practice maintenance schedules and list areas where the user should pay special attention. This section is based on the responses to a questionnaire circulated among TSOs, cable manufacturers, consultants, and utilities.

8.4.1

Maintenance of Bonding Systems

Whereas other HV equipment is subjected to regular maintenance, it has been considered that extruded dielectric underground transmission cables are almost maintenance free. However, recent service experience showed that inexpedient operation may arise if the cable systems are not properly maintained. It is suggested that maintenance of bonding systems follow a regular schedule in order to ensure safe and optimal operation of the cable system under all operational modes (normal, emergency, or fault). Planning of maintenance should be an optimization between what is technically possible, the cost associated, and the benefits thereof. As for all other assets, two different methodologies can be applied to maintenance of bonding systems: • Corrective maintenance Corrective maintenance is done once the asset shows proof of errors in the operation, either due to total breakdown or partial malfunction. • Preventative maintenance Preventative maintenance is inspection of the asset and repair of operational equipment which may fail before next scheduled preventative maintenance.

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The two different methodologies can be combined into one maintenance program. Possible Maintenance Actions are discussed below.

8.4.2

Common Failure Modes

In order to create a maintenance program, it is necessary to understand issues associated with the bonding system. The following lists some commonly experienced issues with the bonding systems and bonding system components.

8.4.2.1 Jacket Damage The sheath insulating jacket may be damaged during handling and installation, overvoltage caused by lightning or switching surges (if the protection by the SVLs are not effective), objects with cable construction surroundings, or cable movement. In addition to the possibility of water ingress, the puncture may result in a malfunction of the bonding scheme, as the damaged areas may appear as a grounding point. For single-point bonded and cross-bonded systems, an extra ground point may lead to unexpected circulating currents which may create localized heating and damage the power cables. It is therefore important to prevent jacket damages and detect jacket damages on a regular basis and perform corrective maintenance when a damage is found. 8.4.2.2 SVL Damage SVLs are an important part of the bonding system to prevent the damage of the sheath insulating jacket and other insulating components in the bonding system from damages caused by transient overvoltages. In general, there are two possible failure modes for SVLs. Firstly, the SVL may fail so that it does not conduct during overvoltages, i.e., it appears as an open circuit. Secondly, the SVL may fail so that it appears as a short circuit, and thus conduct current at normal operating screen voltage; this failure mode is considered more common than the first one. The first failure mode results in possible high screen voltages during transients (e.g., lightning or switching) and leads to possible jacket damage. The second failure mode results in circulating sheath currents that may create over heating of the power cable. 8.4.2.3 Loose Connections (Bonding Leads, SVLs) A common failure mode with the bonding systems is loose connections to, or disconnected, SVLs. Due to erroneous/insufficient installation or movements, etc., the connections may not be sufficiently tight which may lead to insufficient overvoltage protection of the bonding system insulation. 8.4.2.4 Damaged Bonding Leads Damaged bonding leads share the same failure modes described under “Jacket damage”. Furthermore broken bonding lead conductors may result in open circuits where there should be short circuits, e.g., between joints and link boxes. This may

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lead to imbalance and/or hazardously high voltage during normal operation, cable faults, and transient overvoltages.

8.4.2.5 Link Box Failure The link box may fail due to exposure to the harsh environment, including moisture, heat, UV, manufacturing defect, or mechanical impact. Common failures that can be inspected externally include corrosion, physical damages, and moisture ingress. Opening the link box may assist in inspecting components within the link box for signs of moisture ingress, corrosion, loose connections, disconnections, incorrect connection, ineffective sealing gaskets, and failed SVLs. However, it should be noted that opening link boxes may increase the risk for future water ingress due to aging of the water seal. All of these different failure modes may result in losing a grounding point, losing jacket protection by the SVLs, or getting a new unintended grounding point leading to circulating currents. 8.4.2.6 Stand-Off Insulator (Termination Support) Failure The standoff insulators as termination support may fail due to mechanical stress, material aging, or electrical stress. The insulator should be free from scratches and not show any arcing traces. 8.4.2.7 Other Failure Modes An additional list of performance issues and failures found during maintenance inspections and system operations is included as below. • • • • • • • • •

Cracking of terminal support post insulators Insufficient clearance within link boxes resulting in internal flashovers Poor mounting insulator at terminations Poor insulators within link boxes Punched link holes at link boxes that reduce contact surface area Poor SVL connections where small SVL studs pass through slotted holes Insufficient rigidity in lids and poor gasket retention Pits often contain water and water sealing at penetrations is an issue Generally, the local earth mat should have reasonable earthing resistance of, say, 10 Ohms • In addition to the inner earthing connection, there should be an independent external connection to the local earth mat of the LB metal casing/body. The external earthing connection is for personnel safety while the inner connection is the integrated part of cable bonding system.

8.4.3

Corrective Maintenance of Bonding Systems

As corrective maintenance by definition is the repair/change of defected equipment, it will not be further discussed here. However, it should be acknowledged that the main part of the costs for corrective maintenance can be related to the time it takes to find the

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defect and possible associated outage time, rather than the costs of the replacement components themselves. A major point in corrective maintenance of the bonding system may therefore be to find a proper way of rapidly location defective equipment. Such failure location strategies are outside the scope of the present report. It should be noted that a failure of a HV cable may lead to high overvoltages which may harm the SVLs and other components of the bonding systems, especially when the SVLs are not chosen correctly or when the SVLs have experienced excessive aging. As part of the inspection after a fault, it is therefore advisable to perform testing of the SVLs and other components at least nearest to the fault location for integrity. In addition to a visual inspection of the SVLs, electrical tests, as presented in Sect. 8.3 of this document, should be performed. Based on the above, it is determined advisable to perform preventative maintenance, wherever possible, to avoid costs of repair and outage time. It should be recognized that while preventative maintenance time is limited to performing inspection of the system, corrective maintenance is much more time consuming as it includes fault detection, mobilization, visual inspection, fault location, repair, testing, etc. and it is thus much more time economic to perform preventative maintenance than corrective.

8.4.4

Preventative Maintenance of Bonding Systems

As described, it may be more cost efficient to prevent failures with regular maintenance, than to perform corrective maintenance after a failure has occurred. Preventative maintenance can be divided into two sub-categories, online and offline. Online maintenance is the work that can be performed while the cable system is operating, whereas the cable system has to be taken out of service (and grounded) during offline maintenance work. The following presents the identified possibilities for maintenance of bonding systems for HV transmission cables.

8.4.4.1 Online Maintenance Maintenance inspections performed when the cable systems are still in service are described in this section. Test criteria for these inspections must consider electromagnetic interference with applied inspection equipment and induced voltages and currents from adjacent circuits. The inspection or monitoring must also consider the number of measuring or monitoring points across the entire circuit length, especially with multiple minor cross-bonding sections. Device used for partial discharge measurements for cable and accessory insulation diagnostics, such as, high frequency current transformers, can also be used as an inspection tool for the bonding systems. 8.4.4.1.1 Patrolling In order to prevent damages from construction and excavation work near the cable route, it is recommended to perform regular patrolling along the cable route. A visual inspection of the bonding system is preferable on externally exposed components as

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this may be the easiest way to find aged equipment or equipment which may soon fail. However, as bonding systems are often buried, measurements from the vaults or open sections must be considered. 8.4.4.1.2 Sheath Current Measuring current magnitudes and phase angles in the sheath in operation can assist in determining if the current meets the design specifications. If a cross-bonded or single-point bonded system shows large sheath currents, it may indicate that an abnormal condition may have happened to the bonding system, such as, a sheath insulation failure. If a multi-point bonded system shows no sheath currents, it may also show the bonding system is not connected properly. For cross-bonded systems, online measurements may require measurement devices installed at each minor section, whereas for multi-point bonded or singlepoint bonded systems, the measurement devices may be required only at each grounding point. The device may be connected directly to a central data acquisition center or be manually read by dispatching maintenance personnel on site. 8.4.4.1.3 SVL Integrity Some SVL manufacturers embed a sensor (optical fiber) within the SVLs. The sensor can be used to detect the condition of the SVLs. The sensor may also be connected directly to a central data acquisition center or be manually read by dispatching maintenance personnel on site. In addition to the possibility of integrating fiber sensors in the SVLs, it is possible to measure the current in the SVLs. If the current is larger than the anticipated value, the operator may know that something is wrong with the bonding system (including the SVL). 8.4.4.1.4 Distributed Temperature Sensing (DTS) With a DTS system, it is possible to measure the temperature along the cable system. Besides an overall evaluation of the performance of the cable system, the DTS measurements may provide an indication of the performance/status of the bonding system. For cross-bonded systems, a high temperature along one major section may indicate large currents running in the sheath, meaning that the bonding system is faulted. Similarly, if higher temperatures than expected arise in a single-point bonded system, it may indicate that currents are flowing in the sheath, and that the bonding system therefore is faulted. Moreover, if lower temperatures than expected are experienced in multi-point bonded systems, it may be an indication of a low sheath current, meaning that the bonding system could be faulted. It should be noted that a faulted cross-bonded or single point bonded system, as described above, is not necessarily problematic as the grounded bonding system ensures a return path for fault currents. The “only” problem is that a faulted bonding system may reduce ampacity of the cable system. A faulted solid bonded system, as described above, is problematic as it does not ensure a return path for fault currents. Immediate action should therefore be taken. It is noted that the metal tubes containing the fiber cables must be connected to earth potential.

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8.4.4.1.5 Visual or Thermal Images Visual or thermal images can be used to show general or mechanical conditions of exposed components, such as, standoff insulators, SVLs, and bonding leads, of the bonding system.

8.4.4.2 Offline Maintenance 8.4.4.2.1 Visual Inspection A maintenance action preferred by many TSOs and utilities is the visual inspection of the bonding system. A visual inspection of the following components may show the condition of the bonding system. • Link box – Outside: damages, corrosion. – Inside: moisture, corrosion, connections. • Bonding lead: jacket conditions, connections • SVL: conditions, free from scratches and arcing traces. • Standoff insulator (termination support): Insulator condition, free from scratches and arcing traces, etc. 8.4.4.2.2 Measurement of Resistance and Contact Resistance In addition to the visual inspection, it may be preferable to perform measurements of contact resistances inside the link box. The measurement may disclose loose connections. It may also be considered to conduct a measurement of the grounding resistance on a regular basis to ensure a fully functional bonding system. 8.4.4.2.3 SVL Integrity The electrical characteristics of SVLs can be checked. The test includes a voltage/ current profile of the SVLs. A test as presented in Sect. 8.3 of this document is possible to perform on site, such that the SVL can be put directly back into service, whereas a full voltage/current profile may be conducted in a laboratory. In the latter case, the SVLs may be exchanged with the ones that have been fully tested. The SVLs tested at testing laboratories may be reused. It is possible to perform a voltage test for the integrity of the SVLs. Special testers may be used to measure dc leakage current or third harmonic component of the leakage current to assess the conditions of SVLs. Dissipation factor tests may also be used in combination of other diagnostic methods. Environmental conditions (temperature, humidity) under which the tests are performed should be recorded for the evaluation. Sometimes, the SVLs may not be faulty but the test results may show a trending of accelerated aging which can also call for replacement of the SVLs. 8.4.4.2.4 Sheath Voltage Test By performing a screen voltage test, a dc voltage is applied between the metal screen and ground. In this way the operator is able to see if the screen is unintentionally grounded at any point, e.g., a defected bonding system. IEC 60229 includes a sheath integrity test after installation. The after installation test described in IEC 60229

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includes a dc voltage of 4 kV/mm with a maximum of 10 kV for 1 min with all metal layers connecting with the sheath connected together. For maintenance tests, the test voltage is typically reduced by 50%. This test requires a conductive layer outside the insulating jacket or using moist backfill as the conductive layer.

8.4.5

Maintenance Schedule of Bonding Systems

A survey was carried out among the working group members representing different countries on maintenance practices. Table 8.7 shows the list of the questionnaire. Details of the survey are included in Appendix C not reproduced in this chapter of the book. Table 8.7 Questionnaire for maintenance practice survey Maintenance of cable bonding systems Your company: This spreadsheet is intended for collecting data from different cable suppliers and operators among working member countries. The questionnaire is related only to the maintenance of cable bonding systems. If some of the fields in the spreadsheet seems superfluous, please leave it blank or copy the answer from one cell into another. The answers will be part of a CIGRE technical brochure delivered at a later stage by Working Group B1.50. Answers will be anonymized if requested. Solid Single Cross Other point schemes? Bonding methods Please give a brief description of how the different bonding methods are made Scheduled maintenance on the bonding systems What kind of scheduled maintenance is performed What tasks are performed and with what interval? What equipment is being maintained? (e.g., link boxes, earthing boxes, bonding leads, SVLs, mounting insulators, grounding points, earth continuity conductors, etc.) What tests are performed and with what interval? Are there different maintenance requirements seen from different manufacturers? Unscheduled maintenance (after cable fault) What kind of maintenance is performed after a cable fault? What tasks are performed? What equipment is being maintained? (e.g., link boxes, earthing boxes, bonding leads, SVLs, mounting insulators, grounding points, earth continuity conductors, etc.) What tests are performed? Are there different maintenance requirements seen from different manufacturers? Other comments:

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Based on the survey and discussions above, an offline maintenance schedule for cable bonding systems is outlined here for reference only. Users should follow the maintenance schedule as defined by their own practices, and with due consideration to the actual conditions experienced by their cable circuits.

8.4.5.1 Safety Considerations During Maintenance Before going into the technical aspects of a maintenance schedule, it is important to ensure that all maintenance must be performed while taking the highest possible safety precautions. A maintenance schedule should therefore be created with Health, Safety and Environment (HSE) in mind. This means that all maintenance tasks must be performed while ensuring good HSE practices. The following list is in no way exhaustive and all maintenance tasks must be thought over with HSE in mind. However, hereunder is a list of some of the most common HSE issues that must be considered while maintaining a bonding system: • A strong grounding point must be established at all places of work with maximum grounding resistance of 10 Ω. • In order to prevent induced voltages build-up, all metal parts must be grounded at the place of work. • Workers should never work alone. • Escape routes must be available and known to workers before maintenance work begins. • Link and grounding boxes shall not be opened when the cable system is in operation. Additional details on safety considerations are addressed by Working Group B1.44 – Guidelines for Safe Work on Cable Systems under Induced Voltages or Currents.

8.4.5.2 Parameters to Consider for Maintenance Planning There are many different parameters to include in the analysis of optimizing the maintenance schedule for bonding systems of HV transmission cable systems. The following list includes (in no particular order) the parameters which, as a minimum, should be considered when creating a maintenance schedule. • Joint/link box accessibility – Directly buried cable systems are generally a low cost installation option, but access to such systems for maintenance is mostly difficult as the link box and many components of the systems may have to be excavated to access. – Installation in tunnels, ductbanks, and manholes is considered high-cost installation methods, but the access to link boxes, joints, and other components is relatively easier. • Criticality/importance of the line – Higher maintenance costs and more frequent maintenance may be justified for more critical/important lines.

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– Age of line Older cables may require more frequent maintenance than newer lines. – Experience with components Components with more performance issues may be maintained more frequently. All of these parameters add to the determination of maintenance frequency. Maintenance work itself may require a relatively low effort. For example, a visual inspection of the link box is usually straight forward without the need for designated equipment. However, the logistics for creating an overall maintenance schedule of all cable lines may set limits to how often the individual line can be subjected to maintenance. Furthermore, the accessibility of the bonding components could pose an obstacle to performing frequent maintenance as excavating directly buried cable systems is inconvenient, costly, time consuming, and it may need permits from the land owners. This factor is therefore especially important when deciding on the maintenance strategy for cable bonding systems.

8.4.5.3 Recommendations for Maintenance Schedule for Cable Bonding Systems For easily accessible equipment (including equipment on substations), it is recommended to perform the following maintenance work on a yearly basis: • Visual inspection and thermal imaging inspection: – Link boxes and their covers – SVLs – Link boxes: bars and connections – Bonding and grounding leads – Terminal base connectors Furthermore, for easily accessible equipment (including equipment on substations), it is recommended to perform the following maintenance work on a 5-year basis: • Tests: – Test of SVL voltage/current characteristics – Jacket test – 5 kV for 1 min (voltage magnitude depending on SVL rating) – Connection resistance in link box For equipment which is difficult to access, the following maintenance work is recommended on a 5-year basis: • Visual inspection of: – Link boxes and their covers – SVLs

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– Link boxes: bars and connections – Bonding and grounding leads – Terminal base connectors • Tests: – Test of SVL voltage/current characteristics – Jacket test – 5 kV for 1 min (voltage magnitude depending on SVL rating) – Connection resistances in link box Any equipment found faulted during any of the above tests should be repaired or replaced. In addition to the above offline measurements, it should be considered to implement one or more of the online solutions mentioned in Sect. 8.4.4.1. IEEE Standard 400 discusses testing for jacket fault, jacket fault location and pin-pointing, and after repair.

8.5

Conclusions

The CIGRE Working Group B1.50 performed and documented the study committee B1 approved working group Terms of Reference for design, testing and maintenance of sheath bonding systems of ac transmission cables. All achieved deliverables are documented within this technical brochure. The working group deliverables achieved are listed as follows: 1. A general overview and detailed definition for insulated cable system sheath bonding systems. 2. The functionality, detailed description, and listing of available standards for insulated cable system sheath bonding systems and for other cable system components that form part of the sheath bonding systems. 3. A literature review of available published international standards, guidelines, CIGRE technical brochures, and papers to summarize available information on sheath bonding systems. This includes a quick reference table for key design, testing and maintenance aspects required for sheath bonding systems. 4. A survey review to obtain service experience on sheath bonding system design, testing and maintenance. That includes a summary of responses from member countries for all key design, testing and maintenance aspects required for sheath bonding systems. 5. A detailed Section on the design and protection of sheath bonding systems, that describes: the standard type of known sheath bonding system designs; calculation formulas, calculation formula references and examples for sheath induced voltages and circulating currents on sheath bonding systems; sheath voltage limiter selection and application guidelines; sheath bonding system overvoltage calculation models and software references for power frequency and transient network conditions; and insulation co-ordination study requirements for sheath bonding systems.

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6. A detailed Section on the testing requirements of sheath bonding systems. That includes both type testing and commissioning testing tables and references for known testing standards or CIGRE technical brochures. A critical finding by the WG B1.50 is that an insulation co-ordination study shall be performed for each specific project performed to establish the sheath bonding system voltage withstand ratings required for both overvoltage and transient conditions. 7. A detailed Section on sheath bonding system maintenance requirements, with a further consideration for online and offline maintenance activities and scheduling thereof. This chapter is to inform and guide insulated cable system design engineers, operating units, and maintenance engineers on the international best practices to be considered for the design, testing, and maintenance of ac transmission cable sheath bonding systems.

Appendix A: Abreviations, Definitions, and Symbols A1: Abbreviations BIL CIM CP ECC EPR FD LB Metal Sheath MOV OHL Oversheath SVL TSO

Basic Impulse Level Complex Impedance Matrix Constant Parameter Earth Continuity Conductor Earth Potential Rise Frequency Dependent Link Box Also referred as Metal screens or Shield throughout this document. Metal oxide varistor Overhead Line Also referred as Outer Sheath or Jacket throughout this document. Sheath Voltage Limiter Transmission System Operator

A2: Specific Terms Sheath insulation electrically isolates the cable metal sheath from earth and protects the metal sheath from corrosion. Sheath voltage limiters are devices connected to the sheaths of bonded cables, with the purpose of protecting sheath insulation, sectionalizing interruption at joints and other accessories, insulation flange (at GIS) during system transients.

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System transients may be lightning, switching, or fast transient associated with the initial part of a short circuit event. Link boxes provide housing for bonding and/or earthing connections to contain SVLs, link connections, earth cable terminals, sockets for bonding lead entry generally made of removable links. Bonding leads are insulated conductors, single core or co-axial, for bonding connections. Multi-point bonding uses bonding leads at both ends and at intermediate points of a cable circuit. It is a simple and a low cost option with minimum maintenance requirements. It is commonly used for low and medium voltage systems. Single-point bonding: Only one end of the cable metal sheath is directly grounded to the underground earth link. Mid-point bonding consists of two single point bonding systems. Both ends of cable metal sheath are open and the mid-point is grounded through the parallel earth continuity conductor. Cross-bonding interrupts sheath continuity at regular minor section length by crossbonding joints. Connections are made between the sheaths so that each sheath circuit surrounds the three phase conductors successively. Continuous cross-bonding installs sheath voltage limiters at the cross-bonding points to protect screen interruptions from electromagnetic transients. The complete compensation of induced voltages requires that the minor sections are of the same length and that the spacing between cables is constant. Sectionalized cross-bonding consists of multiple major sections along a cable circuit. A major section consists of three minor sections. Cross-bonding and transposition transposed cables at each joint chamber to reduce the induced voltages and sheath circulating currents by cable phase conductors. The induced voltage is then near zero. When cables are laid in flat formation, the compensation of the induced voltages can be achieved if cables are transposed at cross-bonding points. It is worth mentioning that, even for a trefoil laying, transposition of the cables is recommended to limit the induced voltages by nearby conductors. Direct sectionalized cross-bonding consists of multiple major sections along a cable circuit. A major section consists of three minor sections. The highest transient overvoltage appears in the sections closest to the terminations. At the other cross-bonding points of the circuit, cross-bonding of the screens is then performed “directly” by jointing single-core bonding leads, without SVLs. Siphon lines connect overhead and underground cables. Continuous operating voltage, Uc, designated permissible rms value of powerfrequency voltage that may be applied continuously between the sheath voltage limiter terminals – See IEC 60099.4. Rated voltage, Ur, maximum permissible rms value of power-frequency voltage between sheath voltage limiter terminals at which it is designed to operate correctly under temporary overvoltage conditions. Notes: The rated voltage is used as a reference parameter for the specification of operating characteristics. The rated voltage as defined is the 10 s power-frequency voltage used in the

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operating duty test after high-current or long-duration impulses. – See IEC 60099.4. Residual voltage, Ures, peak value of voltage that appears between the sheath voltage limiter terminals during the passage of discharge current. – See IEC 60099.4.

A3: Symbols Symbol E or Ek j ω μ s rs Ik L α d1k ρsoil γ D Rk Rs Rc rs dij Zs Zm Zc Zij Zif Zic Zcf Ef If Ic sif sic scf EEPR

Definition Induced voltage in the screen k (k ¼ 1..3) Complex parameter Angular frequency Permeability Spacing between conductors Metal sheath mean radius Phase currents (k ¼ 1..3) Length of the cable Complex 2π 3 rotation Distance between cable k and parallel conductor (k ¼ 1..3) Soil electric resistivity Euler’s constant Short-circuit fictitious return path distance Earthing resistance at remote end k (k ¼ 1..2) Metal sheath resistance ECC resistance Metal sheath mean radius Distance between phases i and j (i ¼ 1..3) ( j ¼ 1..3) Metal sheath self-impedance Mutual impedance between core conductor and metal sheath ECC self-impedance Mutual impedance between phases i and j (i ¼ 1..3) ( j ¼ 1..3) Mutual impedance between phase i and faulted phase (i ¼ ..3) Mutual impedance between phase i and ECC (i ¼ 1..3) Mutual impedance between faulted phase and ECC Sheath voltage to local earth during fault conditions Earth fault current in conductor Earth fault return current in ECC Spacing between metal sheath i and faulted phase (i ¼ 1..3) Spacing between metal sheath i and ECC (i ¼ 1..3) Spacing between faulted phase and ECC Earth Potential Rise

First occurrence 8.2.1.9 (schematic)

8.2.1.4.3 (Fig. 8.19) 8.2.1.9

(continued)

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Sheath Bonding Equipment for AC Transmission Cable Systems

Symbol γc R η A B X Vsingle Vthree Iccsingle Iccthree Z Y L0 μ Zsw Zmsw

Definition ECC radius Equivalent earth resistance over length Metal sheath current to core conductor current ratio (for solid bonding) Impedances and boundary conditions matrix Known voltages and currents matrix Unknown voltages matrix Screen potential rise for single-phase short-circuit Screen potential rise for Three-phase short-circuit Single-phase short-circuit current Three-phase short-circuit current Impedance matrix Admittance matrix Single-phase or coaxial bonding leads inductance Coupling factor Skywire self-impedance Mutual impedance between faulted phase and skywire

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8.2.3.2

8.2.3.3 8.2.3.4

Parameters from Sect. 8.2.3.1 are not included.

Appendix B Review of service experience-Survey details (Not reproduced in this chapter of the book)

Appendix C Review of service experience-Survey details (2) (Not reproduced in this chapter of the book)

Appendix D: Bibliography/References AEIC: CS9-15: Specification for Extruded Insulation Power Cables and Their Accessories Rated Above 46 kV Through 345 kV. AEIC (2015) Ametani, A.: A general formulation of impedance and admittance of cables. IEEE Transactions on Power Apparatus. 99(3), 902–910 (1980) Chang, M., Shao, X., Ros, H.: B1-1019: In land long distance HVAC cables, innovative examples at 225kV, application to 500kV. In: AORC Technical Meeting 2014 (2014) CIGRE WG 21.07: The design of specially bonded cable systems. Electra. 28, 55–81 (1973) CIGRE WG 21.07: The design of specially bonded cable systems. Electra. 47, 61–86 (1976) CIGRE WG 21.07: Guide to the protection of bonded cable systems against sheath overvoltages. Electra. 128, 47–82 (1990) CIGRE WG B1.18: TB283: Special Bonding of High Voltage Power Cables. CIGRE, Paris (2006)

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CIGRE WG B1.26: TB347: Earth Potential Rises in Specially Bonded Screen Systems. CIGRE, Paris (2008) CIGRE WG B1.30: TB531: Cable Systems Electrical Characteristics. CIGRE, Paris (2013) Du Plessis, T., Jagau, H., Visagie, D.: Evaluating step and touch potential risks on earthing systems of high voltage cable systems. In: 8th CIGRE Southern Africa Regional Conference (n.d.) Electricity Networks Association: Insulated Sheath Power Cable Systems. ENA (2014) EMTP: EMTP Theory Book. EMTP (1995) Ghassemi, F.: Effect of trapped charges on cable SVL failure. Electric Power Systems Research. 115, 18–25 (2014) Gudmundsdottir, U., Gustavsen, B., Bak, C., Wiechowski, W.: Field test and simulation of a 400kV cross bonded cable systems. IEEE Transactions on Power Delivery. 26(3), 1403–1410 (2011) Gustavsen, B., Sletbak, J., Henriksen, T.: Simulation of transient sheath overvoltages in the presence of proximity effects. IEEE Transactions on Power Delivery. 10(2), 1066–1075 (1995) IEEE PES: IEEE 575: Guide for Bonding Shields and Sheaths of Single Conductor Power Cables Rated 5kV Through 500kV. Piscataway, IEEE (2014) IEEE Standard 1300-2011: Guide for Cable Connections for Gas-Insulated Substations. IEEE (2012) International Electrotechnical Commission: IEC 60287-1-2: Electric Cables – Calculation of the Current Rating – Part 1: Current Rating Equations (100% Load Factor) and Calculations of Losses – Section 2: Sheath Eddy Current Loss Factors for Two Circuits in Flat Formation. IEC (1993) International Electrotechnical Commission: IEC 60071-1- Insulation Co-ordination – Part 1: Definitions, Principles and Rules. IEC (2006) IEC 60071.4 – Computational Guide to Insulation Co-ordination and Modelling of Electrical Networks, IEC (2004) International Electrotechnical Commission: IEC 62271-209 High-Voltage Switchgear And Controlgear – Part 209: Cable Connections for Gas-Insulated Metal-Enclosed Switchgear for Rated Voltages Above 52 kV – Fluid-Filled and Extruded Insulation Cables – Fluid-Filled and Dry-Type Cable-Terminations. IEC (2007) International Electrotechnical Commission: IEC 60840: Power Cables with Extruded Insulation and Their Accessories for Rated Voltages Above 150 kV (Um¼170 kV) Up to 500 kV (Um¼550 kV) – Test Methods and Requirements. IEC (2011) International Electrotechnical Commission: IEC 62067: Power Cables with Extruded Insulation and Their Accessories for Rated Voltages Above 30 kV (Um¼36 kV) Up to 150 kV (Um¼170 kV) – Test Methods and Requirements. IEC (2011) International Electrotechnical Commission: IEC 60099-4, Part 4: Metal-Oxide Surge Arresters Without Gaps for ac Systems. IEC (2014) International Electrotechnical Commission: IEC 60287-1-1 – Electric Cables – Calculation of the Current Rating – Part 1-1: Current Rating Equations (100% Load Factor) and Calculation of Losses – General. IEC (2014) International Electrotechnical Commission: IEC 62895 – High Voltage Direct Current (HVDC) Power Cables with Extruded Insulation and Their Accessories for Rated Voltages Up to 320 kV for Land Applications – Test Methods and Requirements. IEC (2017) Kaloudas, C., Papadopoulos, T., Gouramanis, K., Stasinos, K., Papagiannis, G.: Methodology for the selection of long medium-voltage power cable configurations. IET Generation, Transmission and Distribution. 7(5), 526–536 (2013) Khamlichi, A., Denche, G., Garnacho, F., Donoso, G., Valero, A.: B1-108: Location of sheath voltage limiters (SVLs) used for accessory protection to assure the insulation coordination of cable outer sheath, sectionalising joints and terminations of high voltage cable systems. In: CIGRE Session, Paris (2016) Khamlichi, A., Donoso, G., Garnacho, F., Denche, G., Valero, A., Álvarez, F.: Improved cable connection to mitigate transient enclosure voltages in 220-kV gas-insulated substations. IEEE Transactions on Industry Applications. 52(1) (2016) Khamlichi, A., Donoso, G., Garnacho, F., Denche, G., Valero, A.: B3-308: Removing risk of eventual discharges between GIS grounding parts and cable sheath connected to the substation earth through a separate grounding lead. In: CIGRE Session, Paris (2016)

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Lesur, F., Mirebeau, P., Mammeri, M., Santana, J.: Innovative insertion of very long AC cable links into the transmission network. In: CIGRE Session, Paris (2014) Mighe, P., de Leon, F.: Parametric study of losses in cross-bonded cables: Conductors transposed versus conductors non-transposed. IEEE Transactions on Power Delivery. 28(4), 2273–2281 (2013) National Grid plc: TS 3.05.04: Sheath Bonding and Earthing for Insulated Sheath Power Cable Systems. National Grid (n.d.) National Grid plc: TS 3.05.03: Sheath Voltage Limiters. National Grid (n.d.) Nichols, P.: Minimum voltage rating of sheath voltage limiters in underground cable systems: The influence of corrugated cable sheaths. In: 47th International Universities Power Engineering Conference, London (2012) Nichols, P., Yarnold, J.: A sensitivity analysis of cable parameters and their influence on design choices for minimum sheath voltage limiter specification in underground cable systems. In: Australasian Universities Power Engineering Conference, Adelaide (2009) Parmigiani, B., Quaggia, D., Elli, E., Franchina, S.: Zinc-oxide sheath voltage limiter for HV and EHV power cable: Field experience and laboratory tests. IEEE Transactions on Power Delivery. 1(1), 164–170 (1986) Pollaczek, F.: Sur le champ produit par un conducteur simple infiniment long parcouru par un courant alternatif. Revue Gén, Elec. 29, 851–867 (1931) Schelkunoff, S.: The electromagnetic theory of coaxial transmission lines and cylindrical shields. Bell System Technical Journal. (1934) Schutte, P., van der Merwe, W., van Coller, J.: Induced voltage behaviour analysis of an un-grounded outer layer semi-conductive coating of a 400 kV power cable system. In: International Symosium on High Voltage Engineering, Buenos Aires (2017) Sobral, A., Moura, A., Carvalho, M.: Technical implementation of cross bonding on underground high voltage lines projects. In: CIRED 2011, Frankfurt (2011) Wedepohl, L., Wilcox, D.: Transient analysis of underground power transmission systems. Proceedings of the IEE. 120(2), 253–260 (1973)

Tiebin (Tom) Zhao is a Senior Program Manager, Underground Transmission, of the Power Delivery and Utilization Sector of EPRI. His current research focuses on both extruded and laminar dielectric underground transmission cable systems in the area of condition assessment and field inspection, diagnostic procedures and tools, design calculations and software tools, and accessory performance analysis. Before joining EPRI, Tom worked for FirstEnergy where he developed and supported new technologies, initiatives, and processes within transmission operations. Tom also worked for Hubbell Power Systems as a Principal Engineer for design, engineering, and manufacturing of underground cable accessories and overhead line arresters. Tom received a Ph. D. in Power Systems and High Voltage Engineering from The Ohio State University, and a Master of Science and a Bachelor of Science degree, both in Electrical Engineering, from Tsinghua University. Tom has published numerous technical papers and reports and holds several patents, in the areas of underground transmission cable system assessment and monitoring, cable and accessory design, overhead insulator design and applications, and electrical and magnetic field calculations and measurements. Tom is the Principal Investigator of EPRI Underground Transmission Systems Reference Book – 2021 Edition. Tom is the US Regular Additional Representative of CIGRE B1 (High Voltage Cables), a member of AEIC Cable Engineering Committee, a member of IEEE Insulated Conductors Committee, and a Senior Member of IEEE Power and Energy Society.

9

Maintenance and Remaining Life Bart Mampaey

Contents 9.1

9.2

9.3

9.4

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.2 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.3 Terms of Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.3.1 To Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.3.2 To Analyze . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.3.3 To Propose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.4 How to Read the Chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Existing Maintenance Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2 Major Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2.1 Land Cable Systems AC and DC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2.2 Submarine Cable Systems AC and DC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2.3 Fluid Filled Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2.4 Monitoring and Diagnostics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.2.5 Future Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maintenance Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.2 Maintenance Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.3 Previous CIGRE Questionnaire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.4 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maintenance on Land-Based Cable Systems (AC and DC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.1 Common Maintenance on Land-Based Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.1.1 Maintenance Activities to Prevent Third-Party Damages . . . . . . . . . . . . 9.4.1.2 Maintenance Activities on Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.1.3 Maintenance Activities on Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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9.6 9.7

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9.4.2 Maintenance Activities on Specially Bonded Systems . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.3 Additional Maintenance for HVDC Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.3.1 Additional Maintenance Activities on Cables . . . . . . . . . . . . . . . . . . . . . . . . 9.4.3.2 Additional Maintenance Activities on Accessories . . . . . . . . . . . . . . . . . . . 9.4.3.3 Fault Finding on Long HVDC Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.4 Corrective Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.5 Tunnels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.5.1 Cable Design and Impact on Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.5.2 Tunnel Design and Impact on Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.5.3 Maintenance Activities and Procedures in Tunnels . . . . . . . . . . . . . . . . . . Maintenance on Submarine Cable Systems (AC and DC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.1 Preventive Maintenance on Submarine Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.1.1 Maintenance Activities to Prevent Third-Party Damages . . . . . . . . . . . . 9.5.1.2 Maintenance Activities to Control Cable Protection and Health . . . . . 9.5.1.3 Maintenance Activities on Submarine Mechanical Protections . . . . . . 9.5.2 Corrective Maintenance on Submarine Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.2.1 Immediate Actions After Fault Occurrence . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.2.2 Preparation of Repair Works . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.2.3 Mobilization of Resources for Repair Works . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.2.4 Repair Works . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid Filled Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Monitoring and Diagnostics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.1.1 Effective Maintenance Actions to Ensure Availability of a Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.1.2 Effective Measurements to Determine Condition of a Cable System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.2 Overview of Different Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3 Description of the Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.1 AC or DC Voltage Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.2 PD Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.3 DC Insulation Resistance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.4 Dissipation Factor Measurement (Tan Delta) and Dielectric Spectroscopy (DS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.5 DC Voltage Test on Oversheath . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.6 Bonding Performance Test and Monitoring of Screen Voltage and Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.7 Sheath Voltage Limiters (SVLs) Test* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.8 Earthing Resistance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.9 Loop and Contact Resistance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.10 DC Conductor Resistance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.11 Capacitance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.12 Sequence Impedance Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.13 Inspection of Manometers and Plumbing . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.14 Oil Leak Detection and Localization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.15 Oil Analysis: Dissipation Factor Measurement . . . . . . . . . . . . . . . . . . . . . 9.7.3.16 Infrared Temperature Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.17 Localized Temperature Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.18 Distributed Temperature Sensing/Measurement (DTS) . . . . . . . . . . . . . 9.7.3.19 Time Domain Reflectometry (TDR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.20 Frequency Domain Reflectometry (FDR) . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.21 Cathodic Protection Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.22 Oil/Gas Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

599 601 601 602 602 603 604 604 604 605 605 605 605 610 614 615 616 616 617 618 620 620 620 621 622 624 624 624 629 631 631 632 633 634 635 636 637 637 637 637 638 639 640 640 640 642 642 643 643

9

Maintenance and Remaining Life

9.8

9.9

9.10

9.7.3.23 Distributed Acoustic Sensing (DAS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.24 Cable Bathymetric Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.25 Impregnation Coefficient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.3.26 Insulation Sample Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spare Parts Management, Emergency Preparedness, and Training . . . . . . . . . . . . . . . . . . . . . 9.8.1 Spare Parts Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1.1 Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1.2 Identification of the Critical Parts to Be Kept Available . . . . . . . . . . . . . 9.8.1.3 Provision of Spare Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1.4 Spare Parts Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1.5 Inter-compatibility of Spares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1.6 Spare Parts Storage and Quality Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2 Emergency/Repair Preparedness Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2.2 Questions That the Cable Owner/Operator May Face upon a Cable Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2.3 Emergency Preparedness Plan (EPP) or Repair Preparedness Plan (RPP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2.4 Important Issues to Address in the Cable Supply Contract . . . . . . . . . . 9.8.2.5 Contracting Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.2.6 Service Level Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.3 Skilled Personnel and Training . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.2 Labor Cost: Preventive Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.2.1 Reduce Preventive Maintenance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.2.2 Transfer from Time-Based Maintenance Towards Condition-Based Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.2.3 Use of Monitoring Techniques Which Replaces Preventive Maintenance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.3 Monitoring and Diagnostic Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.4 Offshore Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5 Repair Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5.1 Mobilization Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5.2 Material Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5.3 Civil Works Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5.4 Labor Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.5.5 Indirect Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.6 Service Level Agreement Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.9.7 Costs of Storage and Maintaining Spare Parts in Operational Conditions . . . . . 9.9.8 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maintenance and Remaining Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.2 Remaining Life Estimation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.3 Criteria for End of Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.4 Failure Rate Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.4.1 Global Failure Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.4.2 Failure Rate per Age . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.5 Health Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.5.2 Condition Assessment Approaches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.6 Examples: Retirement Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.10.6.1 Retirement Options for Fluid Filled Cables . . . . . . . . . . . . . . . . . . . . . . . .

575

644 644 645 645 646 646 646 646 648 649 650 650 652 652 652 654 656 657 658 659 661 661 661 662 662 662 663 664 664 664 664 665 665 665 666 666 666 667 667 667 669 669 669 670 671 671 672 673 673

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9.10.6.2 Retirement Options for Pipe-Type Cables . . . . . . . . . . . . . . . . . . . . . . . . . Future Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.11.1 From Time-Based Maintenance Toward Condition-Based Maintenance . . . . . 9.11.2 New Methods for Condition-Based Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.11.3 Data Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.11.4 Satisfaction with Diagnostic Methods and Data Collection . . . . . . . . . . . . . . . . . . . 9.12 Recommendations and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.12.1 General Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.12.1.1 Carry Out Cable Maintenance with a Clear Strategy . . . . . . . . . . . . . . 9.12.1.2 Maintenance Strategy Based upon Statistical Analyses . . . . . . . . . . . 9.12.1.3 Diagnostic Measurements and Monitoring Techniques . . . . . . . . . . . . 9.12.1.4 Keep Maintenance Strategy Under Review . . . . . . . . . . . . . . . . . . . . . . . . 9.12.2 Recommendations for Specific Cable Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.12.2.1 Land Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.12.2.2 Submarine Cable Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.12.3 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A. Definitions and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Specific Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix B. Links and References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CIGRE Technical Brochures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D. Case Studies for Lack of Space, This Appendix is not Reproduced in This Chapter of the Book . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix C. Case Studies for Lack of Space, This Appendix is not Reproduced in This Chapter of the Book . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix D. Case Studies for Lack of Space, This Appendix is not Reproduced in This Chapter of the Book . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9.11

9.1

674 677 678 679 681 681 683 683 683 683 683 685 686 686 687 687 687 687 688 690 690 691 692 692 692

Introduction

This chapter partly reproduces the content of the Technical Brochure 825, published in early 2021 by the WG B1.60, convened by B. Mampaey from Belgium. The TB 825 contains numerous appendices that are not included in the chapter. As this book is dedicated to accessories for extruded cables and does not cover Fluid Filled cables, the part of the TB addressing lapped cables is not reproduced in this chapter.

9.1.1

Background

During the 71st CIGRE SC B1 meeting held in Kristiansand (Norway) between August 31 and September 4, 2015, it was decided to set up a task force (TF) on the topic: “To update TB 279 Maintenance for HV cables and Accessories, with the request to advice if it is feasible to set up a WG on the subject.” The TF concluded that there was a clear need for a WG to update TB 279 (which was published in August 2005). The new WG was expected to deal with the following items:

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• To collect feedback from utilities on the present situation and future needs by circulating a questionnaire to utilities • To make the present TB 279 more complete by including AC submarine cables and DC cables • To describe modern methods for condition-based maintenance and to pay attention to new developments • To focus on practical cases of maintenance • To consider the position of Fluid Filled cables and their increasing need for maintenance • To include aspects of maintenance cost

9.1.2

Scope

All cable types need maintenance activities. The brochure TB 825 considers maintenance of HV AC and DC cables, with extruded and with lapped (laminated) insulation, for land and for submarine applications including their accessories. Special attention is paid to the maintenance aspects of fluid-filled cables and accessories to assure high reliability of these cable systems while avoiding negative environmental effects. As stated above, this part of the TB is not reproduced in this chapter.

9.1.3

Terms of Reference

9.1.3.1 To Review • Existing maintenance practice of utilities, by circulating a questionnaire • Customer needs at present and in the future • The position of Fluid Filled cable systems 9.1.3.2 To Analyze • Modern methods • New developments • Cost/benefit maintenance cases 9.1.3.3 To Propose • Maintenance for HV AC and HV DC cables, for extruded and lapped insulation and for both land and submarine applications, and this for cable systems with voltages above 36 kV (Um) • New methods/developments for condition-based maintenance • Increased attention to practical maintenance cases • Introduction of costs related to maintenance actions

9.1.4

How to Read the Chapter

The Technical Brochure 825/ Chapter 9 deals with many different cable families and types. In order to avoid redundancy, the authors used links between parts of the

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TB. Specific topics like spare parts management, training, emergency preparedness is combined in a separate section for all cable systems (since the basis is the same) while certain types of cable systems are treated separately. Below is an overview of the sections and their content. Section 9.2: Existing Maintenance Practices This section gives an overview of existing maintenance practices and their definitions. Section 9.3: Maintenance strategies An overview of maintenance strategies and the observed trends in maintenance strategies is given. Section 9.4: Maintenance on land based cable systems This section provides summary of the answers received on the questionnaire related to land-based cable systems, as well as an overview of the maintenance practices on land-based cable systems, including HVDC cable systems. Most of the maintenance activities that are dealt with here also apply to the land cable sections of submarine cable links. The respective Sects. 9.5 and 9.6 are focused on the basic and additional maintenance activities for submarine cables and fluidfilled cable systems. Section 9.5: Maintenance on submarine cable systems This section provides summary of the answers received on the questionnaire related to submarine cable systems, as well as an overview of the maintenance practices on submarine cable systems, including HVDC cable systems. For the land sections of these submarine cable links, the reader is asked to refer to Sect. 9.4. Section 9.6: Maintenance on fluid filled cable systems (not reproduced) This section provides summary of the answers received on the questionnaire related to fluid-filled cable systems, as well as an overview of the additional maintenance practices on fluid-filled cable systems compared to land-based cable systems. The status on the position of fluid-filled cable systems is given in this section, and for this type of cables, the majority of the maintenance principles as stated in Sect. 9.4 are also applicable. Section 9.7: Monitoring and diagnostics This section provides summary of the answers received on the questionnaire related to monitoring and diagnostics. Basics of test and monitoring techniques are explained in this section and an overview of applicable techniques is advised for each type of cable system and installation. An indication of cost (level) for the different techniques is also provided. Section 9.8: Spare parts management, emergency preparedness, and training This section combines the topics as mentioned in the title covering all cable systems. Section 9.9: Cost of maintenance An introduction of the cost level as used in Sect. 9.6 is given, as well as trends observed related to the costs to the maintenance of cable systems.

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Section 9.10: Maintenance and remaining life This section describes the link between the impact of maintenance and the remaining life of a cable system. Section 9.11: Future developments Based on the answers on some open questions from the questionnaire some trends in future needs and developments are described in this section. Section 9.12: Conclusions and recommendations The main conclusions related to maintenance practices and recommended maintenance practices for land-based, submarine, and fluid-filled cable systems are given. Appendix A. Definitions, abbreviations, and symbols Appendix B. Links and references Appendix C: Case studies This appendix gives some case studies, based on real experiences, on different topics which are discussed in the different sections. Appendix D: Analysis This appendix gives a detailed and more statistical analysis of the answers received on the questionnaire. Appendices C and D of TB 825 are not reproduced in this chapter of the book.

9.2

Existing Maintenance Practices

9.2.1

Introduction

In order to evaluate the existing maintenance practices, a questionnaire was prepared and distributed to all National Study Committee B1 members all over the world. In total 74 replies were received. The geographical spread of the received replies and type of utilities is as in Table 9.1. A detailed analysis of these replies is made in the technical brochure 825. The questionnaire and analyses are divided into the following groups: • Land Cable Systems AC and DC • Submarine Cable Systems AC and DC • Fluid Filled Cable Systems (FF) Table 9.1 Survey responses by region

Continent Africa Asia Europe North America Oceania South America

TSO 1 10 15 3 4 0

DSO 0 2 25 6 4 0

Power generation 0 0 4 0 0 0

Total 1 12 44 9 8 0

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• Monitoring and Diagnostics • Future Developments

9.2.2

Major Conclusions

9.2.2.1 Land Cable Systems AC and DC Land cable systems is the group with the most diversified insulation technology depending on the application (AC or DC) and voltage class. In AC systems the most preferred technology is the XLPE for all voltage classes. Fluid Filled cables are also popular for voltages up to 420 kV and EPR is used up to 150 kV in some countries. In DC applications the main technologies used are MIND (above 170 kV), SCFF (above 72.5 kV), and XLPE (between 72.5 kV and 420 kV). Almost all users have stated that they perform preventive maintenance activities themselves. A high percentage of the users are also able to localize faults using their own resources. For voltages up to 170 kV many of the users perform corrective maintenance activities using own personnel. The majority of the land cable system users has available spare parts or has a spare part policy. The most popular measure to prevent third-party damages to land cable systems is route inspections including marker stones, warning signs, etc. Another consistent measure observed on systems up to 420 kV is provision of information on cable routes to contractors. The majority of the users consider these actions highly effective and well established, although comments received indicated that the effectiveness strongly depends on the maturity and the willingness of the companies or people executing digging work. In addition, mandatory systems where all excavation/digging activities must be announced in advance seem to be a good tool to avoid third-party damages. To ensure availability of their land cable systems the majority of the owners perform the following visual inspections on the following components: terminations and cable clamping underneath the termination, link boxes and earth connections, tunnels, and accessible joint bays. Moreover, most of the users carry out the following tests: outer sheath test, SVL verification, earth resistance at joint bays, and temperatures measurements. According to responses, continuity testing of ECCs and outer serving are highly effective measurement activity while DTS measurements and metallic screen current measurements had the greatest proportion of low effectiveness responses. Finally, temperature monitoring and partial discharge monitoring at nominal voltage are two of the most popular on-line measurements selected by the users in order to ensure the availability of their land systems. Partial discharge monitoring is the online activity with the highest percentage of positive responses about effectiveness, but it is also seen as having the highest requirement for further development. 9.2.2.2 Submarine Cable Systems AC and DC Submarine cable systems are generally divided into two main technologies: that is, with extruded insulation (XLPE or EPR) or with paper impregnated insulation (MI,

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SCFF, and HPFF). For existing AC cable systems, the replies from the questionnaire showed that cables with extruded insulation are the most common, followed by SCFF, HPFF, and very rarely MI. For DC cable systems, MI technology is the most common, followed by XLPE and very rarely SCFF. HPFF cable systems are not part of HVDC technology. Nearly half of the users stated that they perform preventive and corrective maintenance activities by themselves. However, this statement must be taken carefully since only a part of the activities may be done internally. For example, in case of corrective maintenance, a user may perform fault location internally but rely on a subcontractor for offshore repairs. Majority of users (>50%) perform the following actions to prevent third-party damages: inspections of cable routes, burial depth and landfalls, and use of administrative procedures to provide information on cable routes to contractors. These actions are mostly considered highly effective and well established. There are also fewer common actions performed by a minority of users such as dialogue with locals (fishermen) and monitoring of fishing and shipping activities in the vicinity of cables. The latter needs further development according to users that have put in place such monitoring. The main actions for ensuring cable availability (health) which are performed by 25% to 50% of users, sorted by decreasing occurrence are: continuous temperature monitoring via optical fiber (DTS), monitoring of seabed mobility (moving sand waves, seabed erosion), inspection for corrosion (cable hang-off on a platform), control on free-spans, TDR (or FDR or similar) measurements, occasional temperature measurements, and scour control at I/J tubes. Those actions are generally considered highly effective and well established, except for TDR and DTS where majority of users would like to see it improved.

9.2.2.3 Fluid Filled Cable Systems Fluid filled power cables and accessories feature insulation system composed of fluid-impregnated paper or paper/film laminates. They are generally divided into self-contained fluid filled (SCFF) and high pressure fluid filled (Pipe-type) cable systems (HPFF or HPGF/GP). Both systems have ancillary equipment – reservoirs, pumping stations, pressure gauges, and alarms that require periodic maintenance. Fluid-filled cable systems have been around for a long time and still represent a significant installed transmission network base in many parts of the world. In general, these cable systems (mainly the cables themselves) are still in a good condition and the main issue of the technology is the potential for the leak of the fluid which can be accompanied with moisture ingress. The maintenance techniques and methods are designed to address that aspect. Almost all pressurized fluid filled cable systems have a pressure monitoring system with a continuous or periodic maintenance program. From the replies received on the questionnaire, 50 respondents (67%) still have fluid-filled cable systems in service, the majority of 19 users (38%) have a

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replacement policy. Eighteen users (3%) do not have a replacement policy but are phasing out Fluid Filled cables and 10 users (20%) do not have a replacement policy. The maintenance programs for this type of cables are quite mature, due to the long history and experience. Feedback received via the questionnaire shows that the specific and additional maintenance activities as identified in the questionnaire are considered as very effective and mature, some lower scores were given to the inspection of oil tanks, pump stations, and pressure gauge calibration. Also, the dielectric and moisture test on cable fluids scored somewhat lower. On the other hand, the maintenance on Fluid Filled cable systems is quite labor intensive compared to newer cable systems such as cable systems with extruded insulation, which do not have tanks with fluid or gaseous insulation under pressure (except for some sealing ends/terminations). The most recent modifications in the maintenance activities related to Fluid Filled cable systems consist of reduction of the labor part. Some examples are: • Online fluid pressure monitoring instead of on the spot pressure readings • Use of tracers in cable fluid to facilitate and speed up localization of cable fluid leakage

9.2.2.4 Monitoring and Diagnostics With the purpose of achieving a larger degree of utilization of the cable assets and gaining more meaningful insights in the asset’s conditions, monitoring and diagnostic techniques are becoming more and more popular among system operators and utilities. Additionally, recent technological advancement and enhanced big data analytics capabilities have made some of these techniques more powerful, more readily available and more economically viable. Examples of modern techniques which are gaining ground in the field of on-line monitoring are the distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) (require optical fiber), and partial discharge (PD) monitoring. Next to that, a plethora of diagnostic measurements and tests are available for the determination of the condition of an asset. Oil analysis, outer sheath tests, and spot partial discharge measurements are examples of diagnostic that are high on preference list of the asset owners. A comprehensive group of state-of-the-art monitoring and diagnostic techniques is therefore listed and categorized (monitoring, diagnostic, or both), and the applicability of the test technique to certain type of cable (together with indicative information on the related price level) are provided in Sect. 9.7. The test techniques are further shortly explained and the practical application of the techniques to the maintenance of cable systems is also provided. 9.2.2.5 Future Developments The users of HV cable assets expressed the need for further developments, both of technology and methods that would provide valuable information about cable system condition. The market availability of different kind of sensors and monitoring

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devices provides the asset owners with the tools needed to make a full transition toward condition-based maintenance (CBM). Accessing a deeper knowledge of cable systems operating condition is already possible in various ways, however, it is still challenging to find a common base for asset managers to assess and share the health condition of cables. As stated in the previous paragraph, the advancement of computational power, in conjunction with the new machine learning technique, made it easier to extract valuable information from the vast amount of data that modern diagnostic tools generate. At the same time, suppliers and technical engineering companies are going to face an increasing market need for more accurate diagnosis of insulation deterioration and less expensive sensors. The asset owners may have to implement automated processes for the proper data collection from the field into their asset management systems. In many cases specific software is already present, but new storage techniques, newly developed algorithms, improved automatic analysis and assessment are commonly identified as an area for improvement.

9.3

Maintenance Strategies

9.3.1

Introduction

Maintenance is performed on high voltage equipment for a variety of reasons. The main reasons for carrying out maintenance are: • • • • • • • •

To avoid failures To avoid environmental damage To avoid more expensive maintenance later To extend the life of the equipment To avoid unsafe situations To repair failed components To avoid legal and financial penalties To avoid possible unavailability of the line There are three fundamentally different ways to carry out maintenance:

• Corrective maintenance (CM), to repair or replace broken items • Time-based maintenance (TBM), to perform preventive maintenance based on a specified predetermined schedule • Condition-based maintenance (CBM), to perform preventive maintenance based on the present condition (based upon periodic measurements or monitoring) of the component (condition assessment) TBM and CBM both have the intention to avoid failures in service. CBM can also be called “Predictive Maintenance,” meaning measurements and monitoring to be carried out to determine which maintenance actions will follow in order to avoid failures in service.

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A next step in maintenance is the probabilistic approach. This method takes into account several parameters, such as asset condition, maintenance costs, importance of the asset, risks. All these parameters will lead to a probabilistic maintenance program. Needless to say, that in order to be able to build-up such a probabilistic maintenance program, accurate and reliable data and good expert analyses are required. This type of maintenance is at the moment, and with the current information available, not yet applied on cable systems, however, the probabilistic approach is making its entry in utilities, often as a next/future step in the maintenance policies.

9.3.2

Maintenance Strategies

Based upon the replies received on the survey, we see that up till today the majority of the maintenance activities performed are still time-based. However, due to the increased number of cable systems being installed worldwide, there is a growing awareness that the maintenance should shift toward more condition-based maintenance. Performing the traditional TBM on an increasing number of cable systems demands much more effort from an organizational point of view and also demands more personnel to perform these TBM activities, increasing operational expenditures (OPEX). On the other hand, utilities are often confronted to limit or even reduce OPEX costs, meaning that the traditional TBM maintenance activities have to be reviewed. Some trends that we see are the following: • Modified TBM activities depending on the age, importance or criticality, and type of the cable system (e.g., sheath testing frequency adapted to the aforementioned parameters instead of the same frequency for all cable systems) • Reduce the number of TBM activities and include more CBM activities In order to facilitate transition to CBM, it is important that all data related to cable systems is correct and kept up to date (repairs, re-routing, etc.). A good historical database of past events/incidents and diagnostic measurements performed is also very important in order to perform effective CBM. This topic was also identified with the performed survey. An increased interest and application of online monitoring techniques have also been identified during the survey. This is also with the intention to replace TBM activities or to give additional input for CBM activities.

9.3.3

Previous CIGRE Questionnaire

The CIGRE Report “Questionnaire on Maintenance Policies and Trends (JWG 23/39),” published in 2000 [6], examined maintenance practices and costs for different types of maintenance on a range of transmission system apparatus,

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Table 9.2 Breakdown of direct maintenance cost by % for different transmission equipment Transmission equipment Predictive Maintenance Corrective Maintenance Refurbishment Others

G 54 18 20 9

S 57 17 17 9

Tr 50 23 18 8

L 36 29 29 6

T 35 26 35 4

Ca 24 45 24 7

P 57 18 13 11

Co 40 32 12 19

G general, S switchgear, Tr transformer, L line, T tower, Ca cable, P protection, Co control

including substations, transformers, switchgear, overhead lines, cables, protection and control. The questionnaire considered a variety of issues relating to five major parts of the world – Asia, Eastern Europe, Western Europe, North America, and the Southern Hemisphere. Questions were asked about the type of maintenance program being used and, particularly interest to utilities, the maintenance costs. The responses to the question “Could you breakdown the direct maintenance cost in predictive maintenance, corrective maintenance, refurbishment and other” are of particular interest, and they indicate the differences between maintenance on cables and maintenance on other components. This is illustrated in Table 9.2. This table shows that cables, in contrast to other equipment, have the lowest expenditure on predictive maintenance, and the highest expenditure on corrective maintenance. The reasons for this difference are not clear. Due to the fact that cables are buried out of sight in the ground, they may receive less attention than other more prominently visible components. The absence of moving parts and the low risk of explosion, at least for the cable and joints, may also be a factor. The difference in maintenance attention may indicate that better criteria are needed to devise the available maintenance budget in an optimal manner. The available maintenance budget should be assigned according to the contribution to the overall system reliability [B7]. Thus, cables should have a higher maintenance priority, as, in common with other electric apparatus, cable and accessories are subject to failure and outage. A condition-based maintenance approach appears to offer opportunities to detect potential failures before they happen and to reduce the probability of failures in service.

9.3.4

Summary

Table 9.2, as well as the following section reviewing current practices, shows that compared to other plant types cables receive less predictive than corrective maintenance. This, therefore, offers the possibility of performing maintenance in a different manner in the future. Sections 9.4 and 9.5 are reviewing tools for performing predictive maintenance and the defects that these tools can detect. These new tools need to form part of a coherent maintenance strategy, which balances corrective and predictive maintenance according to the needs of the asset owner.

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Maintenance on Land-Based Cable Systems (AC and DC)

This section covers maintenance activities on land-based cable systems (AC and DC). The section does not go into details regarding maintenance aspects on fluid filled cable systems.

9.4.1

Common Maintenance on Land-Based Cable Systems

Many maintenance activities are applicable to both AC and DC land cable systems. These maintenance activities are discussed in this section. Additional aspects which are only applicable to AC or DC can be found in Sects. 9.4.2 and 9.4.3.

9.4.1.1 Maintenance Activities to Prevent Third-Party Damages Cables are vulnerable to damages caused by third parties as they are installed underground. Most third-party damages to cables are caused by civil works like excavation, digging, or drilling. Hence, maintenance should also focus on the prevention of third-party damages. Even though it cannot be considered as maintenance activity, careful design and determination of the cable route and the laying specification can potentially reduce third-party damages. The greater the laying depth and the better the mechanical protection, the lower the risk of third-party damages. At shallow depths, special additional protective covers can help to prevent damages from civil works (e.g., steel plates). Concrete or plastic slabs in warning colors, including the identification of the cable owner, installed slightly above the cables provide a good indication of the presence of a cable to workers. Some countries additionally use warning mesh which is installed at least 20 cm above the cables. Countries that use ducts for cable and concrete layover seem to experience less damages. Agreements with all landowners above the cable route regarding rights and duties further reduce potential third-party impact. For details regarding statistics on third-party damage, reference is made to TB 398. A periodic patrol of cable routes is one measure to identify possible third-party activities near cable routes early. Additionally, the marking of the cable route (if applied) can be checked during such routine inspections. Figure 9.1 shows

Fig. 9.1 Examples of cable route markers

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three examples of markers. On the cable route, no deeply rooted trees or plants shall be present. Special interest should further be laid on the overall accessibility of the cable route, as accessibility is key to fast repairs in case of damages. The survey shows that routine inspections are widely performed and are considered as a wellestablished maintenance activity. Providing proper information of the cable route to contractors and persons planning civil works is another way to minimize damages to cables. To be able to provide this information, cable owners themselves need proper documentation regarding the exact location of their cables. Especially for older cables or ones which were taken over from other companies, the documentation might not be sufficient and might need to be updated through a new survey. Cable owners should log which information was requested by contractors planning work and which information was provided. Generally, certain civil work methods should only be allowed with prior written approval of the cable owner in the near vicinity of (E)HV cables or when crossing cable routes. This concerns, that is, Larssen sheet pile, drilling, or soil displacement hammer. To further minimize the risk of damage due to civil works, personnel from the cable owner can be present on site to check whether the interpretation of the cable route data is correct and if additional agreements regarding protection of the cable are needed. The survey shows that administrative procedures to provide information on cable routes to contractors are widely applied. About half of the respondents consider their applied procedure as highly effective to prevent damages to their cables. The particular implementation and application of these procedures however differ. To achieve high effectiveness, several approaches are feasible. One viable option is that all civil works must be announced before execution via a dedicated notification system. Existing notification systems are often web-based or organized through call centers (often referred to as “dial before you dig”). After notification, asset owners provide information on cable routes in that location to contractors. Figure 9.2 shows an example of a network register on which all engineering companies or civil workers rely by consulting on internet thanks to an agreement. In this case, cables Fig. 9.2 Example of a network register

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are pulled into ducts (HDPE tubes) and the best protection is to cover the tubes with concrete. When introducing such a procedure details need to be discussed and defined in order to achieve high effectiveness to prevent damages while keeping administrative work to a minimum (e.g., lead time of notification, minimum information regarding planned civil work, response time of asset owner, possibly penalty if system is not used, approval of civil work). Some asset managers organize meetings and conferences with civil contractors, public authorities, architects, and engineers to explain the high voltage network risks in case of damage caused by engine or drill machine. Such meetings and conferences are easy to do for small grid areas, for example, cities but are harder for bigger grids. More and more municipalities have systems in place to coordinate infrastructure works between asset owners. The main purpose is to combine installation activities of underground infrastructure and limit the impact of these works on the cities. Often no additional works are allowed within a certain time frame at that specific location (e.g., 5 years). These procedures also have the advantage that there is a better exchange of information between underground (and above ground) asset owners.

9.4.1.2 Maintenance Activities on Cables Land cables are made up of an array of types such as extruded, PILC, SCFF, GP, or HPFF, which within each variety can have many different types of materials or constructions. However, for this technical brochure, the land cables are treated for maintenance analysis as an analogous group. A more detailed section relating to fluid-filled cables is covered in TB 825. The following sections detail the type of cable maintenance activities that are applied to land cable systems in order to ensure a correctly maintained and operating asset. The full analysis and figures from the questionnaire which are referenced below can be found in this technical brochure. 9.4.1.2.1 Inspections of Land Cable Systems An important part of maintenance on land cable systems is the inspection of component parts of the cable system which are readily accessible. As a cable system is for the most part underground, the majority of inspections are carried out on accessories such as terminations, link boxes, tunnels, clamping systems, earth connections, or protections items like cathodic protection systems. However, any exposed cable sections, in tunnels or cable ends entering terminations, should still be inspected as part of maintenance works. Maintenance inspections are generally performed visually and are a first high level indicator of the cable condition and show issues such as damage or defects, mechanical degradation, or excessive electrical activity. During a maintenance inspection, exposed cables should be checked for any outer insulation damage, any signs of excessive movement or any signs of electrical activity. The clamping underneath the cable terminations and the cable clamping/snaking in tunnels, and under bridges, should be checked as this can indicate if the cable has

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moved in service. While inspecting the clamping, any corrosion of the clamps should be observed and noted. If there are any signs of cable movement within the clamps, the clamp bolts should be checked for tightness by taking torque levels of the bolts versus manufacturer’s recommendations. The cable entering the terminations should also be observed for movement or retraction which could indicate abnormal movement of the cable system in service. A simple system is a band of colored cable retainer, installed before and after the main clamps by a special tool (gripper) where you can adjust the strength of closing the retainer, thus it is easy to check if the cable did move in clamps. As with any inspection these should be checked periodically. All connection points, associated with the cable system such as bonding leads and HV connections, should be visually inspected for corrosion or signs of hotspots. Where possible hotspots are noted, contact resistance measurements should be undertaken. It may also be necessary to carry out an infrared survey when the cable is returned to service. Where a cathodic protection system is installed, the anode and control unit should be inspected to ensure no damage has occurred and that it is operational. This includes carrying out a current measurement of the anode and also a voltage check of the metallic screen of the cable. At link box locations, a visual inspection of the link box pit to check for excess water pooling or any movement of civil works should be carried out. All bonding and earthing leads entering the link box should be inspected for damage or defects. The link box should be checked internally for signs of water ingress, corrosion, or hotspots (caused by high contact resistance points). All connection points should be checked for signs of corrosion or hot spots, and where necessary contact resistance measurements taken. When carrying out maintenance inspections it is important to gather as much evidence as possible so that trending of issues can be carried out over several maintenance cycles. To this end it is recommended to have a central database for cable systems for storing reports and recommendations following inspections. 9.4.1.2.2 Maintenance Diagnostic Measurements An important tool in diagnostics of land cable systems is the use of measurement techniques to test/check for any possible issues arising on the cable system or to trend the operation/health of the cable system. The majority of measurement techniques are carried out offline (circuit de-energized) and the results are used as a tool for assessing the land cable system health. Baseline measurements carried out early on (e.g., before the cable is set into service for the first time) are a good reference for measurements later on, as such “fingerprint” measurements reflect the initial condition of the cable system. For the purpose of the questionnaire, the WG gave a set list of measurement types which can be found fully in TB 825 and there is also a comprehensive listing of diagnostic techniques in Sect. 9.7. The aim of diagnostic measurements during maintenance is to determine any issues or possible underlying problems with the land cable system which may not be apparent in service. In case of failure repairs, an option may also be to take material samples and send to laboratories to assess their quality and condition (e.g., insulation, outer jacket, lead sheath).

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Cable sheath integrity is extremely important to the full working system and an excellent indicator of any external damage to the cable circuit. A sheath test (also known as outer-serving test) is done by applying a voltage between the metallic screen and earth, while the cable is out of service, and recording any leakage current or indicators of breakdown of insulation. The test voltages applied can be dependent on cable age, or condition, with an aged system having reduced voltages applied, so as not to overstress the sheath insulation. Metallic screen current measurement is carried out in service and uses a similar idea to outer sheath testing. Any degradation or damage to the outer sheath can lead to a change in the bonding system of the cable circuit and may result in increased circulating currents in the metallic screen. A current clamp is applied to the outer sheath (via bonding lead) and will record any increase in current. However, this is generally only used for specially bonded systems such as single point bonded cable systems or cross-bonded cable systems where the screen currents should be negligible. The value of the screen currents during this insulation test should be recorded and be stored in a database and compared periodically. Experience shows that a hole in outer sheath is detectable and could be located with usual fault locating devices. Testing of sheath voltage limiters (SVL) is an important aspect of cable maintenance as they are integral to the correct operation of specially bonded systems. If an SVL is not operating correctly, then the cable in service will have circulating currents which can result in a de-rating of the cable operational capability. This will also lead to overheating of the cable system if not detected in time, causing an increased aging of the insulation or even breakdown of the cable system. Incorrectly operating SVLs can also lead to partial breakdown of the cable outer sheath due to high over voltages from lightning, short circuits, switching actions, harmonics, etc. Other measurements of interest are distributed temperature sensing (DTS) measurements for indicating hot spots and time domain reflectometry (TDR) measurements. DTS as a measurement tool is capable of indicating a hot spot on a cable system and can be useful for inaccessible sections such as joints. TDR (Time Domain Reflectometry) can be useful for open-circuit faults, severe shunt faults, locating joints, healthy/faulty comparisons between phases and also for comparisons between TDR traces of an originally commissioned fingerprint and traces obtained at any time thereafter during operation. Sending an impulse toward the fault will cause the fault to break down; this allows the transient current to be detectable and multiple reflections of the event to be visible. The loss angle, tan δ, is a measurement of the losses in the insulation material; the so-called dielectric losses. The loss angle is an important indicator for the condition of the cable insulation. The measurement can be performed using the mobile tan δ measurement sets in combination with an external voltage source (resonance test set) or using the network voltage. These are just a number of the measurement types currently being used on land cable systems but give an indication of the very useful information that can be collected and used when assessing and maintaining a land cable system.

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The results of the questionnaire indicate that the sheath test (outer-serving test) is the main measurement maintenance activity utilized. Sheath voltage limiter (SVL) testing had a large positive response in the questionnaire and is generally related to specially bonded systems (such as single point bonding or cross bonded systems). As an online measurement tool distributed temperature sensing (DTS) measurements for hot spots seems to be the most commonly used among recipients. Compared to visual inspections there is a split between these maintenance activities being time based or condition based. Measurements such as sheath tests, verification of SVLs, or earth resistance measurements at joint bays are mainly TBM while DTS measurements, PD measurements, and tan delta tests would be equally TBM or CBM. The general consensus would be that items such as sheath testing or SVL verification are fairly well established whereas measurement types such as DTS or metallic screen current measurements still require development. However, as companies/utilities move toward more innovative and condition-based maintenance plans then these types of techniques should become far wider utilized and established for land cable systems. 9.4.1.2.3 On-line Monitoring Activities As companies/utilities work toward a more condition-based maintenance program the use of online monitoring is becoming more prevalent. This type of maintenance activity is carried out with the cable system energized. The methodologies used are very similar to those covered in diagnostic measurements, such as DTS measurements, metallic screen current measurements, or PD monitoring; however, for this type of activity it is continuous and can show a far greater trend than that of scheduled diagnostic monitoring. This type of monitoring can also be connected to an alarm system which will trigger if certain threshold figures occur. The questionnaire highlighted that there is a relatively low uptake of cable system monitoring. Due to the relatively low amount of utilities performing monitoring techniques, the monitoring types are mostly under development or experimental. DTS measurement for temperature monitoring and PD monitoring are the most established techniques and are the most utilized among respondents. There are two alternative CIGRE technical brochures which also discuss these subjects: Technical Brochure 756 “Thermal monitoring of cable circuits and grid operators’ use of dynamic rating systems” and Technical Brochure 728 “On-site Partial Discharge assessment of HV and EHV cable systems.” This area of cable maintenance is currently the most underdeveloped; however, it is expected that in the coming years, experience and knowledge regarding monitoring techniques will increase and will result in a reduction in outage related to maintenance activities such as measurement testing and a more dynamic maintenance program for land based cable systems. For further details on monitoring and diagnostics see Sect. 9.7.

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9.4.1.3 Maintenance Activities on Accessories Accessories are crucial components of cable installations. Regular maintenance activities can ensure the health and integrity of accessories. For cables installed on land, especially transport possibilities restrict and determine the deliverable cable length, further determining the number of joints necessary for longer lengths. Additionally, cable systems are always equipped with terminations at the beginning and at the end of each cable phase. Accessories are generally mounted on project site. The installation process of joints and termination is still a highly manual process due to its complexity. Additionally, with rising voltage level, the permissible fault tolerances of the jointing and installation process decreases, which not only involves the work steps but also the ambient conditions. Pre-fabrication development of accessories is constantly improving to reduce the amount of manual installation work on site, hence reducing the possibility of negative influences on installation quality. However, so far, the main installation steps of terminations and joints, especially for HV cables, involve quite some manual work on site. According to CIGRE Technical Brochure 379, about 30% of faults on land cable systems reported 2000 to 2005 were failures of joints or terminations. Some of these faults might have been able to detect in an early stage with certain maintenance measures, which might have had a positive impact on the out-of-service time to repair the fault or defect. In the following sections, maintenance activities for terminations and joints to monitor the condition and to check the health and integrity of accessories are discussed. The activities described in this section apply to HVAC as well as HVDC cables. Additional activities, which are applicable for only HVAC or HVDC, are described in Sects. 9.4.2 and 9.4.3. 9.4.1.3.1 Maintenance Activities on Terminations At termination level various maintenance activities can be applied. Depending on the type of termination (AIS, GIS, dry, oil-filled, gas-filled) different maintenance activities are possible. The following subsections are grouped in maintenance activities, which can be applied on all types of terminations, and additional maintenance activities applicable for certain types of terminations (outdoor, fluid-filled, gas-filled). 9.4.1.3.1.1

All Types of Terminations Regardless of the special type of termination, several maintenance activities can be applied to all types of terminations.

Visual Inspection According to the survey, visual inspection is the most common maintenance task on terminations. Visual inspections are an easy and established maintenance activity, while proving to be very effective to detect various kinds of abnormalities. It is recommended to perform visual inspections of terminations at least once a year. Manual visual inspections executed on site not only makes use of the vision sense,

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but other senses such as hearing, touch (only on passive or offline parts) and smell can deliver additional important information. Automated visual inspection methods are evolving and can become a good addition to “old-fashioned” visual inspection. However, automated methods only capture visual information, which must be further processed and analyzed. Visual inspections shall focus on any abnormalities of the termination and its surrounding combined with an integrity check of all visible components and parts of the termination. Abnormalities could be dirt, stains, cracks, chippings, deposits like salt, etc. on the outside of the termination. For fluid filled terminations, the base plate of the termination should be checked for residues of fluids. Further, the integrity and condition of all earthing connections needs to be checked, including SVLs if used. Apart from the termination itself, the condition of the steel structures, screw, and earthing connections should be checked as well. Additionally, the integrity of cable clamps shall be checked and any signs of motion of the cable in clamps documented. Hot Spot Temperature Measurement by Thermography Certain electrical or insulation faults inside terminations can be detected using infrared thermography. As infrared thermographic scanning systems measure surface temperatures only, only hotspots that influence the surface temperature of the termination can be detected. Additionally, to the check for single hotspots, terminations of one cable system should show no significant difference in temperature. It is recommended to do hot spot measurements once a year as part of regular maintenance. The frequency shall be adapted accordingly for suspect terminations. According to the survey, hot spot temperature measurements are done by about half of all respondents. Such measurements are executed once a year by most users. The activity itself is classified as well established by most of the respondents. However, it has to be noted that the right timing is crucial for this maintenance activity to be effective. Partial Discharge Detection (Periodic One-Off Measurements) Generally, partial discharge (PD) detection can be an effective way to evaluate the insulation condition of accessories. For PD detection different methods are available; examples are acoustic emission measurement, radio frequency interference scanning (RFI), and transient earth voltage detection (TEV). PD detection can be carried out while the component is in service (online) or out of service (offline). Contrary to online PD measurements, the voltage can be altered when performing PD detection offline. Meaning, more information on partial discharge inception and extinction voltage can be gathered. Additionally, offline PD detection allows the possibility to check above nominal voltage if any PDs ignite. The obvious disadvantage is that the cable system must be taken out of service for the measurement. Further, additional costs for the external voltage source must be considered. Online PD detection on the other hand captures the PD activity under operating conditions. As online measurement is more sensitive to noise the distinction between noise and PDs from a defect can be a challenge.

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For periodic one-off measurements, it is important to define standardized measurement procedures, in order to be able to compare different measurements to each other (fingerprint-measurements). This can mean to define a certain test setup (especially when using portable devices), or the permanent installation of PD sensors with a defined connection point for the analyzing unit. In addition to the test setup itself, data storage of the measuring data needs to be defined as well. Besides, also the applied measuring parameters of each measurement need to be recorded to allow interpretation of different measurement sets. For further details reference is made to CIGRE brochure 728 On-site partial Discharge Assessment of HV and EHV Cable Systems. According to the survey, periodic one-off PD measurements are done by about 20% of respondents. Remarks indicate that the activity is done mainly on suspect terminations only and not as a regular maintenance task on all terminations. Additionally, PD one-off measurements are mostly not seen as a well-established activity, but an activity which requires further development to be widely applied. Nevertheless, about a third of respondents performing periodic one-off PD measurements consider the effectiveness to prevent future failures to be high. X-Ray Another nondestructive maintenance activity is using X-rays to image the structure of accessories. The image produced can be inspected for defects such as deformations and displacements in cables and accessories [B1]. In Addition, core movement can be detected with this method. Case studies are given in an Appendix of TB 825. According to the feedback of the survey, X-ray is not a widely applied maintenance activity. Only 5% of respondents use X-ray in maintenance of cable accessories; mostly as needed or in exceptional cases. The opinion regarding the maturity ranges from well-established to experimental use, among the users of X-ray imaging. Derived from the few answers to this topic, the intentions for the use of X-ray imagining differ among users. Some users apply X-ray imagining at joints to detect core movement (in particular for Fluid Filled cables), and the method is regarded as well-established activity and highly effective to prevent failures. Whereas on the contrary some users apply X-ray imagining only in case of failure investigations to gain additional information from the images regarding the root cause, but not as normal maintenance task on healthy cables. The maturity level of this activity is considered experimental by those users. In conclusion, X-ray is not considered as necessity for periodic maintenance. It is rather considered a valuable additional tool to determine the condition of suspect accessories and to help in failure investigations. 9.4.1.3.1.2

Outdoor Installed Terminations For outdoor terminations following additional maintenance activities are possible:

Cleaning of Outdoor Termination Dirt and deposits (e.g., salt, algae) on the outside of terminations eventually reduce the creepage distance. Special attention needs to be taken for HVDC terminations

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which attract dust due to the electrostatic effect (also indoor). Hence, cleaning of outdoor terminations is necessary to maintain the integrity of the termination. It is recommended to clean terminations at least once a year. In regions with higher levels of pollution, near-shore or other reasons for higher deposit rates on terminations, cleaning intervals need to be adapted accordingly. According to the survey, the majority of respondents clean outdoor terminations. The frequency varies from fixed time intervals (mostly once a year), to as needed depending on the amount of dirt/deposits on the termination. This activity is regarded as well-established and is seen as highly effective to prevent future failures. Special Coating on Outdoor Termination to Improve the Hydrophobicity Considerable efforts have been made over the last few decades for developing selfcleaning surfaces. Hydrophobic coatings show significant self-cleaning characteristics and long-term resistance to weathering and difficult environments. Such coatings on outdoor terminations help to reduce leakage currents, discharges and pollution flashovers. According to the survey, special coatings on outdoor termination to improve the hydrophobicity are not widely used. Roughly 10% of respondents apply this method. Most of the users regard special coatings as well-established and highly effective to prevent future failures. If applied, it is mostly done for specific cases only (e.g., after frequent flashover events, near shore, high pollution areas), and not as a standard maintenance activity. Corona (Not Asked for in the Survey) Outdoor installed terminations can be checked for corona to determine abnormalities. If applied, special attention to the bolts on top of terminations should be made. Similar to PD or temperature measurements a comparison between phases of one cable system should be done. This maintenance activity was not asked for in the survey but was mentioned by one respondent. Check of Arrestors (Not Asked for in the Survey) Arrestors of terminations, which are equipped with a surge counter, should be regularly checked for data recording and functionality as part of maintenance. This maintenance activity was not asked for in the survey but was discussed among the working group. 9.4.1.3.1.3

Fluid-Filled/Gas-Filled Terminations Presently, the vast majority of cable terminations at transmission voltage level are filled with insulation fluid or insulating gas. This applies not only to terminations of fluid-filled cables but also to terminations of extruded cables. Currently, strong effort is taken in developing dry-type terminations for all voltage levels. However, fluidfilled and gas-filled terminations are applied widely and call for additional maintenance activities, especially terminations where the insulating medium is under pressure need special attention in maintenance. In principle, the maintenance

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activities of these types of terminations are similar to maintenance activities for fluidfilled cables. Additionally, manufacturers often provide terms for certain components (e.g., O-rings) after which they need replacement. Maintenance instruction should reflect this data. Pressure Monitoring/Alarm/Density Monitoring and Pressure Readings (on Location) Monitoring of the pressure of fluid-/gas-filled terminations and/or density monitoring is essential to be able to detect deviations in an early stage. Certain defects can be recognized before an electrical breakdown of the termination occurs. When using a monitoring system, it is important to also check the functionality of the monitoring system and its alarms as part of maintenance on a regular basis. An alternative way to monitor the pressure of terminations is to do pressure readings on location. This activity can easily be combined with visual inspections for example. Regardless, if pressure is monitored online or if pressure readings on location are applied, not only the pressure data itself, but also the corresponding ambient conditions need to be recorded as the pressure depends also on these conditions. An analysis of pressure data should be performed from time to time to be able to detect trends – for example, possible slight deviations over time. According to the survey, both pressure monitoring/alarm/density monitoring and pressure readings on locations are widely applied on terminations. While monitoring is mostly done using continuous remote measurements, pressure readings on locations are done as often as once a week. The appropriate frequency certainly depends on whether pressure reading is the only source of information about the pressure, or if additionally, some kind of monitoring system is installed. Pressure Gauge Calibration/Exchange In addition to pressure monitoring and pressure readings, attention should be paid to the pressure gauges themselves in maintenance. A regular calibration or exchange of the pressure gauges should be part of maintenance of fluid-/gas-filled terminations under pressure. According to the survey, about 20% of respondents do pressure gauge calibration. The time interval of exchange/calibration is mostly once a year. For fluid-filled terminations, following additional maintenance activities are possible: Check of Fluid Level Lack of insulation fluid eventually leads to breakdown of terminations. Most leakages of terminations can be detected through visual inspections. However, failure cases are recorded, where the insulation fluid leaked into the XLPE-cable and no sign of leakage could be visually detected. Therefore, apart from visual inspections it is recommended to check the fluid level of terminations on a regular basis. The challenge with this task is that terminations are generally not designed to allow easy checks of the fluid level. Normally, terminations have to be taken out of

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service and have to be opened, to determine the fluid level. This activity bears the risk that the insulation fluid gets contaminated. The development of other methods is needed to facilitate this maintenance task – in the best case, without having to take the termination out of service. One possibility is to request the termination designer to have facility to be able to check the fluid level without having to open the whole termination, and this would reduce the risk of contamination (e.g., insertion of a rod, sensors, visual possibility). In the survey question it was asked that the “check” of fluid level was used in combination with pressure monitoring. According to the survey, almost half of respondents perform this maintenance activity. The frequency ranges between every 3 months up to every 6 years. The activity is considered by the majority of respondents to be highly effective to prevent future failures and well established. Analysis of Condition of Insulation Fluid As the majority of terminations are filled with insulation fluids, regular checks of these fluids can help to determine the condition of the fluid. Knowledge of the condition of the termination liquid greatly contributes to decision making, whether the insulation fluid is still serviceable or may need replacement. Different analysis methods and sample taking methods are available (see, e.g., EpriReport_2 [2]). It is noted that pulling fluid samples hold a potential danger to contaminate the insulation fluid in the terminations. Additionally, care has to be taken that the sample itself is not contaminated before analysis to guarantee that the characteristics of the fluid sample are not altered. Sample taking as well as storage until analysis must be done under controlled conditions to avoid any contamination of the sample itself as well as of insulation fluid of the termination. Different kinds of insulation fluids are used in terminations and this has to be taken into account when analyzing the fluid, as well as in the interpretation of the data. Especially regarding silicone oils, which are widely used in terminations, no common thresholds for dissolved gases exist presently. This makes the interpretation of data challenging. However, broader application of DGA on silicone oils will mean more future development to determine thresholds for gas levels. An indication for possible thresholds can be found in EpriReport_2 [B2]. According to the survey, analyses of termination liquids are not commonly done. About a quarter of respondents do condition analysis of insulation fluids of terminations. When considering DGA it is good to know the characteristics of fluids of newly installed terminations (e.g., detailed data sheet). DGA could be a tool to check installation quality by analyzing a fluid sample a few months after commissioning. Endoscopy To check for water ingress and, more generally, whenever the insulation fluid is to be tested for impurities, an endoscopy test can be used. Attention is needed in order to not introduce any pollution or contaminants into the termination during the endoscopic examination. The application of such a test can be found in [B2]. If the termination is not designed to allow such test, it is advised to choose an alternative such as taking oil samples and run DGA analysis or analysis of the water content in

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oil, which is considered more effective and less intrusive than the endoscopic examination. During the endoscopy it is also advisable to verify the health condition of the grading cone inside the termination itself: after a visual probe assisted check, conclusions have to be taken about the opportunity to open and dry out the insulation fluid, in order to have further details on the potential tracking of the cone. According to the survey, endoscopy tests are not widely applied by operators of cables. Only 10% of respondents use them as part of their maintenance. Regarding frequency of this activity, only two answers were given, which are every 5 years, and every 10 years. Hardly any information was given on the effectiveness of this method. Regarding maturity, the majority of users classify endoscopy tests as either experimental or requiring development. Fluid Replacement If the condition of the insulation fluid is poor (e.g., derived from DGA or endoscopy tests), a fluid replacement can prolong the lifetime of a termination. According to the survey, fluid replacement is done by about 15% of respondents. This method is seen by the majority of users as highly effective to prevent future failures and the maturity is seen as well established. Comments to this maintenance activity show, that refills are done if required, in exceptional circumstances or if the insulation fluid is in poor condition. Another reply claims to not do complete replacements, but refill as required. Regarding frequency of this activity, the answers show relatively short intervals ranging from every 1/3 year to every 5 years. It is assumed that the short intervals correspond to checks like pressure reading, fluid level check, or fluid condition analysis which may lead to the decision of fluid replacement rather than the fluid replacement or refill itself. 9.4.1.3.2 Maintenance Activities on Joints Joints are often not accessible. For inaccessible joints, only monitoring equipment can give information on their condition. However, if joints are accessible, it is recommended to apply similar maintenance activities as for terminations, to check the integrity of joints regularly. Joint locations are generally outside of substations or transition stations. Hence, it is necessary to have all necessary permissions to ensure the accessibility to all joints for maintenance activities and measurements. It has to be noted that no information is available from the survey, how many respondents have accessible joints in the first place. This has to be kept in mind when interpreting the data given from the survey. 9.4.1.3.2.1

Hot Spot Temperature Measurement of Joints (Tunnel, Manholes) Similar to hot spot measurements on terminations, these measurements can also be performed on accessible joints. Seventeen percent of respondents do such measurements as part of their maintenance. To do so, mostly IR-cameras are used. For non-accessible joints the temperature can be monitored via temperature sensors (i.e., PT100) or fiber optics (see Sect. 9.7 for further reference).

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9.4.1.3.2.2

Visual Inspections of Joints (e.g., in Tunnels, Shafts/Pits, Manholes) Similar to visual inspections of terminations, accessible joints should be visually checked for any kind of abnormalities. Visual inspections shall focus on any abnormalities of the joints and its surrounding combined with an integrity check of all visible components and parts of the joints. Further, the integrity and condition of all earthing connections needs to be checked, including SVLs if used. Apart from the joints itself, the condition of the steel structures, screw, and earthing connections should be checked as well. Additionally, the integrity of cable clamps shall be checked and any signs of motion of the cable in clamps documented. 9.4.1.3.2.3

Joint Sectioning Test (Only in Joints with Screen Separation) A joint sectioning test is normally performed during sheath testing. The principle is earthing one side of the sheath at a sectionalizing joint (joint with screen interruption) and applying voltage on the other side. In this way the integrity of the sheath interruption is tested and possible sheath to sheath faults can be detected. About 13% of respondents perform joint sectioning tests. 9.4.1.3.2.4

PD Detection (One-Off Measurements) Similar to one-off PD measurements at termination level, PD detection can be performed on joints as well. According to the survey about 20% of respondents perform periodic PD measurements (either on online of offline cables).

9.4.2

Maintenance Activities on Specially Bonded Systems

For HVAC cable systems, additional maintenance is advisable for specially bonded systems. Examples are: • • • • •

Verification of cross-bonding operation Inspection of link boxes Inspection of sheath voltage limiters Screen current measurements Verification of the integrity of the oversheath

A specially bonded design is incorporated on cable systems to reduce induced currents on cable screens, which have a de-rating effect on the cable operational capacity. A specially bonded system is made up of two design types: single point bonding and cross bonding. This is achieved by incorporating different arrangements of the cable screens. These bonding systems would generally use SVLs as part of the installation. The traditional design and installation method of cable bonding systems would have been directly earthed, where the cable screens are earthed at set locations along the cable route.

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A single point bonded design is used for a single section of cable and is achieved by earthing one end of the cable screen wires while leaving the opposite end unearthed. This results in no circulating or induced currents; however, there will still be a standing induced voltage on the screens which must be taken into account. Generally, the unearthed end is terminated through an SVL, connected to earth. For large transient voltages, during fault conditions mainly, the SVL will “break down” and allow a path to earth. It is important that the SVLs are tested periodically so as to prove that they are operational and have not become a path to earth during normal operating conditions, as this will lead to a directly earthed system and circulating currents in the cable screen wires/sheath. For single point bonded systems there can also be an earth continuity conductor (ECC) that is present, to allow a path for fault currents. If the ECC termination points are accessible, these should be inspected during maintenance inspections to ensure continuity. This can be achieved by visibly checking the installation, but if it is possible to disconnect the ECC a continuity test should be carried out. A cross bonded system is used for longer run of cables and incorporates the transposition of cable screens, or the cable cores in some instances, to result in a net zero value of induced currents. Due to the long cable sections used, SVLs are positioned at transposition points to allow for earthing points for large voltages under fault conditions. It is important that the SVLs are tested periodically so as to prove that they are operational and have not become a path to earth during normal operating conditions, as this will lead to a change in the bonding configuration and result in circulating currents in the cable screen wires/sheath. In both cases above, it is important that no sheath faults are present on the circuit, as this will introduce new earthing points on the bonding system and result in induced currents being present, especially in directly buried cable systems. It is also necessary on a single point bonded and cross-bonded system, that link boxes containing SVLs are free from water ingress as this will result in an unwanted earthing point on the system. The use of specific sensors to protect the circuit from vandalism and to detect water ingress in the link boxes could also be considered. The visual inspection of link boxes and SVLs should be performed on a regular basis and after any short-circuit in the cable system or after a major system failure. Additionally, the SVLs should be either substituted or tested to determine their exact condition by checking their volt-ampere characteristic curve (e.g., every 10 years). This test can be performed on site with portable equipment or in a laboratory. Currently, concepts are developed to verify the operation of these specially bonded systems while in operation by carrying out sheath current measurements. Any change to the bonding system may result in increased and/or unbalanced currents and highlight issues arising with the cable system. For safe work it is also advisable to perform periodical checks of the earthing resistance at link boxes to avoid harmful touch potential. Regarding guidelines of safe maintenance on link boxes and other equipment of specially bonded systems, reference is made to the upcoming Technical Brochure of WG B1.44 “Guidelines for safe work on cable systems under induced voltages.” For more details relating to specially bonded systems on HV cables, reference is made to CIGRE Technical Brochure 283.

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Additional Maintenance for HVDC Cable Systems

9.4.3.1 Additional Maintenance Activities on Cables HVDC cable systems require very few additional maintenance activities compared to HVAC cable systems. Since no significant inductive coupling effect is present in HVDC cables, there are no induced currents in the cable screens and hence no cross-bonding techniques are necessary to increase the ampacity of the HV cable system in normal operation. Under fault conditions, the resistive coupling effect is present in HVDC systems as well and can cause a significant earth potential rise between screen and earth. Fault currents flowing through the earthing electrode into earth will cause an earth potential rise. The fault current will return from the fault location to the power source following various paths. These paths could include screen wires of the faulted power cable/s, earth continuity conductors installed along with the cables, top wires of OHL lines, earth itself, and other metallic infrastructure installed in the ground. Figure 9.3 gives an overview of the calculation of the earth potential rise: the resistance at both extremities of the HV cable system is negligible and I3 is very low compared to I1 and I2. The maximum earth potential rise occurs when a fault appears in the middle of the HV cable system between the two screen earthing points. In order to limit the earth potential rise and avoid an electric breakdown of the sheath insulation, the cable screens are sectionalized and earthed locally. This requires the installation of local earthing loops and eventually their protection by cathodic protection.

Fig. 9.3 Earth potential rise in HV cable system during fault conditions.
Uf ¼ the earth potential rise
R ¼ the dc resistance (per km) of the cable screen
‘ ¼ the length of the cable system
If ¼ the fault current

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Fig. 9.4 Visible flashover marks on termination

9.4.3.2 Additional Maintenance Activities on Accessories 9.4.3.2.1 Terminations The difficulties in dimensioning the insulation of the DC cable end termination has caused several fault cases for the utilities. The root cause of the faults is that the creepage distance of cable end termination porcelain insulator could be designed too near to its limits for the environmental conditions it is put into. Actual conditions like humidity, icing, frost and cold fog and rain should be considered by the specification and the design of the termination. If this is not the case, flashovers at the termination in the named severe conditions could take place (Fig. 9.4). Similar conditions could be caused also by the pollution or salt from the sea. More in general, these kinds of faults/experience should lead to better technical specification. Instead of replacing the cable end termination, the electrical withstand level of the termination in these severe conditions can be improved by coating the termination and by regularly cleaning the surface of the terminations. DC voltage could attract more dust particles and thus require more frequent cleaning of termination compared to AC voltage even for indoor applications. 9.4.3.2.2 Joints For HVDC joints no special maintenance activities are required compared to HVAC joints.

9.4.3.3 Fault Finding on Long HVDC Systems HVDC cable systems are required for the transport of large energy amounts over long distances. Therefore, long power cables are generally designed as HVDC links. Cable fault location on long and extra-long cables is a particular challenge. On long

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submarine cables, most of the commonly used measuring methods developed are not successful for application on short length of buried land cables. In HVAC, the fault current due to electric faults is large. For HVDC transmission systems the fault current, due to electric faults, is much lower and only affects the individual faulty section of the overall transmission system. This specific parameter (long cables – high resistance faults – require adapted fault finding techniques: TB 773 – Fault location on land and submarine links (AC and DC). • On long and extra-long cables, special high performance TDR are applied and provide best technical features to overcome the high pulse attenuation and thereby allows successful detection and distance measurement of low resistance cable faults, as well as identification and distance measurement of cable joints and the cable end. • Non-convertible high resistance faults can only be measured by application of a dedicated high voltage measuring bridge according to the Murray Method and intermittent faults require special high voltage fault location systems for the location of intermittent faults on long and extra-long submarine cables. There, the Decay Method and the Differential Decay Method provide a good technical solution. Common available cable fault location equipment is designed neither to cope with extraordinarily high energy levels, nor for safe discharge of such high energy. Moreover, common available equipment is not safe to cope with transients waves of such high energy content. Additional safe discharge of high discharge energy and protection against transient waves is necessary for long cable systems.

9.4.4

Corrective Maintenance

Corrective maintenance is generally defined as the maintenance carried out after fault recognition and intended to put an item into a state in which it can perform a required function. The following is a brief description on this topic but does not go into detail as it is outside the scope of this technical brochure. The application of an efficient corrective maintenance program is important in the continuity of a cable system. A defect, or fault, may be detected during inspections, diagnostics/test measurements or monitoring, but the course of action to rectify the fault should be consistent for all three maintenance activities. The same can be said for a failure in service but this will be more accurately addressed using an emergency preparedness plan to return the asset to service. The fault identified during maintenance cycles should be classified for priority such as low risk, medium risk, high risk, or emergency. By classifying the fault, it is then possible to have appropriate actions and timelines assigned to each classification. An example of this would be the corrective maintenance actions for sheath faults. Depending on the test results obtained during outer sheath tests, a classification could be applied to the corrective action. A low risk sheath fault could be monitored over several maintenance cycles until an appropriate outage was available for repair.

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A high risk, or emergency level, sheath fault would require immediate action before the cable system could be returned to service. In order for an effective corrective maintenance system to be in place, accurate processes should be developed to ensure the corrective action is of an appropriate and timely response to the fault found during maintenance activities.

9.4.5

Tunnels

Tunnels are normally designed for a life of a hundred years. It should be an integral part of the tunnel that it be designed and constructed to enable maintenance, repair, and replacement of the HV cable systems and different structures inside the tunnel. Specific preventive maintenance activities are necessary in order to preserve the structure of the tunnel as well as to ensure the safe operation of the HV cables. On the other hand, specific access and safety procedures to enter the tunnel are necessary to guarantee the safety of the personnel and the quality and safe operation of the installed infrastructures inside the tunnel. Major repairs and renovations may be required in case of major deterioration of the structure. The TB 720 “Fire issues for insulated cables in air” covers different aspects of HV cables in tunnels. This paragraph describes different aspects with a direct link to maintenance activities.

9.4.5.1 Cable Design and Impact on Maintenance From the design of the HV cable it is possible to take into account the impact on maintenance activities once the HV cable is in service. Cleats or supports used should be designed to have the same (or longer) asset life as the cable. The cleats should be calculated, in function of the type of cable, to support the electrodynamic forces (short-circuit) and the dilatation of the conductor in normal operation (snaking). The design of the earthing system of the HV cable system could avoid or limit the number of components that needs periodic testing (e.g., SVL) or visual inspection (e.g., limit number of joints). The monitoring of critical components (e.g., joints, SVLs) can help to limit the number or the duration of visual inspections inside the tunnel. The design of the cable could take into account an easy verification of the quality of the outer sheath. In case an outer sheath test is carried out, a semi conductive layer is applied over the outer sheath. Another possibility is to use a multi-colored layer design with the outer of the outer sheath a different color to the inner layers. In order to increase the performance of the outer sheath for the risk of fire, a special flame retardant sheathings (e.g., HFFR) or intumescent paints should be used. Additional information with regard to SVLs and bonding systems in tunnels is provided in TB 797. 9.4.5.2 Tunnel Design and Impact on Maintenance Various fire equipment can reduce the risk for fire in a tunnel: early detection of smoke release and temperature increase, or with installations of sprinkler or gas spray systems, avoid having combustible material in the tunnel, make use of fire-

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retardant materials when possible. Periodical inspection and maintenance of the overall structure and a good organizational method improves greatly the safety and reduce the consequences of a fire start. A forced ventilation system helps to cool down the conductor temperature and to increase the cable ampacity, but in case of fire the ventilation system accelerated the propagation speed of the fire. Forced ventilation can also be used to increase chance of safe escape instead, by extracting the smoke away from the occupants’ escape route. Such methods are employed in safety design of road tunnels with burning vehicles. It would require airflow reversing system including appropriate control.

9.4.5.3 Maintenance Activities and Procedures in Tunnels A maintenance program should be established in order to ensure that debris does not accumulate and that all the essential services of the structure are working properly, hazardous materials are not stored in the structure and access/exit ways are clear. Some typical maintenance activities for HV cables are listed below: • Visuals check for corrosion of the cleats or supports • Visual check for sediments on cables • Visual inspection of the intumescent paint, etc. But also, other maintenance activities on the structure and installed equipment are necessary: • Inspection on the accessibility of the tunnel • Check for water ingress in the shaft and horizontal part of the tunnel • Inspection and verification of the functionality of fire alarms, ventilation systems, etc. • Maintenance on heating, communication material (e.g., phone, HF radio, communication network), etc. • Lights and emergency lights • Surveillance and cleaning of tunnels and its access • FO cables and FO equipment • Emergency evacuation material, etc. Local regulations concerning inspection and certification should be followed.

9.5

Maintenance on Submarine Cable Systems (AC and DC)

9.5.1

Preventive Maintenance on Submarine Cable Systems

9.5.1.1 Maintenance Activities to Prevent Third-Party Damages Available statistics demonstrate that internal failures constitute only a minor share of all submarine cable faults (ref. CIGRE TB 379, 2009). The main causes of external aggression to submarine cables are fishing activities and anchoring. Deliberate

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aggression against in-service HV cables have rarely occurred. Therefore, it is inadvisable to keep the position of the submarine power cables secret. International Cable Protection Committee Recommendation No. 5 “Standardization of Cable Awareness Charts” suggests that before, during, and after cable installation, one of the first steps necessary to protect a submarine cable from third-party damage is to communicate the cable location to sea bed users that engage in activities that may endanger the cable. All littoral countries have national hydrographic authorities responsible to issue official nautical charts. The cable route should be communicated to the appropriate national authorities so that the cable will be shown on government produced and commercially available charts as well as chart corrections communicated to mariners. These communications known as “Notices to Mariners” are issued by national hydrographical authorities, and they announce important changes in the nautical environment. In case of newly installed submarine cables, these are represented by a chart correction Notice to Mariners. It is the responsibility of vessel navigators to subscribe to these Notices issued by the relevant authorities be they the traditional paper charts and recently mandated Electronic Chart Display and Information Systems (ECDIS). It should be noted that there are electronic sea charts on the market which may be less accurate and less up to date than those products authorized by the national hydrographical authorities. However, these will be more likely to be used by smaller vessel operators. The charting of submarine cables is covered under International Hydrographic Organization (IHO) Chart Specifications S4 Edition 4.5.0 published in October 2014, specifically B-443, B-320.6i, and C-408. By disseminating the cable route information to the public domain, on the occasion that the cable is damaged and those responsible known, the cable owner is in a better position to recover financial losses associated with the damage [B5]. Without making the route information public as described there can be no question of “culpable negligence” on the part of the third party as anticipated under Article 113 of the United Nations Law of the Sea convention (UNCLOS) [B5]. UNCLOS is an international legal instrument familiar to most professional seabed users. However, there are a number of other seabed users who are unfamiliar with UNCLOS nor the importance of submarine cables. These same users may be ignorant that their activities pose a significant risk to submarine cables. For example, the level of awareness within coastal recreational and fishing fleets to cable safety and potential damage claims by cable owners can be significantly lower than with professional seabed users. Likewise, these same users might not even be aware that the electronic charts bought from the Internet are not accurate or up to date. Warships and other government ships operated for noncommercial purposes may, due to their general immunities, undertake activities inconsistent with the contemporary practice of professional commercial seabed users. It is therefore recommended that cable owners do not solely rely on Notices to Mariners to inform seabed users as to the locations of cable and associated risks and may wish to consider specific programs for specific sectors.

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Fig. 9.5 Snapshot of cable awareness chart. (Credit: KIS-ORCA)

Fishing risks can be addressed through a number of activities. It can be useful to enroll to a dedicated fishing or marine association. The European program KIS-ORCA (www.kis-orca.eu), the Kingfisher Information Service – Offshore Renewable & Cable Awareness project (KIS-ORCA) is a joint initiative between the European Subsea Cables Association (ESCA), Renewable UK and the Kingfisher Information Service of Seafish and provides up-to-date information to fishermen about the location of submarine cable and renewable energy structures in Europe (Fig. 9.5). Fishermen can be addressed through local fishermen associations. Some fishermen might perceive the presence of the submarine power cable as an obstacle in their fishing grounds. They should be informed that an entanglement of their gear with a cable actually can be very dangerous for them and should thus be avoided. Fishermen should also be made aware that they may be entitled to compensation for gear lost or discarded in the protection of cables depending on jurisdiction and also any penalties may apply for willful damage of submarine cable. Anchoring risks can be limited through a number of techniques. Burial or other forms of mechanical protection are standard practice. If the cable system can be routed such that it is in an area of low vessel activity this can greatly reduce the likelihood of a cable strike and damage. The experience of the local Vessel Traffic Service centers (VTS) should be consulted to find areas of low anchoring risk. If possible, anchoring in the vicinity of the cable should be discouraged. Marine authorities may declare protection zones where certain activities such as anchoring and fishing are prohibited.

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The Automatic Identification System (AIS) is a means to track vessel movement. The International Maritime Organisation (IMO) mandates that every vessel under the SOLAS convention and over 300 tons is obliged to operate an AIS transmitter which transmits the vessel identity, position, direction, and speed as well as other information via the VHF (Very High Frequency) band, in regular short intervals. AIS can also be required for smaller vessels depending on local jurisdiction, such as the requirement from EU that EU fishing vessels exceeding 15 m length need to be equipped with AIS transmitters (Article 10 of EU Council Regulation No 1224/2009). Land-based stations receive the signals and some organizations publish the data on the internet. The VHF system limits the range usually to some 20–30 km from the coastline. There are now some satellite based AIS systems that can monitor vessels far from the coast. It should be noted that many Internet provided AIS maps are updated only with a certain delay and therefore do not reflect the current situation. A number of commercial organizations offer cable system owners a service where the information received via AIS is correlated to the cable route of the cable. Predetermined vessel activities like unexpected slowing-down or changing its status to “at anchor” can be detected and will provide the cable system owner with an automated alert. The cable system owner can then use this information to initiate preemptive mitigation efforts such as engage with the captain via radio contact, the vessel owner, and insurance associations (P&I – Protection & Indemnity Clubs) to move the vessel or report to the relevant authorities if applicable. AIS data can also be evaluated on-line in commercial marine survey centers. Automatic systems seem to be under development that can analyze vessel movements with certain algorithms and decide if there is a perilous situation. Such systems might be improved in the future by artificial intelligence that can learn about normal and abnormal vessel behavior in a given location. AIS can and has been used in cases of damage even when the vessel has “turned off” its transponder. Most if not all commercial AIS software used by submarine cable owners records the data being displayed meaning a disappearing vessel cannot hide. This data may be used as evidence in liability lawsuits. Before the wide introduction of AIS important cable routes were in cases protected by patrol vessels or even patrol aircraft. Another form of remote vessel identification usually limited to national fishing fleets is Vessel Management System (VMS). The access to this information may be limited as it may have commercial value to fishermen. In some jurisdictions, VMS information is only available via an injunction which would likely only be available after a damage event. Seabed mining is an emerging threat to cable owners/operators, while most power cable installations are currently limited to the territorial sea or economic exclusion zone. The experience from the international telecommunication cable industry is that seabed mining claims are becoming more impacting. These claims can cover vast areas and claims are becoming more prolific as the seabed mining industry matures. Seabed users devoted to sand and gravel extraction, dredging or mining, are particularly dangerous for submarine cables and a good cable route selection makes any encounter less likely. Instead, the position of submarine cables should be shared with all involved. Every user of the marine space should be aware of the existence and position of a submarine power cable.

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More information regarding cable awareness and marine liaison can be found in ICPC Recommendation n 6 “Recommended Actions for Effective Cable Protection (Post Installation)” and in Guidelines produced by regional cable protection organizations. Cable Protection Organizations Since submarine cable protection is an objective for many submarine cable stakeholders there are a number of cable protection organizations globally. Submarine cable owners may be member of one or several cable protection organizations. The following list (in alphabetical order) represents all major regional and international cable protection organizations (Table 9.3).

Table 9.3 Cable protection organizations Name Danish Cable Protection Committee

European Subsea Cables Association

International Cable Protection Committee

North American Submarine Cable Association

Oceania Submarine Cable Association

Brief Description Danish Cable Protection Committee (DKCPC) is a forum of companies that owns submarine cable and pipeline owners and operators in Danish territorial waters. The role of DKCPC is to improve the protection of submarine cable and pipeline assets in Danish waters for the benefit and security of supply for the markets they serve. The European Subsea Cables Association (ESCA) is a forum of companies which own, operate, or service submarine cables in European and surrounding waters. The role of ESCA is the promotion of marine safety and the safeguarding of submarine cables from man-made and natural hazards. International Cable Protection Committee (ICPC) is a forum of submarine cable owners and operators, service providers, manufacturers, and governments. The role of the ICPC is to be the international submarine cable authority providing leadership and guidance on issues related to submarine cable security and reliability. North American Submarine Cable Association (NASCA) is a forum of companies which own, operate, install, or maintain submarine telecommunications cables in North American waters. The role of NASCA is to provide and exchange information on technical, legal, and policy issues of common interest with regard to submarine telecommunications cable. Oceania Submarine Cable Association (OSCA) is a forum of companies which own, operate, or service submarine cables in Oceania regional waters. The role of OSCA is to promote and engage with stakeholders in the protection of submarine cables.

Website http://www. dkcpc.dk/

http://www. escaeu.org/

https://www. iscpc.org/

https://www. n-a-s-c-a.org/

http://www. oscagroup. com/

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9.5.1.2 Maintenance Activities to Control Cable Protection and Health The cable owner/operator may set up an inspection plan for the submarine cable asset. The type of inspections and frequency must be adjusted to the local conditions and take into account risk assessments. Depending on the seabed properties and dynamics a submarine survey may be necessary every few years or may never be required. The type and frequency of inspections can also change during the lifetime of the asset. 9.5.1.2.1 Offshore Surveys It is good practice for submarine cable owners to possess exact knowledge of the position of the cable and its environment. The geographical data from the “As-laid” or “As-built” documentation provided by the installation organization at the end of the installation provides a baseline for the management of the cable system. Recommendations for the content of As-laid or As-built records can be found in CIGRE TB 773 (Fault Location on Land and Submarine Links) and ICPC Recommendation N 10 (Minimum Requirements for Load and Lay Reporting and Charting). For marine geographical data, it is of paramount importance to define an unambiguous positioning framework for traceability and to allow comparison of different set of data acquired at different occasions. For example, the International Association of Oil&Gas Producers (IOGP) maintains Geodetic Parameter Datasets referred as the EPSG code (www.epsg.org). The most common geodetic reference system used is WGS 84 which is also basis for Global Positioning System (GPS) navigation. The projection system must also be defined, such as the universal transverse mercator (UTM). Finally, a vertical datum must be chosen, such as the lowest astronomical tide (LAT) or mean sea level (MSL). Various countries may apply differently or derived geodetic systems and vertical data so it is advisable to follow the recommendations of the national hydrographic authorities. The as-laid documentation provides a geodetic representation of the cable location with respected to the two (or three) dimensional representation of cable route. The as-laid documentation may not precisely represent the location of the cable due to measurement errors at installation. The true position of the cable might deviate from the recorded position of the cable laying vessel, especially in deep waters or where the lay tension has not been competently managed by the installation provider. There are several techniques that can minimize these accuracy issues at installation; however, they are outside of the terms of this technical brochure. Over time, submarine cables can change their position relative to the as-laid information. Events such as water currents, sediment movements, heavy storms, earthquakes, landslides, or any combination can impact on the bathymetry and seabed morphology. Depending on local soil conditions and seabed formations some regions are more prone to these events and resulting changes in cable position. Changes in seabed morphology can change the depth of burial of an installed cable. This change can be significant, in some cases up to several meters. Another cause of seabed movement is known as giant sand waves (Fig. 9.6). These have the effect burying parts of the cable deeper while exposing others, potentially up to free hanging. Cases of both self-burial and deburial of submarine cables are known. For the purposes of submarine cable maintenance and operation, the depth of burial and seabed

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Fig. 9.6 Image obtained from a bathymetric survey showing sand waves

morphology should be reasonably understood for a particular installation. For example, a cable shallower than intended may reduce the physical protection level while a deeper than intended cable might impair the thermal rating. If not already required from permits or from the local authorities, it is advisable that cable system owners maintain up-to-date cable system records, charts, etc., to a reasonable level of accuracy taking into account the dynamics and properties of the seabed. It should be noted that in area of high dynamics the surveys are to be carried out more frequently, as seems reasonably practical, comparing to the areas of low or no seabed dynamics. As highlighted at the beginning of this section, the type of inspections and frequency must be adjusted to the local conditions and take into account risk assessments. Irrespective of periodic surveys, it is advisable that surveys and inspections are undertaken in the case of specific events such as earthquakes, major storm events, and the like. Such a survey is an appropriate response to events that might have changed the cable position or protection level. Depth of burial can be measured using a cable tracker which can be mounted on a Remotely Operated Vehicle (ROV) or held by a diver. Cable trackers are based either on magnetic field measurements, acoustic waves, or a combination of those in order to determine its relative location of the cable. For magneticbased cable trackers, a tone may be applied at one of the cable ends or depending on the tracking system, it may be induced by the tracker itself. Performance in measuring cable position and accuracy for depth of measurement depends a lot on the type of cable, its distance to the cable tracker, type of soil, cable on-line or off-line, etc. If the cable position deviates from its previous position, this should be updated with the relevant national hydrographical authorities as described in Sect. 9.5.1.1 for the effect described in the same section. If the burial depth or external protection level is found different from anticipated values the cable owner/operator may decide to take remedial measure to the thermal conditions and/or physical protection level of the cable. Dredging or mass-flow excavation can remove covering soil if necessary. Remedial protection works are described in Sect. 9.5.1.3. Additional information on marine survey methods is provided in CIGRE Technical Brochure 610 (Offshore Generation Cable Connections, Feb. 2015). 9.5.1.2.2 Landfall Inspection The landfall portions of a submarine cable deserve some extra attention. The cable route is changing from the relative uniformity of the seabed through tidal flats, a sandy or rocky beach, splash zone, cliffs, and other obstacles. Whether cables are installed in

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Fig. 9.7 Cable exposure at landfall. (Credit: www. aphotomarine.com)

HDD, buried pipes, directly buried, clamped, externally protected, or surface laid, it is advisable to schedule visual inspections and topography measurements of the landfall zones in order to detect changes such as soil movements, exposure of cable or protection pipe, unexpected construction work, damage to any clamp or external protection, and cable damage. For long landfalls, drones may be considered to fly the entire landfall portion and indicate if a closer inspection is necessary. Each inspection should be documented to establish a base for comparison in the future (Fig. 9.7). 9.5.1.2.3 Cable System Inspection on Platforms Cable installations on offshore platforms (including offshore wind turbines) have some sensitive parts where the cable is exposed: • • • •

Scour zone J-tube bellmouth, centralizer, and plug Hang-off (Fig. 9.8) Topside transition joint

Fig. 9.8 Hang-off and cables on an offshore platform

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• Topside cable, clamps, glands, and sealings • Cable termination • Link boxes, optical fiber boxes, grounding arrangements The subsea portions (scour zone, J-tube bellmouth) should be inspected by ROV or divers since changes/damages in this area can result in expensive outage time and repair if not counteracted in time. As an example: Erosion of the scour protection can result in a free-span of the cable and subsequent vibration-induced damages to lead sheath or metallic wires. Checking for marine growth inside the J-tube may also be considered. Components over the water level should be visually inspected regularly regarding corrosion, mechanical damages, brittleness, loose parts, leakage, etc. Thermography and testing of cable sheath and earthing as well as thermography of accessories may also be considered. Cable on topside should be inspected for presence of bird feces (to be cleaned) and status of fire-resistant coatings (if any). Dynamic Cables to Floating Structures Loss of buoyancy over time, due to material aging of cables and buoyancy modules, as well as environmental effects such as marine growth, may ultimately lead to cable impacting the seabed and damaging the cable. Consequently, it is advisable to plan regular measurements of cable and buoyancy modules position, as well as the extent of marine growth. In case marine growth exceeds the design assumptions, cleaning may have to be considered. The tools to be used must be proven safe with regard to the dynamic cable sheath, and with regard to buoyancy modules and other ancillary equipment. The type of tool to be used may depend on the type of marine species encountered (soft marine growth versus hard marine growth). 9.5.1.2.4 Measurements and Monitoring with Fiber Optics Submarine power cables are nowadays generally equipped with integrated fiber optic cables or installed in bundle with a fiber optic cable. The use of fiber optic based measurements and monitoring systems are increasingly being used on submarine power cable systems for detection and localization of potential: • Hotspots by distributed temperature measurements • De-buried sections by distributed temperature measurement and/or acoustic measurements • Mechanical stress by distributed strain measurements • Mechanical damage or fault on the power cable by recording deterioration of OTDR traces • Fault pinpointing by recording distributed acoustic or vibration measurements, etc. For more detail, see Sect. 9.7, Monitoring and diagnostics.

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9.5.1.3 Maintenance Activities on Submarine Mechanical Protections Submarine cables have wire armor which primarily works to take tension during installation in water or on laying vessel but also work as an external protection. However, additional mechanical protection of submarine cable against third party or environmental aggression is often provided by burial into the seabed, and sometimes by means of external protection (rock placement, iron shells, concrete mattresses, etc.). Cables may also be left unprotected on the seabed, provided that there is a very low risk from external aggressions, for instance at great water depth or areas with low fishing and navigation activity. In a case of seabed movement resulting in exposing free-spanned cable, an assessment for VIV (vortex-induced vibration) shall be carried out to prevent fatigue and breakdown, and the design of wire armor and the cable weight would be an essential part of the stability study. In that case, stabilization of cables (anchorage, grout bags, concrete mattress) may be required, in order to avoid abrasion and fatigue due to cables movements from hydrodynamic forces. Reasons to consider additional or remedial protection works may be linked to: • Installation works that were unable to reach initial target burial depth – although this should normally be solved during the project phase • Changes in burial depths, or ultimately cable exposures and free spans from sediment mobility, discovered after a survey or from DAS/DTS measurements • High failure rate observed from external damages, showing that cable is insufficiently protected or stabilized • Changes in external risk exposure, such an increase of anchor risks or fishing techniques having contact with the seabed Remedial protection works may also have to be carried out because of a formal obligation (e.g., insurances, authorities) or for safety reasons (e.g. risk for fishing). Otherwise, it is recommended to take a decision regarding potential remedial protections after a complete risk-cost-benefit assessment of: • Risks associated with performance of remedial works (e.g., risk of damaging the cable) • Costs of remedial works • Expected benefit over the remaining lifetime of the cable (e.g., lower failure rate) The main risk associated with these operations is to damage the cable. This risk remains low when remedial actions are carefully designed and performed according to industry best practices. Costs of such operation may very well depend on the techniques chosen, level of protection, soil, and weather conditions. Moreover, some tools or techniques require to work offline for safety reasons, or for cable integrity (e.g., risk of increasing electrical stresses in the insulation of a DC cable when increasing the temperature gradient by water forced convection). In such a case, commercial losses during operations may also need to be considered.

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Table 9.4 Comparison of most used protection techniques Type of protection technique Post-Lay Jetting

Post-Lay Trenching

Rock Placement Concrete Mattresses and Grout Bags Iron Shells

Situations where it is generally most suited Fine and soft soils (e.g., sands, low strength clays) Generally limited to straight route segments

Relatively hard soils (e.g., hard strength clay) Generally limited to straight route segments All type of soil except where there is a risk or erosion and rock sinkage over time All type of soil except where there is a risk of erosion and rock sinkage over time All type of soil Noting that it would generally need to involve divers since there is generally not enough slack to bring the cable on a vessel deck

Possibility to be applied when the cable is in service Generally possible, although the tool may touch the cable Potential power limitations to be assessed with DC insulated cables due to sensitivity of temperature gradient over insulation Generally possible, although the tool may touch the cable

Yes

Yes

Unlikely

The expected benefit of performing remedial protection works can be assessed, considering: • Comparison of risk of cable damage before remedial works and after remedial works • Financial damage of potential failures (cost of repair + commercial losses) • How long the remedial protection works may last • How fault location and cable retrieval may become more difficult in case of an internal fault • Reduction of insurance rates A brief comparison of the most used techniques is presented in Table 9.4.

9.5.2

Corrective Maintenance on Submarine Cable Systems

Logically a cable repair is required for a compromised cable such that it is unable to safely transfer energy. Depending on the cable system, its configuration, its environment, and the location of the fault, the procedures and means for repair can greatly vary. This

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section gives a typical list of operations to perform for a cable failure in the open sea, but it is advisable that cable owners have their own procedures for various possible scenarios integrated into a Repair Preparedness Plan (Sect. 9.8.2).

9.5.2.1 Immediate Actions After Fault Occurrence Operators will receive alarms and/or protection apparatus may indicate a compromised cable. At this stage, it is advisable as the first step of any plan that the fault indication is confirmed to be “real” and not the result of a false activation. It is also advisable for the operator to consult any tools they may use for fault situation like fault data recorders, AIS and the like. In the cases of facilities comprising an overhead and underground configuration, physical inspection may be warranted. After the fault is confirmed to be a real, pre-location should occur promptly (as a rough estimation this might be done analyzing the cable operators line protection system) and should provide the cable owner with an understanding if the fault is on the land or sea section of the cable and an indicative fault location from the point of testing and pinpointing of the fault can be done. For fault location, please refer to CIGRE TB 773 “Fault Location on Land and Submarine links.”

9.5.2.2 Preparation of Repair Works Further to pinpointing of the fault, availability of jointing personnel and equipment shall be assessed, followed by commence preparation of spare cable transport logistics as well as stored equipment and materials, which among others may include: • • • • •

Spare joint kits and end caps Fiber Optic cable (if applicable as separate item) Weather forecasts from local weather forecast institute Progress charter of vessel and operation – specific engineering Order diving assistance if required

Once this is established, the following items should be discussed together by the client and repair contractor(s) (unless a suitable turnkey fault response contract exists with the cable manufacturer): • Obtaining necessary permits to undertake cable repair. • Survey of the suspected fault area and the wider surrounding, taking into account any anomalies (scaring, UXO, etc.). • Any further fault location pinpointing, if required (refer to CIGRE TB 773). • UXO clearance, if required. • Acquire vessel(s) plausible for necessary cable repair works. • Ascertain most compatible equipment to de-bury the cable and protect the cable bight.

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• Proximity to third-party crossings: if the repair works are planned in the proximity of a crossing, notice of the intended operations shall be provided to the service owner in accordance with the relevant Crossing Agreement. • An induced voltage assessment prior to commencement cable repair or re-jointing works. Adequate safe procedures mitigating risks associated with working under impressed voltages shall be in accordance with TB 801 (“Guidelines for safe work on cable systems under induced voltages or currents”).

9.5.2.3 Mobilization of Resources for Repair Works The following mobilization tasks should be carried out in advance of carrying out marine cable repairs or replacements: • Mobilize offshore staff. • Load equipment and materials onboard the cable repair respectively support vessels (for details, refer to Table 9.5). • Monitor weather forecasts to identify suitable weather windows. • Make necessary preparations according to process instruction for cable repair splice.

Table 9.5 Typical items mobilized for a submarine cable repair operation Item Cable repair vessel or barge. This can be a cable laying vessel (CLV) or a vessel of opportunity (VOO) mobilized for cable repair, depending on availability Cable repair spread. The cable repair spread typically includes:
Turntable or cable basket (the latter for coilable cables only or with additional external drive unit)
Cable pick-up system
Tensioner(s)
Chute(s)
Cable repair facilities (jointing container or similar) Diver spread (if required) Cable de-burial/rock removal and jetting spread ROV(s) Navigation and positioning services Radio communication equipment Spare cable, repair joints, end sealing kits, and other cable-specific spares, equipment, and tools Repair manual including process instruction for completing the repair joints On-deck cable cutters for emergency cutting during jointing Subsea cable cutters and clamps for cutting and retrieval of cable An appropriate tool for on-deck cable handling and laydown of repaired cable and joints (spreader bar, quadrant, cable bow, etc.) Cable rigging equipment (towing sock, yale grip, etc.) Cable guard or support vessel

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Fig. 9.9 Vessel under mobilization for a cable repair

Typical items mobilized for a submarine cable repair operation are shown in Table 9.5: The cable repair vessel, cable repair spread, and specialized personnel are subject to availability and the offshore market conditions at that time. Having contractual arrangements, when possible, can help to secure the lead times of those critical items and personnel (Fig. 9.9).

9.5.2.4 Repair Works In case the cable is buried, cable de-burial either side of the fault should consider the water depth as well as the cable burial characteristics in that area. Generally, the cable should be excavated a minimum of two-three times water depth to ensure enough cable is exposed to enable both ends to be brought onto the vessel for jointing operations. This can vary depending on accuracy of the fault location and expected longitudinal water penetration. De-burial operations will be slower and more difficult in areas of rock placement or stiff soils. If the cable is in an area protected by concrete mattresses or rock berm, additional equipment will be required to clear the protection (for short sections and if permitted it may be more economical to abandon and bypass the damaged section under the rock/mattresses). Following de-burial/rock removal of the cable, the following steps normally occur: • Visual survey of suspected fault location. This is typically carried out with an ROV flying over along the suspected damaged section to check for any obvious sign of the cable fault. In shallow water depths this may be performed by divers. It is highly unlikely a positive fault identification will be made at this stage unless the damage is from an external source, but it is still prudent to carry this exercise out.

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• Cutting the cable in the vicinity of a suspected fault location and, if applicable, configure the cable at seabed for later hair-pin lay down. The cable is normally cut with a diamond cutter or a guillotine cutter. • In case of repair operations in SCFF cables, the pumping station shall be parameterized with the needed values to enable a proper manipulation of the cables (ref. CIGRE TB 801). • Clamps or any suitable cable rigging equipment is installed on both cable ends by use of an ROV and winches/cranes, respectively supported by divers (see Fig. 9.10). • The first cable end to be recovered should be the presumed “healthy end.” After recovering it to the vessels deck, the cable is secured, prepared, and confirmed to be free of any further damage. • Cutting back the cable until the cables insulation system is free of water penetration traces. • After the cable is found to be “healthy and dry,” it is sealed off and recovery rigging is installed, possibly with a transponder on the cable end. • Lay down the intact and sealed cable onto the seabed. • Retrieve the suspected damaged side of the cable onto the vessel and pick it up moving astern until the damaged part of the cable is expected to be on-board the vessel. The “damaged” cable is recovered with the already installed clamp/ rigging equipment. It is recovered to deck, secured, and the testing is performed to confirm the fault. This testing should indicate how much cable should be removed to get beyond the fault to a cable section with full integrity and absence of water penetration.

Fig. 9.10 Example of recovery rigging

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• If applicable, the cable is then pulled further on board before making an additional cut. After final confirmation the cable is found “healthy and dry,” it can be either sealed off with recovery rigging installed and put back to seabed for later jointing operations or directly prepared for the first jointing. • Perform a jointing operation with the retrieved cable. Normally, the type of jointing will depend on water depth, which may require different techniques, like inline jointing for shallower repair and Omega-type joint for deeper repair. In the case of DP vessel, the jointing of the first joint is performed while the vessel is staying on DP with the bow or stern against the current and wind. A constant monitoring of the angle in the cable chute, tension, and touchdown during jointing operation should be in place to prevent excess loading of the cable. • Re-layoff cable: After the successful first joint, the cable is laid toward the first end according to normal laying procedures. It is advisable that an ROV is used during this laying operation to monitor the touchdown point. The other end (that was previously capped and sealed) is recovered to deck and the second joint is performed. • Lift the undamaged side of the cable onto the vessel and perform a repair joint and lay down the cable. • Final Laydown: After the jointing operation, the cable bow with the cable is lowered to the seabed using a set of crane and winches. The ROV releases the cable from the bow and the bow is recovered. A survey of the laydown area (video survey) is performed with the ROV. • Re-burial of cable and joints to ensure adequate cable protection. • Testing: an electrical test of the cable to be performed from the local onshore substation (at least a soak test) before loading the cable is recommended (refer to CIGRE TB 490, TB 496, TB 728). • Final survey and update of cable system records.

9.6

Fluid Filled Cable Systems

As fluid filled cables are not the topic of this chapter, the part of TB 825 dedicated to Fluid Filled cables is not reproduced here.

9.7

Monitoring and Diagnostics

9.7.1

Introduction

The purpose of this section is to provide the reader with an overview of diagnostic and monitoring methods for maintenance of high voltage cables. Throughout this brochure: a diagnostic technique is one that helps identify the presence, nature, and/or cause of a problem within the cable system, typically without specifying how the problem originated; a monitoring technique is intended as a continuous supervision activity carried out by specialized equipment to keep track of specific (critical) parameters during the operation of the asset.

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Various techniques are presented in the form of a table while more details are presented in subsequent sections. CIGRE members worldwide have responded to some open questions in the questionnaire related to the most effective maintenance and diagnostic methods to ensure the availability and determine the condition of the cable system. The main conclusions drawn from the analysis of the responses are summarized below.

9.7.1.1 Effective Maintenance Actions to Ensure Availability of a Cable System The questionnaire raised the following question: What are the five most effective maintenance actions that you perform to ensure the availability of your cable system? Out of the 74 users, 66 have responded to the question regarding the most effective maintenance actions that you perform to ensure the availability of the cable system. While eight did not give an answer. The responses have been grouped in categories and presented in Table 9.6 below. The percentages refer to the 66 users that have responded to the question. Interestingly, 4 of the 66 respondents (6%) stated that at the moment they are not performing any specific actions for ensuring the availability of their systems. A significant amount of users, 29% of the respondents, has selected online maintenance activities to increase the availability of their network. This likely applies to the most critical assets. The majority of the respondents, 57 of the 66 (86%), perform periodic visual inspections and surveys of their equipment. Of the 57, 28 include checks on the hydraulic system of fluid filled components, oil pressure readings, pressure gauge, and alarm checks. Periodic route patrols are carried out by 20 respondents as part of the visual inspection protocols. Six of the respondents that perform visual inspections have indicated that a check of the cathodic protection system is included in Table 9.6 Overview of most effective maintenance actions Maintenance actions ensuring availability of the Cable System Visual inspections and surveys Checks on earthing and bonding system, outer sheath test, screen currents On-line monitoring methods (temperature, PD, etc.) Temperature measurements (distributed/ spot) Oil analysis fluid filled cable and/or accessories Registration system, making aware third parties of cable routes for preventing potential digging related failures Partial discharge measurements on-line (circuit energized)/off-line (circuit not energized) Condition-based maintenance, repair, or replacement Diagnostic tests on cable insulation deterioration No actions taken Spare part management and emergency planning

Users 57 24 19 17 13 10

(%) 86% 36% 29% 26% 20% 15%

9

14%

5 5 4 3

8% 8% 6% 5%

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their program. Additional inspection of the clamping system is included by six of the respondents that perform visual inspections. Three of them perform a check and clean the components in termination pits, link boxes, etc., when necessary. Checks and possibly testing of earthing and bonding systems are conducted by 24 respondents (36%). Only four of these respondents also check the status of the SVLs, and two perform a measurement of the screen currents. According to 17 respondents (26%), measurement or monitoring of the temperature (DTS or spot thermography) is an effective means to ensure the availability of connections. Oil analysis from fluid-filled cables and components is an effective measure to ensure availability for 13 out of the 66 respondents (20%). Here it should be noted that not all 66 respondents are owners of fluid-filled cable systems. According to 10 of the 66 respondents (15-%), another effective method to avoid failure related to excavation works is to have a registration system making aware third parties of existing cable routes. Periodic spot PD measurements or continuous PD monitoring is considered as an action to ensure availability of the cable system for 9 out of 66 responses (14%). Three of these nine combine a PD measurement with a HV voltage test on the main insulation. Based on the responses other effective methods for ensuring system availability are preventive maintenance, repair, or replacement based on condition of the components (8%), periodic diagnostic measurements on cable insulation (9%), and spare part management and emergency preparedness in order to reduce the outage time as much as possible (5%).

9.7.1.2 Effective Measurements to Determine Condition of a Cable System The questionnaire raised the following question: What are the three most effective measurements you perform that determines the condition of your cable system? Out of the 74 users, 66 have responded to the question regarding the most effective measurements for the determination of the condition of a Cable System. While eight did not give an answer. The responses have been grouped and presented in Table 9.7. The percentages refer to the 66 users that have responded to the question: • Of the 66 respondents, 15 (23%) stated that at the moment they are not performing any specific measurements for the determination of the condition. Two of these 15 monitor the condition of their systems by observing the historical performance of the systems. • Twenty-three of the respondents of the 66 respondents (35%) perform oil analysis on samples from fluid-filled cables and accessories. Three of these 22 also perform an impregnation coefficient measurement. • Twenty-one respondents (32%) perform tests on the sheath insulation system, such as sheath voltage tests and checks on the bonding system of the cables. Three of these 20 also perform measurements or monitoring of the screen currents.

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Table 9.7 Most effective measurements that determine the condition of the cable system Condition determination measurements Oil analysis fluid filled cable and/or accessories Checks on earthing and bonding system, serving test, screen currents On-line monitoring methods (temperature, PD, etc.) Partial discharge monitoring/spot measurement No measurements taken Temperature measurements (distributed/ spot) Oil pressure and oil volume monitoring and readings Visual inspections and surveys Tan delta measurement Time domain reflectometry and/or Frequency domain reflectometry Depth of burial X-rays test Water treeing occurrence test Laboratory tests on cable sample; condition assessment

Users 23 21 16 15 15 14 10 10 8 5 2 2 2 1

(%) 35% 32% 24% 23% 23% 21% 15% 15% 12% 8% 3% 3% 3% 2%

• For 15 respondents (23%), an effective diagnostic for the condition assessment of a cable system is PD measurement or monitoring on cable and/or accessories. Four of these 15 combine a PD measurement with a HV voltage test on the main insulation. • According to 14 respondents (21%), measurement or monitoring of the temperature (DTS or spot thermography) is an effective diagnostic method for the assessment of the asset condition. Seven of these 14 have chosen a distributed temperature sensing system while seven of the 14 perform spot temperature measurements with thermography or using thermocouples. Based on the responses other effective diagnostic methods are oil pressure and oil volume monitoring or measurements (15%); visual inspections (15%); tan delta measurement of the main insulation (12%); time domain reflectometry (TDR) or line resonance analysis (FDR) (8%); depth of Burial for sub-sea cables (3%); X-rays of accessories (3%); and water treeing occurrence measurements (3%). One of the 66 respondents performs a full condition assessment test program on cable samples that become available (i.e., after a repair) in the laboratory. Among the 66 respondents, 16 (24%) perform one or more on-line monitoring activities. On-line temperature monitoring is carried out by six of these 16 (38%). On-line oil pressure of cables and/or accessories is performed by six of them (38%). On-line PD monitoring is carried out by four of the 16 (25%). Two of the 16 (13%) monitor the burial depth of sub-sea cables and two (13%) do not specify the type of other on-line monitoring activities that they perform.

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Overview of Different Techniques

Table 9.8 provides an overview of the diagnostic techniques applicable to high voltage cable systems. The table differentiates between AC and DC systems, between land and submarine applications, as well as among insulation material types. As some diagnostic techniques consist of measuring parameters which can also be continuously monitored, these techniques belong to both the diagnostic and monitoring categories.

9.7.3

Description of the Methods

9.7.3.1 AC or DC Voltage Test These tests are performed mostly as after-installation (commissioning) tests (IEC 60141, IEC 60840, IEC 62067, CIGRE TB 490, CIGRE TB 496, IEEE 400.1), with the purpose of exposing defects that could cause premature failure (breakdown) in the main insulation, especially as a consequence of poor workmanship on joints and terminations assembled on site. The likelihood of having such a defect progress to breakdown during the test depends heavily on testing time and testing voltage. The higher the test voltage, the higher the probability of insulation breakdown during the test. In this sense, this test acts as a screening process for insulation defects, which in turn decreases the probability of a premature failure in service. The AC voltage test is also used as a maintenance test. In such case, however, the applied voltage level is typically lower than that applied during commissioning (IEC 60141, CIGRE TB 758, CIGRE TB 680). The purpose of the high voltage test as maintenance test is to expose defects that may have developed during service. It is widely known in the industry that the application of AC voltages on XLPE insulation systems shall be avoided when that same insulation has previously been exposed to high DC voltages. This also applies to DC XLPE insulation materials. This implies that AC voltage tests shall be avoided for quality assurance of DC cables after DC tests have been carried out, or after they have been put in service, as that may lead to deterioration, or worse, breakdown of sound cable insulation. Similarly, the application of high DC voltages on XLPE insulation intended for the use in AC systems shall be avoided. In general, a DC test is usually less expensive than an AC test. Both require similar preparations (outage on the circuit, safety precautions) but the equipment used differs significantly. The common factors influencing the cost of both tests are: • Cost of the outage (labor, planning, loss of revenue, etc.) • Test location – equipment mobilization and shipping costs rise considerably when the test is to be performed in remote locations, or congested areas with difficult access • Length of the cable – it has a direct impact on the required equipment and generator power (for AC tests) and on the discharge energy capability (for DC tests)

Diagnostic technique AC Voltage Test on Main Insulation PD Measurement (online, offline, monitoring) DC Voltage Test on Main Insulation DC insulation resistance measurement Dissipation Factor Measurement (Tan Delta) Dielectric Spectroscopy DC Voltage Test on Oversheath Bonding Performance (Sheath current/ voltage)

L1-L6

L1-L6

L1-L4

L1

L1-L3

L2

L1-L2

L2

D

M/D

D

D

D

D

D

M/D

X

–

X

X

X

X

–

X

X

X

– X

X

X

X

X

X

X

X

X

X

SCFF/ XLPE PILC HPFF X X X

Monitoring/ Cost level diagnostic (Sect. 9.9.3) AC Land

Table 9.8 Overview of diagnostic techniques

X

X

X

X

X

X

X

X –

–

X

X

X

X

X

X

–

–

X

–

X

Submarine/subsea SCFF/ GP XLPE HPFF X X X

–

X

–

–

X

–

X

X

X

X

X

–

–

X

MIND –

XLPE –

DC Land

–

X

X

X

X

X

–

SCFF/ HPFF X

–

X

–

–

X

X

–

XLPE –

–

X

X

X

X

X

–

–

X

X

X

X

X

–

SCFF/ HPFF –

Maintenance and Remaining Life (continued)

MIND –

Submarine/subsea

9 625

Diagnostic technique Sheath Voltage Limiters (SVL) Test Earthing Resistance Measurement Loop and Contact Resistance Measurement DC Conductor Resistance Measurement Capacitance Measurement Sequence Impedance Measurement Inspection of Manometers and Plumbing

L1

L1-L2

L1

L1

L1

L1-L2

L1

M/D

D

D

D

D

D

M/D

X

–

–

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

SCFF/ XLPE PILC HPFF X X X

Monitoring/ Cost level diagnostic (Sect. 9.9.3) AC Land

Table 9.8 (continued)

X

X

X

X

X

X

–

X

X

X

X

X

X

X

X

X

X

X

Submarine/subsea SCFF/ GP XLPE HPFF X – –

–

–

– –

X

X

X

X

MIND –

X

X

X

X

XLPE –

DC Land

X

–

X

X

X

X

SCFF/ HPFF

–

–

X

X

X

X

XLPE –

–

–

X

X

X

X

MIND –

Submarine/subsea

X

–

X

X

X

X

SCFF/ HPFF

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Oil Leak Detection and Localization Oil Analysis Dissipation Factor Measurement (Tan Delta, DC insulation resistance, DGA, Breakdown Voltage Test, Moisture Content) Infrared Temperature Measurement Localized Temperature Measurement Distributed Temperature Sensing/ Measurement (DTS) Time Domain Reflectometry (TDR) Frequency Domain Reflectometry (FDR)

L2 for PFT

L1-L2

L1

L1-L2

L2-L4

L1

L1

M/D

D

M/D

M/D

M

D

D

X

X

X

X

X

X

X

X

X

–

–

X

–

–

X

X

X

X

X

X

X

X

X

X

X

X

–

–

X

–

X

X

X

X

X

–

–

X

X

X

–

–

X

X

X

X

X

–

–

X

X

X

X

X

–

–

X

X

X

X

X

X

X

X

X

X

–

–

–

–

X

X

X

–

–

–

–

(continued)

X

X

X

–

–

X

X

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Diagnostic technique Cathodic Protection Performance Oil/Gas Pressure Distributed Acoustic Sensing (DAS) Cable Bathymetric Survey Impregnation Coefficient

L1-L2

L2-L4

L2-L5

L1

M/D

M M

M/D

D

– X –

X

X –

SCFF/ XLPE PILC HPFF X X X

Monitoring/ Cost level diagnostic (Sect. 9.9.3) AC Land

Table 9.8 (continued)

X –

X

– X

X

X

X –

Submarine/subsea SCFF/ GP XLPE HPFF X – X – X

XLPE –

DC Land

– X

MIND X

–

SCFF/ HPFF X

X

– X

XLPE –

X

– X

MIND X

Submarine/subsea

–

SCFF/ HPFF X

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Fig. 9.11 Test setup for long AC 400 kV cable

In addition to all the above, the cost of the AC test is heavily dependent on the type of insulation under test, due to differences in the dissipation factor among the insulation materials. For example, EPR insulation has relatively high dissipation factor, which may result in the need for more powerful equipment to energize the cable to the desired voltage as compared to XLPE insulation (all else being equal). All the aforementioned considerations result in large differences in the cost of the test. An example of a test setup required for testing long AC 400 kV cables is presented in Fig. 9.11.

9.7.3.2 PD Measurement Measurement of partial discharge (PD) allows for detection of latent localized defects in the insulation. Gross defects may also be detected, which allows the test to be stopped before an insulation breakdown occurs. Only certain types of defects can be detected, namely those that result in PD. These typically consist of (gaseous) voids or contaminants within the bulk of the insulation, as well as interface defects, typically caused by workmanship issues. As PD signals are very high frequency pulses, they are subject to significant attenuation when propagating along the cable. When cable systems also present discontinuities in their characteristic impedance, for example, joints, the original PD signal is further distorted during its propagation. This means that, in general, the closer the PD sensors are to the PD source, the more effectively the signals can be measured. For the purpose of conducting a thorough PD measurement on long, multi-jointed cables, it is thus crucial to measure PD locally on all accessories (joints and sealing ends/terminations). This practice not only distributes the measurement system in a uniform way along the cable, but it also provides an effective measurement of PD on the cable-accessories interfaces, which are the most frequent points of failure. Fluid filled insulation (including PILC and MIND) is more resistant to PD activity than XLPE. For fluid filled, MIND, and PILC insulation, higher levels of PD are allowable for an extended period of time. For this reason, the assessment of on-line PD measurement on fluid filled cables is based on trending rather than just detection and localization. If there is significant PD increase over time, then this is a sign of defect deterioration and some further actions may be required.

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The application of PD measurement on submarine links, as well as on land cables where the distance between accessories is large (more than a few kilometers), is limited due to PD attenuation and dispersion. Due to their very low repetition rate under DC applied voltage, partial discharges are not as critical a phenomenon as under AC voltage. For the same reason, the measurement of PD during DC voltage tests is a topic that is still being researched. There are, in general, three different ways of adopting PD measurement techniques, which are associated with the degree of monitoring one wish to achieve: • PD measurement during after installation (commissioning) test – in this case, PD is measured during the commissioning test of the cable system at elevated voltage (above rated voltage), which typically lasts at least 1 hour. Here, while the tests provide an effective screening of major defects in the main insulation and accessories interfaces, the measurement of PD can take advantage of the increased electrical stress within the insulation to reveal minor defects which would be likely to cause a failure during operation. • Spot maintenance PD measurement – this measurement, normally conducted on specific accessories during operation (online) or during an outage (offline), can be either periodical or occasional, for example, following a major event which is suspected to have negatively affected the integrity of the cable system or a repair. If performed periodically, one wishes to analyze the acquired measurements to identify trends on the PD amplitude, repetition rate, extinction and inception voltage (last two only off-line). Trending is especially important for fluid filled, PILC, and MIND cables where PD may be present at operating voltage for long time. This can give valuable information on the ongoing degradation of the asset. • Online PD monitoring – this is a continuous monitoring of PD during operation via permanently installed PD sensors and monitors. Other than being able to spot trends in the PD signals, it is possible via online PD monitoring to receive real time alarms whenever the measured PD exceeds predetermined parameters, or whenever critical patterns are identified. This is nowadays made possible by advanced algorithms and more powerful data processing units. The popular, easily accessible cloud technologies of nowadays, allow the application of machine learning techniques on large data sets, which are expected to make pattern recognition increasingly reliable in the future. Finally, the postprocessing of the data acquired prior to a failure can be useful for a rapid fault location. From the cost perspective, the first may be the least expensive if combined with the high voltage test unless it is performed by a different crew, then it would be similar to the second option “spot maintenance PD measurement.” The last option, online PD monitoring requires the biggest initial investment plus later costs of interpretation and maintenance. For more details on PD measurement refer to CIGRE TB 728, CIGRE TB 297, CIGRE TB 182, and CIGRE TB 680.

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9.7.3.3 DC Insulation Resistance Measurement The insulation resistance measurement was historically considered a diagnostic test for paper insulated cables but for XLPE cables it is not a good method due to very high resistance of the insulation. It is also a method commonly used after repair as a first rough check of the insulation. The results of the DC insulation resistance measurement should be considered very carefully because they depend on the cleanliness of the sealing ends (terminations), humidity, and temperature of the cable and the air. The dependence of so many external factors makes this method unreliable. The insulation resistance measurement itself is a relatively simple test where DC voltage is applied between the main conductor and cable shield. The voltage may vary between a few hundred volts and a few kilovolts depending on the cable characteristics. At lower voltage, the measurement may not be accurate on certain types and lengths of cables. 9.7.3.4 Dissipation Factor Measurement (Tan Delta) and Dielectric Spectroscopy (DS) Dissipation factor or tan delta (TD) measurement is performed to assess the condition of bulk insulation (IEC 60141). This measurement is generally insensitive to localized defects unless the cable is extremely short, and the defect is fairly large. Dielectric spectroscopy (DS) is similar to TD measurement but it is performed for various frequencies ranging from 0.001 Hz to 1 kHz, hence TD measurement is a subset of DS. The result of DS is a curve that allows for the assessment of aging and moisture content in the insulation. Recovery-voltage tests that record the voltage on the insulation after various durations of reduced-voltage DC pulses followed by insulation shorting are intended to provide similar results to dielectric spectroscopy. Dissipation factor (TD) plays an important role in AC insulation where its increasing value may be a symptom of degraded insulation or moisture ingress. Under DC voltage there is leakage current which corresponds to the non-zero conductivity (limited resistivity) of the insulation. This, however, does not directly relate to the AC dissipation factor value. Since the TD measurement on XLPE cables requires application of high voltage AC, it is not recommended (Sect. 9.7.3.1) on HVDC XLPE cables if they were subject to HVDC voltage. TD measurement on oil filled cables, including MIND insulation, may not require application of high voltage and it may be part of the diagnostic procedure. In particular, dielectric spectroscopy may provide valuable information about the condition of the insulation like aging or moisture content. Cable insulation can be modeled by a resistance R(ω) in parallel with a capacitor C(ω) shown below, where R(ω) represents the loss part of the dielectric and C(ω) describes the lumped-circuit capacitance of the cable. When the voltage V is applied to a cable, the total current I in the cable is the vector sum of the leakage current Il and the charging current Ic. The phasor relationship between the currents is shown in Fig. 9.12.

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Fig. 9.12 Phasor relationship between the currents

Fig. 9.13 Example of DS on 138 kV cables

I ¼ I l þ I c ¼ V ðGðωÞ þ jωC ðωÞÞ

ð9:1Þ

An example of DS on 138 kV SCFF cables is presented in Fig. 9.13.

9.7.3.5 DC Voltage Test on Oversheath The purpose of this test is to ensure that the cable oversheath is intact. The oversheath not only provides mechanical protection to the cable from the

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environment but also provides touch voltage protection to the people and requires the operation of the sheath voltage limiters (SVLs) in case of installations where the cable screen is not directly bonded to earth (single-point bonded and cross-bonded systems). Because of this, the test voltage should provide certain confidence level that the oversheath will withstand not only the induced voltage that can occur during the faults in the grid but also transients. For example, if the SVLs are rated at 12 kV (which have a protective level of at least 25 kV) a DC test at 5 kV would provide inconclusive results, that is, positive result does not mean that the oversheath would withstand the voltage at which the SVL operates. After installation (commissioning) tests are usually based on IEC standards which recommend test voltage of up to 10 kV. North American standards (AEIC CS9 and ICEA S-108-720) recommend test voltage to 6 kV per each mm of the average oversheath thickness but not more than 24 kV. For service aged cables the test voltage may be reduced, but the SVL rating should still be considered. Some internal standards (RTE, ELIA) provide reduced test levels for service aged cables and for various types of oversheath (PVC, PE, or HDPE). Unless the land cables are directly buried the DC test on the oversheath requires semi-conductive (extruded or graphite) layer on the surface of the cables or the cables must be immersed in water otherwise it may not be applicable (results may be inconclusive). This is not applicable to subsea (submarine) cables.

9.7.3.6 Bonding Performance Test and Monitoring of Screen Voltage and Current Bonding performance is often performed as part of after installation (commissioning) procedure to verify theoretical calculations with the measurement (CIGRE TB 680). This test can also be performed as a maintenance test to allow for assessment of the condition of the sheath voltage limiters (SVLs) and earthing of the cable sheath. This is usually not applicable for submarine cables and HV DC cables because their sheath is directly bonded to earth. For further information on bonding of HV cables please refer to CIGRE TB 283 and CIGRE TB 128. A graphical example of the results of measurement and calculations is presented in Fig. 9.14.

Fig. 9.14 Graphical example of measurement and calculations of screen voltage. Blue is the measured value whilst, Red is the calculated value in volts

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9.7.3.7 Sheath Voltage Limiters (SVLs) Test* Sheath (screen) voltage limiters (SVLs) play an important role in protecting cable outer sheath from breakdown during fast transients and resulting transient earth (ground) potential rise. SVLs are used in cross-bonded or single-point bonded systems where they provide isolation of the cable screen from the earth to prevent circulating currents that would limit the thermal rating (ampacity) of the cable during normal and fault conditions, while allowing fast transient currents to flow to the earth. From the design point of view, the SVL are small surge arresters that are installed (in most cases) in link boxes. This means that they have highly nonlinear characteristic and two modes: nonconductive and conductive with a very narrow transient zone (knee). During fast transients, the SVL should limit the voltage between the local earth and the cable screen to avoid breakdown of the cable oversheath and screen interruptions, thus according to the insulation coordination rules, the withstand voltage of the cable oversheath must be higher than the protection level provided by the SVL. Also, the SVL can only dissipate the energy of overvoltages due to fast transients (lightning) and are not meant to operate (conduct) during faults. All surge arresters have limited life span and those installed in the substations may have counters that are used for an asset management and replacement strategy. From this perspective, the SVLs may be subject to the same events and should be considered for replacement with the surge arresters. Also, periodic inspection of the link boxes allows for discovering moisture ingress and preventing corrosion. Failure of the SVL in service may result in either lack of protection (SVL open) or in circulating currents flowing in the screen (SVL shorted) limiting the cable ampacity. The former is more probable while the latter may result in fire or explosion of the SVL but neither of these scenarios is desirable and utilities may consider the following: • Periodic visual inspection or DC test • On-line continuous monitoring of the SVLs The former involves taking an outage on the circuit and opening the link boxes, which requires time and resources. Depending on the location, number of link boxes and installation type this may incur significant costs. The on-line continuous monitoring of the SVLs does not require as frequent inspections but instead requires the initial capital expenditure and maintenance of the monitoring system. In return, the on-line monitoring system provides immediate notice that the condition of the SVLs has deteriorated. If no monitoring is installed, it is recommended to at least replace SVLs when the line surge arresters are replaced. The latter have counters that determine their loss of life and since the SVLs may be subject to as many transients as the surge arresters it is reasonable to assume equal lifespans. For additional information about maintenance testing on SVLs, refer to HD 632 S3:2016 Part 2, paragraph 8.10.

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9.7.3.8 Earthing Resistance Measurement Earthing resistance measurement is a one-time or periodic test performed on earth grids in substations (cost evaluation level L2) and due to possible corrosion should be considered in the general maintenance program and not only for cables. Insufficient/inadequate earthing may cause a risk of step or touch potential during faults and transients which pose risk to the public and employees. For joint bays (cost evaluation level L1), this diagnostic may be performed as part of the after installation (commissioning) test procedure to check if measurements are aligned with theoretical calculations, or before corrective maintenance works to ensure safe conditions for workers (especially under induced voltages/currents). In such a case, any connections (such as metal sheath, ECC) must first be disconnected from the local earthing system (Fig. 9.15). There are several possible methods to measure earthing resistance of a substation or a joint bay. In a conventional method (“fall of potential” method), a current is injected into the electrode system under test by a current source connected to earth remotely, and the resulting rise of earth potential in the electrode under test is measured with respect to another remote earth reference. This measurement is then repeated around a dozen times at increasing distances until reaching an asymptotic earthing resistance value. When using this method, it is important to make sure that the reference earth is not overlapping with the equipotential zone of the earthing system being tested. This will require test leads much longer than for the equipotential zone, such as at least 15 times the largest diameter of the earthing grid. In congested areas with many interconnections, this may be very difficult to achieve with a test electrode. If an outage can be arranged, a transmission line can be used to inject the test current into another substation’s earthing grid, which then simulates a real fault scenario (Figs. 9.16 and 9.17).

Fig. 9.15 Earth resistance measurement

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Fig. 9.16 Earth resistance measurement

Fig. 9.17 Fall of potential curve. Curve in blue: measured earth resistance (ohm), Curve in red: theoretical earth resistance (ohm)

9.7.3.9 Loop and Contact Resistance Measurement Contact resistance measurement is usually performed on all contacts between the cable screen and the earthing grid in the substation or at the joint bay. This is very important to ensure that the path to earth is of the lowest possible resistance to ensure the safety of the public and the employees are not at risk. The concerns are step and touch potentials during faults and transients, as well as overheating of the contacts in two- and multiplepoint bonded systems where circulating currents in the cable screen may be present. The test is performed by means of a 4-terminal DC low resistance measurement often as part of the after-installation field acceptance (commissioning) testing program. The periodicity of the measurement depends on the location of the asset. If a time-based maintenance program is not in place, then the first indication of the necessity to perform contact resistance measurement is a sign of corrosion that can be identified via visual inspection.

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9.7.3.10 DC Conductor Resistance Measurement DC conductor resistance measurement may be used to detect high contact resistance of the conductor in the joints or outside connections (CIGRE TB 680). Its accuracy and reliability is heavily affected by the fact that the resistance depends on the temperature of the conductor which is unknown, hence this measurement is based on the comparison between 3 phases (AC) or 2 poles (DC) of the same circuit but this still does not guarantee equal temperatures of the cable conductors. 9.7.3.11 Capacitance Measurement Capacitance measurement only has little diagnostic value and is sometimes performed after installation rather than a maintenance test (CIGRE TB 680). Capacitance is measured during DS or TD measurement and can also be derived from the AC test parameters. 9.7.3.12 Sequence Impedance Measurement Sequence impedance does not change significantly in service unless geometry of the installation changes or more cables are added in the same corridor, hence it is mostly performed as an after-installation test (CIGRE TB 680). Sometimes utilities include sequence impedance measurement in the scope of the maintenance testing in order to verify protection and control (P&C) settings, especially if there is a history of tripping due to wrong settings. Measurement methods are presented, with schematics, in TB 531 “Cable Systems Electrical Characteristics” – Appendix C. This test can also be used to measure sheath currents and voltages, to ensure that cross-bonding connections were done properly and to verify that they measurements match the design calculations. 9.7.3.13 Inspection of Manometers and Plumbing The hydraulic system consists of the oil pressure cable, cable accessories, expansion vessels, pressure gauges, and pipework. It ensures correct oil pressure management. The performance of the oil pressure circuit, the cable, and accessories are based on the correct operation of the hydraulic system of the connection. To ensure the correct operation of the hydraulic system several tests and inspections can be carried out on the manometers and plumbing. The purpose of the inspection of the manometers is to check their functionality. Pressure gauges are checked for the correct indication, operation of the minimum and maximum signaling contacts and correct setting of the minimum and maximum pressures. These settings depend on the design of the cable system and are calculated by a cable system expert. To check the operation of the manometer, the valves to the cable and the vessels are closed. The manometer reading drops to zero bars when the auxiliary valve is open, and the minimum signaling should respond. With the help of a one-hand pump, the pressure can then be increased until the maximum alarm is triggered. After venting, the cable taps and the vessels can open again. The purpose of inspecting the plumbing is to check the pipework, couplings, taps, and connections for leaks, wear, and breakage. First, the pipework should be cleaned, and the fittings should be checked for leaks. When in doubt whether there is indeed a leak on a system component, a tissue paper is wrapped around the

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suspicious components of the pipework. In case of permanent leakage on a coupling, this must be replaced. The taps are also checked to see if they can be opened and closed smoothly. This activity is carried out at the end closures, the manometers and the accessible vessels of the stop joints along the route of the connection.

9.7.3.14 Oil Leak Detection and Localization The detailed methods and common techniques are explained in the CIGRE technical brochure 652 “Guide for the operation of self-contained fluid filled cable systems.” In the two paragraphs below, there is a short summary of the techniques for land and submarine cables. Leak Location Techniques for Land Cables • Freezing This method freezes a short length of cable fluid, so the cable needs to be de-energized. A small length of cable is uncovered, usually mid-point in the leaking cable section and frozen with liquid nitrogen. When the oil is frozen solid, monitoring the pressure drop at each end of the hydraulic circuit gives an indication of which side of the freeze is leaking. Suitable precautions need to be taken to ensure the safety of people conducting the freeze and to ensure the frozen cable does not move and damage the cable. • Hydraulic Bridge Technique This method, commonly referred to as flow boards, is used on single core cables and measures the flow of fluid through the cable, and by knowing the length and hydraulic resistance of the cable an estimation of the leak position can be found. The cable must be de-energized. Stable temperatures and pressures are required to achieve consistent results. The reliability of the hydraulic bridge technique is crucially dependent upon an accurate knowledge of the cable hydraulic parameters, for example, oil viscosity, hydraulic resistance and the static head difference of the oil section where leak location is required. • PFT Technology This method is based on introducing a small amount of perfluorocarbon tracer (PFT) liquid into the fluid of the cable. When a cable leak occurs, the fluid wets the subsurface soil allowing some evaporation of the tracer, which vents to the atmosphere, forming a plume with the highest concentration at the vent point. This tracer plume is then detectable by an air sampling mobile unit or by sampling air along the cable route. Once the leak is localized, further borehole sampling may be required to pinpoint the cable leak.

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Leak Location Techniques for Submarine Cables Leakage in a submarine cable system requires immediate action, as a fluid leakage into water systems must be stopped as soon as possible. Leaks are either detected by loss of fluid and/or detection of a fluid spill on the water surface. In case of leakage (no electrical breakdown in the insulation) the following steps are recommended: 1. 2. 3. 4. 5.

Ensure that fluid pressure can be maintained for the cable Search for possible leaks Organize a marine spread suitable for leak detection at sea Perform a desktop study using existing documentation of the cable Use the flowboard method to see if there is an indication of the relative position of a leak from each cable end

For visual inspections, an ROV or diver survey of the leaking cable should be undertaken. As freezing or PFT is not an option for submarine cables, cutting and sealing of the cable is the alternative.

9.7.3.15 Oil Analysis: Dissipation Factor Measurement Oil analysis is a powerful tool for condition assessment of fluid-filled accessories. The processes of aging under the influence of the electric field, thermal load, and discharge activity can be detected. Oil analyses are easily reproducible, so that regular oil sampling (e.g., once a year or every 5 years) can give a good picture of the progress of aging processes in the cable accessory. The analysis of the oil aims at measuring the different properties of the oil that can be affected by the aging processes. By comparing with reference values, the measurement data can be interpreted to assess the condition of the cable. The oil analysis results of different cable systems are easy to compare, which means that a large file of reference data can be available for the assessment of individual analysis results. Although oil analysis provides an indication of the local condition experience has shown that an appropriate selection of sampling locations along the system provides a good overall picture of the system condition. Oil samples can be taken where this is possible, usually at the locations of terminations, stop joints, feeding joints, or from the location when the cables are cut to be repaired. The following tests are performed on a sampled oil: • Determination of the loss angle (tan δ) at various temperatures, in accordance with IEC 60247. Increased tan δ values indicate contamination of the oil (water, oxidation products, and/or other polar components), resulting in an increase in conductivity. Measurement of tan δ gives an indication of the aging of the insulation. An increase in the tan δ value that starts at low temperatures and further increases at higher temperatures indicates a strong degradation of the oil that is not due to normal aging. Further analysis is required in this case, such as the breakdown value and the gas concentrations. An increase in the tan δ value that starts at low temperatures,

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but does not continue at higher temperatures, indicates the presence of moisture in the oil. A water content determination is, in this case, the means to check this. • Determination of the breakdown value, in accordance with IEC 156. A low breakdown value is linked to contamination of the oil (water, cellulose chains, and/or conductive particles); in some cases, this contamination can also be observed visually. • Determination of concentrations of the dissolved gases in the oil, similar to the method described in IEC 567. The gas analyses provide information about aging and disruption processes. Increases of certain gases or combinations of certain gases are related to certain aging or disruption processes. After interpretation of the analysis results, possibly by comparison with previously performed analyses on the same compound, an estimate is made of the condition of the investigated connections or part of the connection. Good data about the history of the accessory is useful, as is comparison between different points on the same system.

9.7.3.16 Infrared Temperature Measurement It is possible that insulation degradation raises the material conductivity leading to higher temperatures (eventually thermal runaway and breakdown). This is also the case for areas such as contact resistances, especially for old or badly made screw connections. It is difficult to detect temperature increases due to PD as this would require high repetition rate of PD which is typically not seen under DC voltage. This is applicable on regular and transition joints in vaults, J-tubes, hangoffs, and terminations. 9.7.3.17 Localized Temperature Measurement Localized temperature measurements at specific positions along the cable system can be performed by means of well-established types of measurement equipment. The most widely adopted are thermocouples and resistance thermometers (e.g., PT100 or PT1000). These are analogue sensors, which are tied to the cable’s or accessory’s outer surface to measure the temperature at the specific location continuously. The acquisition of the measurements occurs via metallic (copper) wires, which connect the sensor to its acquisition or interrogation unit, which in turns displays the measurement. The fact that the measurement is wired poses some limitations to the applicability of these types of sensors, particularly when measurement at remote locations is to be performed. Other point temperature measurement solutions allowing wireless measurement acquisition are available in the market. The disadvantage of these is that power supply is normally needed locally at the sensor location. 9.7.3.18 Distributed Temperature Sensing/Measurement (DTS) DTS techniques rely on the use of fiber optic cables, normally deployed either alongside or within the sheaths of high voltage power cables, to measure the fiber’s temperature and thereby reveal hotspots in the cable system. The measurement can be performed via standard single-mode or multi-mode fibers, where light pulses injected by an interrogator placed at the substation are backscattered (reflected with diffusion) in a temperature-dependent way. The way laser signals are translated into temperature

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measurements occurs according to either Raman or Brillouin scattering principle. As DTS techniques measure the temperature at the fiber location, algorithms are necessary to extrapolate the actual conductor temperature at that same longitudinal location. The DTS performance in terms of measurement range increases as the loss on the fiber decreases. However, all else being equal, the performance of the DTS is always a compromise between the required measurement time (time between two subsequent measurements), its spatial resolution, and its accuracy. DTS instruments are only interfaced to the cable system, namely, they only need to be plugged into the optical fibers at one end to be able to perform the measurement. For this reason, DTS instruments can either be permanently installed on one cable system for continuous monitoring during operation, or they can be transported to different locations to monitor different assets for shorter periods of time to create temperature signatures. Commercially available DTS systems can, at present, measure up to several tens of kilometers, with a spatial resolution of a few meters and an accuracy down to +/ 2  C (intended as two standard deviations). Long DC links (>100–150 km) can currently not be monitored via DTS over their entire length. A double-ended measurement can, however, double the length of a cable system covered by the monitoring. DTS provides a very good basis for the verification of the design thermal rating (ampacity) calculations as well as identification of thermal bottlenecks, overloading conditions in N-1 situations, changing environmental conditions (moving sanddunes offshore, etc.). DTS systems can transfer measurements and hot spots to the SCADA-system. Software is available to calculate emergency load based on live measurements. An example of the DTS measurement is presented (Fig. 9.18). CIGRE TB 756 includes more information concerning thermal monitoring of cable circuits utilizing DTS. This measurement system is applicable to all type of cables, if there is an optical fiber installed with it.

Fig. 9.18 Example of a DTS measurement/profile

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Fig. 9.19 Example TDR plot

9.7.3.19 Time Domain Reflectometry (TDR) Time domain reflectometry (TDR) is a diagnostic technique based on the traveling wave principle. Portable equipment generates a high-frequency voltage pulse (in the order of few V to few kV), which is applied between conductor and screen at one end of the cable system, while the remote end can be either earthed or isolated. The reflected signal is then acquired, and the integrity of the main insulation can be assessed. TDR is most often used to locate faults, where the change in the characteristic impedance of the insulation at the fault location creates a wave reflection whenever the fault impedance is sufficiently different from the impedance of the cable itself. A TDR measurement is also performed right after commissioning (CIGRE TB 490, CIGRE TB 680). The purpose of this is to retrieve a so-called “fingerprint” of the cable system, which then can be used for reference at later stages to identify unwanted changes within the cable system as compared to its as-built condition. An example of a TDR plot with an earthed remote end is presented in Fig. 9.19.

9.7.3.20 Frequency Domain Reflectometry (FDR) FDR has been used in telecommunication for many years and it has been proven to have a much higher sensitivity to detect defects and quality joints (crucial in telecommunication cables) than TDR. The measurement is based on the same principle as in network vector analyzers and is performed by injecting variable frequency signals (e.g., white noise or swept frequency signal) and analyzing the response in frequency domain. At various frequencies the line response is different resulting in characteristic “bumps.” An example of a raw FDR plot of a 3-core cable is presented in Fig. 9.20.

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Fig. 9.20 Example FDR plot

9.7.3.21 Cathodic Protection Performance A cathodic protection system is used to prevent the corrosion of metal in pipe type cable systems, SCFF cables, and cables with lead sheath, as well as metal structures that provide support for joints in vaults by making the metallic sheath the cathode of an electrochemical cell. Its main components are a sacrificial anode, a battery, and a rectifier. Drainage is used to safely evacuate stray currents caused by trains or other sources. Grounding circuits of underground cable systems and steel pipes close to railways or other stray current sources must be controlled, and if stray currents are observed, drainage is installed. To test the performance of these systems, the following parameters are periodically measured on site: • • • • •

Battery voltage Rectifier voltage and current Drainage current Pipe potential at rectifiers and drainage location Rail voltage if the drainage is connected to a railway

Those parameters may also be measured continuously (monitoring). Periodic potential checks along the circuit are necessary to ensure that the system is functioning adequately at the known trouble spots, and complete surveys are necessary to detect any changes to the environment, such as additional underground installations, or competing cathodic protection systems from other utilities.

9.7.3.22 Oil/Gas Pressure The hydraulic cable system design of SCFF cables takes into account the cable route and elevation (or vertical profile), as well as the cable fluid thermal expansion and

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contraction caused by cable system temperature variations. The design must also ensure pressures do not fall under well-defined values so positive pressures are maintained at any time. For special applications, gas under pressure is used to provide electrical insulation (e.g., GIL systems, SF6 filled cable accessories). The (online) follow-up of the oil and gas pressure is necessary to ensure the correct functioning of the cable system and/or components under pressure.

9.7.3.23 Distributed Acoustic Sensing (DAS) Similar to DTS for temperature measurement, DAS technologies are able to make use of optical fibers to detect acoustic sounds, which propagate in the ground in the form of acoustic vibrations. In this case, only single-mode fibers can be used due to the need for higher signal resolution. The detection of vibrations via the interpretation of reflected light pulses is performed according to the Rayleigh scattering principle. The detection of vibrations along the cable system can have multiple purposes, depending on the surrounding conditions. The primary goal for adopting DAS is, however, a quick (possibly instantaneous) fault location. In fact, similar to an explosion, a high power cable fault creates powerful vibrations in the immediate surroundings of the fault location, which the DAS is expected to reveal. If not immediately flagged by the DAS, the fault and its location can be searched in the measurement log via the DAS software. Due to the fact that DAS inherently resolves all types of vibrations in the fiber’s surroundings, vibrations originating from the cable system cannot be discerned from those coming from elsewhere. While this fact limits DAS effectiveness in noisy environments, it also allows a wider range of applications. As an example, DAS could also be used to reveal possibly hazardous ground activities occurring in the vicinity of a land cable, as well as detect marine activities nearby a submarine cable. However, as this recognition processes currently needs to be assessed manually, some DAS manufacturers are heavily investing in machine learning and pattern recognition algorithms to make the equipment fully autonomous. For the purpose of fault location, DAS systems are normally a permanent installation. There are however cases where portable DAS systems were used for fault location on cables not originally equipped with DAS, but where optic fibers were available. Here, an impulse generator is used to excite the fault, such that those vibrations are generated and detected by the DAS. 9.7.3.24 Cable Bathymetric Survey Bathymetric surveys are geophysical surveys carried out to obtain a partial or entire mapping of submarine cables’ routes from a bathymetric viewpoint. The survey is typically performed before cable laying and burial, but normally also immediately after (post-lay) to provide reference data for future surveys. By comparing survey data acquired during the cable’s lifetime with the as-built

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survey, one can determine the cable’s depth of cover at the time of the survey as compared to the as-built, thus assessing the need for re-burial campaigns. Bathymetric surveys may also be required by local authorities in connection with consent applications and the release of permits. The frequency with which these surveys need to be conducted is dependent on different factors, for example, the nature of the soil, the occurrence of extreme weather conditions (e.g., storms, hurricanes) at the specific location, and the criticality of the asset. Bathymetric surveys are normally carried out by survey vessels equipped with SSS (Side Scan Sonar) or MBES (Multibeam Echo Sounder). While SSS technologies are best suited to obtain a detailed view of the seabed, to identify rocks, boulders, debris, and other items, the MBES provides seabed contours and is best fit to measure water depth.

9.7.3.25 Impregnation Coefficient Impregnation coefficient is a diagnostic test performed to check for gasses in the paper insulation. Free gasses in the paper insulation of a cable are a threat to the reliability of the connection. Formation of gasses can be caused by, among other things, partial discharges or by an oil leakage in an SCFF cable system. The test procedure includes tapping a predetermined small amount of oil, after which the pressure drop in the cable is being measured. All connected vessels on the oil section to be tested must be closed during the test. The impregnation coefficient is then calculated on the basis of the amount oil tapped, the total oil volume in the hydraulic section and the measured pressure drop. The derived value is then compared with a critical value. The critical value is usually defined by a cable expert on the subject. 9.7.3.26 Insulation Sample Testing Where cable or accessory repairs are performed due to failure or relocation, it may be possible to obtain insulation samples for testing. If these are far enough from a failure site to have avoided damage from the fault, then these methods may point to causal factors in the failure analysis. Even in the absence of a failure, they may be used to provide an indication of the overall insulation health and aging condition. XLPE cross sections can be examined for dimensional changes associated with heating, oxidation induction time may be able to indicate what maximum temperature was reached, mechanical and chemical tests can show if there has been significant thermal aging, and slices can be checked for water-tree count. Laminated cable insulation of fluid-filled cables can be checked for tape displacement, wax formation, evidence of discharge activity in the butt gaps, and paper samples can be sent for degree-of-polymerization testing to determine the extent of thermal ageing.

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9.8

Spare Parts Management, Emergency Preparedness, and Training

9.8.1

Spare Parts Management

9.8.1.1 Context When dealing with spare parts management it is of prominent importance to define what has to be considered as a spare. The definition of spare is as following: “A spare part is any material available without a specific destination, to be kept available, ready to be used by all, to deal with urgent interventions related to the occurrence of failures.” A spare is usually considered different from a replacement part, which is a material available for a specific plant, acquired at the same time as the construction of the facility. A replacement part could be eventually used for failures, but not in an exclusive way; in fact, a replacement is frequently used for managing the heavy maintenance routines, in such a way avoiding long lasting out of service. To avoid that a spare part is used as a replacement part, spares could be declared accordingly (e.g., as “safety stock”) within the warehouse management system. A replacement part, as well as a spare, could or could not be kept on site or they could be stored in the supplier warehouse as well as in the owner warehouse, in accordance with the company’s policy. In this context a spare could be any HV cable length or any HV cable accessory that is used to face the loss of HV cable elements caused by any kind of failure. Spare part management aims at increasing the availability of the cable system in operation. To archive this, a certain amount of spare parts should already be available at the time of commissioning and should be kept ready for use as long as the cable systems for which it is aimed at are under operation. Therefore, spare parts need to be checked, stored, and maintained accordingly. In case of use of spare parts, new spares may have to be ordered, depending on what is left is sufficient or not to cover potential future failures. Spare parts shall be of sufficient quantity and shall be available in a timely manner, which could be managed by the owner itself or by means of the original supplier through a proper maintenance contract, in order to promote efficiency and minimize performance disruption of electrical power system. 9.8.1.2 Identification of the Critical Parts to Be Kept Available A proper identification of the critical spare parts to be kept available should take into consideration the combination of three main factors: • Component failure rate • Impact on the quality of service • Delivery times (lead times) Since lead times for the HV equipment are usually not compatible with the needs of a proper continuity of service, this could be considered an irrelevant factor and the choice is determined only by the variability of the first two. For the purpose of

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Fig. 9.21 Failure rate/Quality of service

identifying the components for which it is appropriate to have stock, these two factors can be related to each other with a law of the type described below (Fig. 9.21): Failure rate  k∙

1 Quality of service

ð9:2Þ

For sake of simplicity, the curve can be approximated with a simplified function, dividing the axis into three zones, identified by the Quality of Service which can be classified High, Medium, and Low. The value 1 would be assigned to the QoS indicator in the case of maximum importance for the service, and 0 for zero importance. The three bands are identified as shown in Fig. 9.22 below (High: for 0.5 < QoS