Materials Ageing in Light-Water Reactors: Handbook of Destructive Assays 3030855996, 9783030855994

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François Cattant

Materials Ageing in Light-Water Reactors Handbook of Destructive Assays Second Edition

Materials Ageing in Light-Water Reactors

François Cattant

Materials Ageing in Light-Water Reactors Handbook of Destructive Assays Second Edition

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François Cattant FC² – François Cattant Consulting Plescop, France

The Materials Ageing Institute (MAI) ISBN 978-3-030-85599-4 ISBN 978-3-030-85600-7 https://doi.org/10.1007/978-3-030-85600-7

(eBook)

1st edition: © Materials Ageing Institute (MAI) and EDF 2014 2nd edition: © Materials Ageing Institute 2022 This work is subject to copyright. All rights are solely and exclusively licensed 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

2010 Foreword

As the largest worldwide PWR1 operator, Electricité de France has been collecting for the past 30+ years' results of not only in-house but also foreign metallurgical examinations, mainly on PWR components, along with some results from BWR2s. This tremendous amount of data, efficiently collected by François CATTANT, with the help of the CEIDRE and of the EDF R&D, along with some foreign organizations or operators, demonstrate that sharing of field experience is very active in the nuclear industry. In 1990, Pierre MOUSSET published the first handbook of destructive examinations which proved to be very useful for training of metallurgical technicians and engineers during the past 20 years. As intended by the author, this handbook has been a “reference document” and has recently been edited in electronic format, thanks to Philippe GATELIER (CEIDRE). In the meantime, new events have occurred, with potential impact on the nuclear components’ long-term behavior, which have been documented by laboratories that conduct metallurgical examinations. International meetings, such as the “Fontevraud” conference organized by the French Nuclear Energy Society under the technical lead of EDF, Areva and the CEA,3 have provided periodic reviews of the events, a summary of which is presented hereafter. In the 80s, steam generator degradation, especially A600 tube bundles were the first issue on which many laboratories in the world worked on simultaneously. Many forms of degradation had already occurred, including not only PWSCC4 but also others such as denting at tube support plate locations and wastage. Regarding other PWR major components, the pressure vessel was focus of much attention and irradiation embrittlement monitoring programs were far from being completed (all vessel materials surveillance capsules had not been withdrawn yet). Even if the assets life management program were in place, pressure vessels had not operated 1

PWR: Pressurized Water Reactor. BWR: Boiling Water Reactor. 3 CEA: Commissariat à l’Energie Atomique (Atomic Energy Commission). 4 PWSCC: Primary Water Stress Corrosion Cracking. 2

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long enough to raise questions. As for other components, a few destructive examinations had made us think that we may have to face some new issues down the road (thermal fatigue, split pins cracking, baffle bolts cracking, etc.). In the 90s, steam generators were still a major issue because of MA6005 cracking although this alloy had been replaced several years before first by TT6006 and then by A690. EDF had already pulled several dozens of tubes for destructive examination in the hot laboratory of Chinon. Regarding A600, another warning came from the pressurizer instrumentation nozzles of the 1300 MWe reactors which experienced early cracking and were soon replaced with stainless steel nozzles. PWSCC was the failure root cause. Concerning pressure vessels, the results coming from the materials irradiation embrittlement monitoring program of the Chooz A7 reactor revealed a discrepancy between predictions and experiments. Explanation had to be found in fabrication records and operational data. A few years later, the paramount importance of destructive examinations for the operator and for the designer, came even more into light. As a matter of fact, although steam generator tubes failures were catching most of the attention, a leak of a reactor pressure vessel head penetration in 1991, not expected so early, triggered a tremendous amount of work and research on A600 thick sections. Framatome (now Areva) and EDF launched comprehensive studies in order to improve the understanding of this material behavior. Elsewhere in the world, this event drew rather little attention, appearing as a French-specific issue. Sophisticated nondestructive examination techniques were developed to check for this material condition either in the vessel top head penetrations or vessel bottom head penetrations. Besides this, EDF launched a vast program to know more about the failure of tubes from a replaced steam generator8; an activity prompted by the fact that several tube ruptures had already occurred in foreign countries. International research programs are also currently active, leading to significant sharing of results and operational experiences, especially regarding A690 behavior, the reference for PWSCC resistant material. Starting in the 2000s, the most significant progress comes from the pressure vessel studies with the US work on the “Master Curve” and the final results from the Chooz A vessel examination program. Chooz A was decommissioned at the end of 1991 and mechanical specimens were machined from samples harvested from the core shells. Destructive examinations are also very important to the understanding of the failures of 600/182/82 alloys in the US, either at Davis Besse (vessel head), VC summer (vessel outlet nozzle), North Anna 2 (vessel head) or at South Texas Project 1 (bottom mounted nozzle).

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MA: Mill Annealed. TT: Thermally Treated. 7 Chooz A was the first French PWR. 8 Steam generator of Dampierre 1, loop #3 (steam generator #27). 6

2010 Foreword

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Major improvements in knowledge have also been achieved in the IASCC9 of core lower internals bolts, thermal fatigue which will become even more important after the leak of a RHR10 elbow at Civaux 1, martensitic stainless steels ageing, hardfacing alloys, typically stellite although being more and more replaced with cobalt free alloys, frequently used in valves, and steam generator channel head partition plate. Concerning piping and pumps, as an example, the thermal ageing of cast stainless steels is well documented since the early 90s. The ageing mechanisms are today reviewed (ferrite decomposition) with more powerful observation tools. The improvement of the knowledge regarding thermal ageing mechanisms, for longer and longer periods of operation, supports the prediction models of the mechanical properties’ evolution, in the context of life extension beyond 40 years. Regarding A600 base metal, EDF has recently devoted a lot of resources to the steam generator channel head partition plate issue. The paramount importance of a deformation prior to operation has been demonstrated. This result is consistent with what has been observed on vessel head penetrations in the 90s and allows today the proposing of a prediction model and fine-tuning the maintenance strategy. Stress corrosion cracking mitigation techniques, such as zinc injection in the reactor coolant system, should be soon more generally available and in use, following laboratory studies, supported by destructive examinations. Today, concerning steam generators, all laboratories worldwide are not only working on PWSCC but also on the numerous secondary side corrosion events which can occur in the various tube bundle materials such as MA600, TT600 and alloy 800, due to the operation practices (chemistry and presence of pollutant such as lead). As with the pressure vessel, it is not surprising that the life extension beyond 40 years of operation of this component, which is not supposed to be replaced, focuses major interest on the new methods for interpreting operation and metallurgical examinations data. At last, something would be missing from this overview if not mentioning, as a conclusion, the third-generation reactors such as the European Pressurized Reactor, which have been designed to take full advantage of the experience of operating reactors. This field experience which has been taken into account in the design and construction codes such as the RCC-M11 led to the request for material modifications or replacements, and even to ban the use of certain materials for specific purposes. This has been a brief overview of some of the progress made over a few dozens of years thanks to the metallurgic examination of nuclear power plant components, such progress should go on.

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IASCC: Irradiation Assisted Stress Corrosion Cracking. RHR: Reactor Heat Removal (system). 11 RCC-M: Règles de Conception et de Construction des matériels Mécaniques des ilots nucléaires PWR (design and construction rules for mechanical components of PWR nuclear island). 10

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The nuclear power plants life extension plans and the increasing needs of safety justifications call for more and more metallurgical examinations: this is a fundamental and decisive evolution in the nuclear industry. No doubt that this handbook, made unique by its extended content and its variety of images, will become the new and essential reference for nuclear power plant materials experts. Let me warmly thank all the contributors to this handbook which shows the increasing importance of the metallurgical destructive examinations, and especially the person who launched and coordinated it, François Cattant. CEIDRE12 Director13 Cécile Laugier

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CEIDRE: Centre d’Expertise et d’Inspection dans les Domaines de la Réalisation et de l’Exploitation (Examination and inspection center in the fields of fabrication and operation). 13 At the time the handbook was written (2009).

2020 Foreword

Since the writing of the previous version of the handbook and Cécile Laugier’s foreword, almost 10 years have passed with rich news in materials ageing for nuclear power plants. To complete the overview drawn up by Cécile Laugier on 30 years of nuclear power at EDF, I would like to mention a few highlights of the years 2010 on materials ageing for EDF’s nuclear fleet, confirming the importance of keeping on capitalizing and developing expertise in this field. First of all, countermeasures were deployed on a large scale to offset the difficulties that arose during the previous period. For example, the corrosion problems linked to Alloy 600 that once affected steam generator bundles (tubes and plugs) and reactor pressure vessel heads are about to disappear thanks to the widespread replacement by Alloy 690. The absence of failures observed in operation to date confirms the relevance of this alloy, which is considered to be virtually insensitive to corrosion. It should be noted that in this vast replacement program, the sleeving technique with Alloy 800 has been an excellent complement by enabling certain steam generator replacements to be postponed without jeopardizing safety.

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At the same time, zinc injection continued to be extended in order to reduce the dosimetry due to corrosion products, with a beneficial side effect to also reduce the risk of stress corrosion cracking initiation. In order to deal with Irradiation-Assisted Stress Corrosion Cracking (IASCC) of the vessel internals reinforcement bolts, a strategy was deployed to inspect all units and replace the screws bolts on the oldest units. Other countermeasures proved effective over time, but generated subsequent problems on other components. This is the case with the wear of the control rods guide cards, which has increased with the use of wear-treated rods over the last few decades. Then, some degradations previously identified have continued to initiate, due to a lack of success in developing definitive remedial actions, such as cracks at the tubes’ foot on the secondary side of 600TT and 800 Alloy steam generator tubes, and more generally clogging and fouling on the secondary side of the steam generators requiring preventive cleaning operations, the frequency of which must be further optimized thanks to R&D work on the kinetics of clogging and fouling after chemical cleaning. We should also mention the wear of the thermal adapter sleeves, for which remedial actions are still being studied. These examples stress the importance of in-service monitoring based on qualified NDT applications of increasing performance and the development of the most reliable prediction tools for the maintenance of these components. Finally, the increased requirements linked to regulatory changes lead to the re-examination of some justification cases, often seeking for more physical and less empirical models, in order to better describe ageing mechanisms. The purpose of my remarks is less to discuss the available margins than to point at the increased importance of component expertise, which should not be limited to observed degradations alone but extended to the scope necessary for understanding and modelling physical phenomena. In this field, research institutes such as the MAI, which links the academic world to the industrial world, have an essential role to play. The overview over 40 years of operation is rich in lessons. It invites us to continue to capitalize on and assess the phenomena over time, with rigor and modesty. At this point, I would like to pay tribute to the commitment and dedication of researchers and engineers from all over the world to expertise and research on materials ageing. I would like to thank them, because such a book would not be possible without them. I would particularly like to acknowledge the long-term commitment of François Cattant who, on the opportunity of the 10th anniversary of the MAI, spontaneously proposed to me the updating of his book, written almost 10 years ago. In spite of the workload that such a work can constitute, I have been able to see that his commitment and willingness to share his knowledge and experience have not diminished for his second book. May he be thanked a second time.

2020 Foreword

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The updating of this book was also an opportunity to extend the international feedback by adding contributions from CGN, China General Nuclear power group and MAI long-lasting member. I would like to warmly thank them for having willingly shared their feedback and thus contributed to the improvement of knowledge. In the end, the book will have doubled in volume, so much so that the mass of knowledge acquired over the last 10 years has been significant. I have no doubt that this book will be appreciated as much, if not more than the previous one, and will become a reference book for researchers and engineers interested in the exciting field of materials ageing materials and remedial actions adopted to deal with it in nuclear power plants. Hing-Ip Wong MAI director

For a Better Next Decade

In retrospect, it has been realized that since Suzhou Nuclear Power Research Institute (SNPI) jointed the Materials Aging Institute (MAI) in 2011 as a full member on behalf of CGN, 10 years have passed before the 2020 version of the MAI material handbook is officially published. In the past ten years, the cooperation between SNPI and MAI has gone from the initial difficulties to an in-depth integration in various fields. Over the past decade, both sides have faced the ups and downs of the nuclear power industry and shared each other’s progresses. Subsequently, the communication between us is becoming more and more frequent, the ties between us are becoming closer and closer, and the coverage of the cooperation is becoming broader and broader. By 2020, CGN has undertaken 7 MAI research projects which cover more than 70% of MAI R&D areas increased from the initial 10%, accumulative MAI project funds (equivalent technical contribution) undertaken by the CGN reach 2.5 million euros, and the accumulated R&D funding for the MAI invested by the CGN is more than 4.67 million euros. Through years of the in-depth cooperation, CGN has

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obtained a large number of scientific research results and organized or participated many special training courses and technical exchanges in depth. In 2020, two sides deepen further the cooperative relationship and have jointly built “Enterprise Overseas Joint Laboratory Construction Project of Jiangsu Province” successfully. All of these, mark the further deepening of the friendly cooperation between the two sides and also conforms to the “Co-construction, openness and cooperation” from the global economic philosophy advocated by President Xi Jinping. Thus, the subsequent cohesive development of both sides will surely provide a solid guarantee for the safe operation of nuclear power plants. The writing process of the MAI material handbook is actually a microcosm of the cooperation between the two sides. Years of material aging collaborative research results are finally integrated by convergence in the integration and bred in the intersection to contribute a series of classic cases of the material aging for the nuclear power industry. We sincerely hope that this book can become an essential reference for every material aging engineer. Looking back, it is not that ten years are too brief, but ten years are too swiftly passing by. We are looking forward to expecting a more brilliant chapter of the cooperation between the two sides in the next decade. Xue Fei Director Power Plant Life Management—Technology Center China General Nuclear Power Group, Shenzhen, China

Acknowledgments

This handbook is the product of a team effort. The following individuals or organizations have participated by providing results, comments, support or reviewing: Al Ahluwalia Aladar A. Csontos Alain Pencreac’h Andréas Schumm Antoine Ambard Arnaud Mazenc Benoit Tillard Bernard Yrieix Chunhui Wang Claire Rainasse Clara Panait Claude Pagés David Steiniger Denis Dallery Denis Weakland Dominique Moinereau Ellen Mary Pavageau Elodie Fargeas Emmanuel Lemaire Eric Derniaux Eric Garbay Eric Molinié Fan Minyu, Fang Kewei Francis Fradet François Foct

Electric Power Research Institute—USA Nuclear Regulatory Research—USA EDF—France EDF—France EDF—France EDF—France EDF—France EDF—France CGN—China EDF—France EDF—France EDF—France Electric Power Research Institute—USA EDF—France Retired from First Energy Nuclear Operating Company—USA EDF—France EDF—France EDF—France EDF—France EDF—France EDF—France EDF—France CGN—China CGN—China EDF—France EDF—France

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François Vaillant Frédéric Renaud Gary L. Stevens Gary Moffatt Hervé Gloriant Hideo Tanaka Hongqing Xu James Cirilli Jan van der Lee Jean Christophe Couty Jean Christophe Le Roux Jean Luc Delanoue Jean Marie Boursier Jean Michel Stephan Jean Paul Massoud Jim Hyres Karine Dubourgnoux Kyoichi Asano Lai Yunting Larry Nelson Laurent Duvernoy Lin Lei Liu Xiangbing Liu Zhong Marc Boccanfuso Marc Delnondedieu Marie Tourneur Marielle Akamatsu Mike Mc Devit Mike Robinson Nadine Gay Nathalie Monteil Nhu-Cuong Tran Nicolas Robert Odile de Bouvier Ooki Suguru Pal Efsing Patrice Pitner Patrick Todeschini Peng Qunjia Priscille Cuvillier Randy Stark Régis Tampigny Rémi Bonzom Rémi Mercier

Acknowledgments

EDF—France EDF—France Nuclear Regulatory Research—USA South Carolina Electric & Gas—USA EDF—France The Kansai Electric Power Company—Japan Areva—USA Exelon—USA EDF—France EDF—France EDF—France EDF—France EDF—France EDF—France EDF—France Babcock—USA EDF—France TEPCO—Japan CGN—China Retired from General Electric—USA EDF—France CGN—China CGN—China CGN—China EDF—France EDF—France EDF—France EDF—France South California Edison—USA Duke Power—USA EDF—France EDF—France EDF—France EDF—France EDF—France TEPCO—Japan Vattenfall—Sweden EDF—France EDF—France CGN—China EDF—France Electric Power Research Institute—USA EDF—France EDF—France EDF—France

Acknowledgments

Romain Verlet Ronald Baker Said Taheri Salem Miloudi SFEN Shi Fangjie Shi Jinhua Sophie Maingot Steven Fyfitch Sunichi Suzuki Takayuki Magari Tatsuo Ishikawa Terry Mac Allister Thierry Couvant Ti Wenxin Xu Chaoliang Xue Fei Yang Shen Yannick Thebault Yu Weiwei Zhang Zhouyong Zuo Dungui

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EDF—France South Texas Project Energy Generating Station—USA EDF—France EDF—France French Nuclear Energy Society—France CGN—China CGN—China EDF France Areva—USA TEPCO—Japan The Kansai Electric Power Company—Japan The Kansai Electric Power Company—Japan South Carolina Electric & Gas—USA EDF—France CGN—China CGN—China CGN—China EDF—France EDF—France CGN—China CGN—China CGN—China

Special thanks to Mohamad Behravesh, retired from the Electric Power Research Institute, for his careful final review of the entire original document. This revision was made possible because of the deep involvement of Yannick Thebault, who provided a large quantity of information and spent many hours in reviewing most of the chapters.

Goal of the 2020 Revision

The first version of the Handbook of Destructive Assays includes results anterior to 2010. Thus, The MAI considers that 10 years is a relevant interval for updating this handbook. So, the 2020 version of the Handbook of Destructive Assays compiles all the information already included in the 2009 version with new results obtained between 2009 and 2019. Moreover, two additional chapters (numbers 24 and 25), has been added. Chapter 24 contains a basic review of the main NDE/NDT techniques used in light water reactors to detect and/or monitor field failures. Chapter 25 is related to Balance Of Plant destructive examinations. Hereafter are some of the major modifications brought to the 2009 version, the reader will find in the 2020 revision. Chapter 2: Fundamentals of Light Water Reactors A brief description of VVER (Voda-Vodyanoi Energetichesky Reaktor) reactors has been added. Chapter 3: Failure and Ageing Mechanisms This chapter has been strongly extended by adding 10 new failure and ageing mechanisms: cavitation erosion, vibration fatigue, environmentally assisted fatigue, excessive deformation and plastic instability, elastic or plastic instability—buckling, progressive deformation, fast fracture in the ductile regime, fast fracture in the brittle regime and in the fragile/ductile region, swelling under irradiation and thermal ageing of 30% chromium nickel base alloys, ordering. Chapter 5: Nickel Base Alloys The main supplements brought to this chapter bear on bottom mounted instrumentation, reactor pressure vessel head nozzles, X750 split pins and bolting, pressurizer nozzles, steam generator blowdown nozzles and steam generator channel head issues.

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Chapter 6: Steam Generator Tubes, Plugs, Sleeves and Heat Exchangers The main supplements brought to this chapter bear on: • • • • •

600TT tubes suffering from axial cracking; Alloy 800 tubes suffering from ODSCC; 600TT tubes suffering from axial and circumferential ODSCC; 600MA tubes suffering from severe IGA at TSPs and Blowdown heat exchangers degradations in operation.

Chapter 7: Stress Corrosion Cracking of Cold Worked Stainless Steel The main supplements brought to this chapter bear on the destructive examination of a cracked Alloy A-286 vent valve jackscrew, a pressurizer heater failure examination, the synthesis of destructive examinations carried out on reactor coolant pumps bolts and studs and on supplements to the destructive examination of a steam generator inlet nozzle safe end. Chapter 8: Stainless Steels IASCC The destructive examination of a replacement former-baffle plate bolt has been added to this chapter. CNG research experiences in magnetic methods used to evaluate the susceptibility of IASCC has also been added to this chapter. Chapter 9: Stress Corrosion Cracking of Stainless Steel in Polluted Environment or in Occluded Conditions The main supplements brought to this chapter bear on in core instrumentation guide tubes corrosion, RPV flange leak off lines corrosion and bolts cracking. Chapter 10: Rupture and Stress Corrosion Cracking of Martensitic Stainless Steel The main supplements brought to this chapter bear on a valve stem rupture. Chapter 12: Hydrogen Embrittlement Several destructive examinations have been added to this chapter. Chapter 15: Hardfacing Materials Degradation The main supplements brought to this chapter bear on a safety injection system valve. Chapter 16: Mechanical Fatigue Failure Various destructive examinations have been added to this chapter. Chapter 17: Thermal Fatigue Failure Various destructive examinations have been added to this chapter.

Goal of the 2020 Revision

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Chapter 18: Thermal Ageing One destructive examination and one comprehensive study of 17-4 PH ageing have been added. Chapter 21: Wear Various destructive examinations have been added to this chapter. Chapter 22: Miscellaneous Degradation Observations This chapter has been significantly extended. Chapter 23: BWRs Cracking This chapter has been significantly extended. Chapter 24: NDT Techniques Used in LWRs for Failures Detection and/or Monitoring This chapter is new. Chapter 25: Balance Of Plant This chapter is new.

Contents

Part I

Fundamentals, Degradation Mechanisms, Failures of Nickel Alloys, Heat Exchangers and Cold Worked Stainless Steels 3

1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2

Fundamentals of Light Water Reactors . . 2.1 Background . . . . . . . . . . . . . . . . . . . 2.2 Basics of Pressurized Water Reactors . 2.3 Basics of Boiling Water Reactors . . .

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3

Failure and Ageing Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Aqueous Corrosion . . . . . . . . . . . . . . . . . . . . . . . . 3.2.2 Atmospheric Corrosion . . . . . . . . . . . . . . . . . . . . . 3.2.3 Hot Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Cavitation Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . 3.3.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . 3.3.3 Mechanism Description . . . . . . . . . . . . . . . . . . . . 3.3.4 Mechanism Impact . . . . . . . . . . . . . . . . . . . . . . . . 3.3.5 Influencing Conditions . . . . . . . . . . . . . . . . . . . . . 3.3.6 Components Susceptible to Cavitation Erosion . . . . 3.3.7 Preventing Cavitation Erosion . . . . . . . . . . . . . . . . 3.4 Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . 3.4.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Mechanism Description . . . . . . . . . . . . . . . . . . . . 3.4.4 Understanding and Keeping Fatigue Under Control 3.4.5 Mechanism Impacts . . . . . . . . . . . . . . . . . . . . . . . 3.4.6 Initiation Parameters List . . . . . . . . . . . . . . . . . . .

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3.4.7 Potentially Susceptible Components . . . . . . . . . . . . . 3.4.8 Preventing Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 Vibration Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.3 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.5.4 Application Domain . . . . . . . . . . . . . . . . . . . . . . . . 3.5.5 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.5.6 Mechanism Consequences . . . . . . . . . . . . . . . . . . . . 3.5.7 Influent Parameters . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.8 Potentially Concerned Components . . . . . . . . . . . . . 3.5.9 Preventing Vibration Fatigue . . . . . . . . . . . . . . . . . . 3.6 Environmentally Assisted Fatigue . . . . . . . . . . . . . . . . . . . . 3.6.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.6.2 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.6.3 Mechanism Consequences . . . . . . . . . . . . . . . . . . . . 3.6.4 Influent Parameters . . . . . . . . . . . . . . . . . . . . . . . . . 3.6.5 Potentially Susceptible Components . . . . . . . . . . . . . 3.6.6 Preventing Primary Water Assisted Fatigue . . . . . . . 3.6.7 Corrosion Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 Excessive Deformation and Plastic Instability . . . . . . . . . . . . 3.7.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7.2 Materials and Components of Concern . . . . . . . . . . 3.8 Elastic or Plastic Instability—Buckling . . . . . . . . . . . . . . . . . 3.8.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8.2 Materials and Components of Concern . . . . . . . . . . 3.9 Progressive Deformation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.1 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.2 Materials and Components of Concern . . . . . . . . . . 3.10 Fast Fracture in the Ductile Regime . . . . . . . . . . . . . . . . . . . 3.10.1 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.10.2 Materials and Components of Concern . . . . . . . . . . 3.11 Fast Fracture in the Brittle Regime and in the Fragile/Ductile Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.1 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.2 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.3 Metallurgical and Mechanical Aspects of Cleavage Fracture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11.4 Main Materials and Components of Concern . . . . . . 3.11.5 Materials Mechanical Characterization . . . . . . . . . . . 3.11.6 Fracture in the Brittle—Ductile Transition Domain . . 3.11.7 Intergranular Fracture . . . . . . . . . . . . . . . . . . . . . . . 3.12 Austenitic Stainless Steels Irradiation Embrittlement . . . . . . .

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Contents

3.13

3.14

3.15

3.16

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3.12.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.12.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . . 3.12.3 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.12.4 List of Influent Parameters . . . . . . . . . . . . . . . . . . . 3.12.5 Components of Potential Concern . . . . . . . . . . . . . . 3.12.6 Preventing Austenitic SSs Irradiation Embrittlement . Austenitic Stainless Steels Irradiation Creep . . . . . . . . . . . . . 3.13.1 Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13.2 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.13.3 Application Domain . . . . . . . . . . . . . . . . . . . . . . . . 3.13.4 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.13.5 Mechanism Impacts . . . . . . . . . . . . . . . . . . . . . . . . 3.13.6 List of Influent Parameters . . . . . . . . . . . . . . . . . . . 3.13.7 Potentially Affected Components . . . . . . . . . . . . . . . 3.13.8 Preventing Austenitic Stainless Steels Irradiation Creep . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Irradiation Assisted Stress Corrosion Cracking of Austenitic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.14.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . . 3.14.3 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.14.4 Various IASCC Mechanisms . . . . . . . . . . . . . . . . . . 3.14.5 List of Influent Parameters . . . . . . . . . . . . . . . . . . . 3.14.6 Potentially Affected Components . . . . . . . . . . . . . . . 3.14.7 Preventing IASCC . . . . . . . . . . . . . . . . . . . . . . . . . RPV Steels Neutron Irradiation Embrittlement . . . . . . . . . . . 3.15.1 Description of the 2 Embrittlement Classes (Hardening and not Hardening) . . . . . . . . . . . . . . . . 3.15.2 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.15.3 Application Field . . . . . . . . . . . . . . . . . . . . . . . . . . 3.15.4 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.15.5 Mechanism Impact . . . . . . . . . . . . . . . . . . . . . . . . . 3.15.6 List of Influent Parameters . . . . . . . . . . . . . . . . . . . 3.15.7 How to Mitigate RPV Steels Neutron Irradiation Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . Swelling Under Irradiation . . . . . . . . . . . . . . . . . . . . . . . . . 3.16.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.16.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . . 3.16.3 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 3.16.4 Preventing Swelling . . . . . . . . . . . . . . . . . . . . . . . . Cast Stainless Steels Thermal Ageing . . . . . . . . . . . . . . . . . . 3.17.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 3.17.2 Application Domain . . . . . . . . . . . . . . . . . . . . . . . .

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128 129 129 134 137 137 137 137 138 138 139 141 141 142

. . 142 . . . . . . . . .

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143 143 143 145 146 150 151 154 155

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155 155 155 156 157 158

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159 160 160 160 161 169 170 170 170

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Contents

3.17.3 3.17.4 3.17.5 3.17.6 3.17.7

4

Mechanism Description . . . . . . . . . . . . . . . . . . . Mechanism Consequences . . . . . . . . . . . . . . . . . . List of Influent Parameters . . . . . . . . . . . . . . . . . Potentially Concerned Components . . . . . . . . . . . How to Prevent and Mitigate Cast SSs Thermal Ageing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.18 a′ Precipitation Ageing of Martensitic Stainless Steels . . . 3.18.1 Mechanism Identification . . . . . . . . . . . . . . . . . . 3.18.2 Application Domains . . . . . . . . . . . . . . . . . . . . . 3.18.3 Mechanism Description . . . . . . . . . . . . . . . . . . . 3.18.4 Mechanism Effects . . . . . . . . . . . . . . . . . . . . . . . 3.18.5 Influent Parameters List . . . . . . . . . . . . . . . . . . . 3.18.6 Potentially Affected Components . . . . . . . . . . . . . 3.18.7 How to Prevent and Mitigate a′ Precipitation Ageing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.19 Low Alloy Steels and Carbon Steels Thermal Ageing or Temper Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.19.1 Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.19.2 Mechanism Identification . . . . . . . . . . . . . . . . . . 3.19.3 Domains of Relevance . . . . . . . . . . . . . . . . . . . . 3.19.4 Phenomenon Description . . . . . . . . . . . . . . . . . . 3.19.5 Mechanism Consequences . . . . . . . . . . . . . . . . . . 3.19.6 List of Influent Parameters . . . . . . . . . . . . . . . . . 3.19.7 Susceptible Components . . . . . . . . . . . . . . . . . . . 3.19.8 Preventing and Mitigating Temper Embrittlement . 3.20 Thermal Ageing of 30% Chromium Nickel Base Alloys, Ordering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.20.1 Mechanism Description . . . . . . . . . . . . . . . . . . . 3.20.2 Preventing SRO and LRO . . . . . . . . . . . . . . . . . . 3.21 Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.21.1 General Description . . . . . . . . . . . . . . . . . . . . . . 3.21.2 Ashby Maps: Wear Mechanisms . . . . . . . . . . . . . 3.21.3 Influence of Particles . . . . . . . . . . . . . . . . . . . . . 3.21.4 Wear Consequences . . . . . . . . . . . . . . . . . . . . . . 3.21.5 Influent Parameters . . . . . . . . . . . . . . . . . . . . . . . 3.21.6 Preventing Wear . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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183 183 183 183 184 184 185 186 187

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187 187 196 196 196 199 201 201 201 202 202

Materials Properties . . . . . . . . . . . 4.1 Austenitic Stainless Steels . . . 4.2 Ni Alloys . . . . . . . . . . . . . . . 4.3 High Strength Alloys . . . . . . 4.4 Carbon and Low Alloy Steels 4.5 Hard-Facing Alloys . . . . . . . .

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205 205 208 212 215 219

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170 173 173 177

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177 178 178 179 179 180 181 181

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Contents

4.6 4.7 4.8

5

xxvii

Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Titanium Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Materials Forbidden in the Containment Building . . . . . . . . 4.8.1 Materials in the Containment Building Atmosphere 4.8.2 Polluting Materials . . . . . . . . . . . . . . . . . . . . . . . .

. . . . .

Nickel Base Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Destructive Examinations Related to Reactor Pressure Vessel Issues—Results and Remediation . . . . . . . . . . . . . . . . . . . . . 5.2.1 Reactor Pressure Vessel Outlet Nozzle Cracking . . . 5.2.2 Reactor Pressure Vessel Outlet Nozzle Repair Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.3 Reactor Pressure Vessel Outlet Nozzle Dissimilar Weld Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.4 Reactor Pressure Vessel Outlet Nozzle Leak . . . . . . 5.2.5 Destructive Examination of a Boat Sample Removed From a Leaking Bottom Mounted Instrumentation Nozzle at a W Plant . . . . . . . . . . . . . . . . . . . . . . . . 5.2.6 Laboratory Analysis of a Boat Sample Removed From a Leaking Bottom Mounted Instrumentation Nozzle at a CE Plant (Hyres 2015) . . . . . . . . . . . . . 5.2.7 Laboratory Analysis of a Bottom Mounted Instrumentation Nozzle at an Areva Plant (Derniaux 2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.8 Synthesis of the Destructive Examinations Carried Out on EDF Reactor Pressure Vessel Head Penetrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.9 Destructive Examination of a Boat Sample Harvested From a Leaking Penetration of a B&W Unit . . . . . . 5.2.10 Replica of a Leaking Control Rod Drive Mechanism Penetration From an MHI Unit . . . . . . . . . . . . . . . . 5.2.11 Destructive Examination of a Boat Sample Harvested From a Penetration of a W Unit . . . . . . . . . . . . . . . 5.2.12 Destructive Examination of a Retired Reactor Pressure Vessel Head . . . . . . . . . . . . . . . . . . . . . . . 5.2.13 Destructive Examination of a Control Element Drive Mechanism Repaired with A52 . . . . . . . . . . . . . . . . 5.2.14 Leak of a Reactor Pressure Vessel Head Vent Nozzle at a KHIC-CE Unit ([PRI-10–02, 2010]) . . . . . . . . . 5.3 X-750 Field Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.1 Destructive Examinations of X-750 Split Pins—Results and Remediation . . . . . . . . . . . . . . . .

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221 222 223 223 224

. . 225 . . 225 . . 226 . . 226 . . 230 . . 237 . . 242

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. . 287 . . 313 . . 323 . . 328 . . 338 . . 345 . . 355 . . 358 . . 358

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Contents

5.3.2

Destructive Examination of X-750 Clevis Bolts (Hyres 2014) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4 Destructive Examinations Related to Pressurizer Issues—Results and Remediation . . . . . . . . . . . . . . . . . . . . . 5.4.1 Destructive Examination of an Instrumentation Nozzle Leaking at First Outage . . . . . . . . . . . . . . . . 5.4.2 Destructive Examination of a Leaking Instrumentation Nozzle . . . . . . . . . . . . . . . . . . . . . . 5.4.3 Laboratory Analysis of a Pressurizer Safety Nozzle . 5.5 Destructive Examinations Related to Steam Generator Issues —Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1 Destructive Examination of a Leaking SG Blowdown Nozzle of a Framatome Unit . . . . . . . . . . . . . . . . . . 5.5.2 Destructive Examinations of Leaking SG Blowdown Nozzles of KHIC-CE Units (Chung 2007 (Hwang et al. 2008) [PRI-07–10] [PRI-08–06]) . . . . . . . . . . 5.5.3 Synthesis of the Steam Generator Channel Heads Destructive Examinations . . . . . . . . . . . . . . . . . . . . 5.5.4 Destructive Examination of a Steam Generator Inlet Nozzle Dissimilar Metal Weld . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Steam Generator Tubes, Plugs, Sleeves and Heat Exchangers . . 6.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 Materials Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Steam Generator Tubes Examinations—Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.1 Tubes with Primary Water Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.2 Tubes with OD Initiated Corrosion (IGSCC, IGA, TGSCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.3 Tubes with ID and OD Initiated Corrosion . . . . . . . 6.3.4 Tubes with Wear . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.5 Tube with Defects in the Tubesheet . . . . . . . . . . . . . 6.3.6 Tubes with Bulging Above the Tubesheet . . . . . . . . 6.3.7 Fatigue Cracking of U-bends (Boccanfuso et al. 2014b; Duisabeau et al. 2014) . . . . . . . . . . . . . . . . . 6.4 Steam Generator Tubes Plugs—Destructive Examination Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5 Steam Generator Tubes Sleeves—Destructive Examination of a Welded Sleeve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6 Steam Generators Blowdown Heat Exchangers Degradations in Operation (Praud et al. 2014) . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . 383 . . 391 . . 391 . . 395 . . 400 . . 408 . . 408

. . 414 . . 422 . . 459 . . 469 . . 471 . . 471 . . 475 . . 477 . . 477 . . . . .

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516 628 635 648 653

. . 661 . . 690 . . 720 . . 726 . . 737

Contents

7

Stress Corrosion Cracking of Cold Worked Stainless Steels . . . . 7.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2 Destructive Examinations—Results and Remediation . . . . . . 7.2.1 Destructive Examination of 2 Thermocouple Clamping Devices (Staples) . . . . . . . . . . . . . . . . . . 7.2.2 Destructive Examination of a Cracked Alloy A-286 Vent Valve Jackscrew (Fyfitch et al. 2014) . . . . . . . 7.2.3 Stress Corrosion Cracking of A286 Reactor Coolant Pump Turning Vane Bolts (Ickes and Ruminski 2019) . . . . . . . . . . . . . . . . . . . 7.2.4 Destructive Examination of New Replaced Pressurizer Instrumentation Nozzles . . . . . . . . . . . . . 7.2.5 Destructive Examination of a Leaking Pressurizer Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.6 Destructive Examination of 4 Failed Pressurizer Heaters (Thebault et al. 2011) . . . . . . . . . . . . . . . . . 7.2.7 Pressurizer Heater Failure Examination (Ruminski and Lisowyj 2013) . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.8 Destructive Examination of Reactor Coolant Pump Diffuser Studs (Shen et al. 2018) . . . . . . . . . . . . . . . 7.2.9 Synthesis of Destructive Examinations Carried Out on the Bolting of N4 Reactor Cooling Pumps . . . . . 7.2.10 Destructive Examination of 2 Leaking Tubes from a Chemical and Volume Control System Non-regenerative Heat Exchanger . . . . . . . . . . . . . . 7.2.11 Destructive Examination of 7 Tubes From a Retired Chemical and Volume Control System None Regenerative Heat Exchanger . . . . . . . . . . . . . . . . . 7.2.12 Destructive Examination of a Pressurizer Old Relief Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.13 Destructive Examination of a Steam Generator Inlet Nozzle Safe End . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Part II 8

xxix

. . 739 . . 739 . . 739 . . 739 . . 742

. . 748 . . 756 . . 761 . . 766 . . 775 . . 781 . . 786

. . 800

. . 807 . . 814 . . 820 . . 835

Stainless Steels Failures, Hydrogen Embrittlement, Boric Acid Corrosion, Hard Facing Materials and Fatigue Failures

Stainless Steels IASCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1 Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2 Destructive Examinations . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1 Destructive Examination of Core Lower Internals Bolts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2 Destructive Examination of a Core Lower Internals Bolt (Panait et al. 2014) . . . . . . . . . . . . . . . . . . . .

. . . 839 . . . 839 . . . 839 . . . 839 . . . 851

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Contents

8.2.3

Examination of Baffle-Former Bolts from a Westinghouse 4 Loop Unit (McKinley et al. 2013) 8.2.4 Destructive Examinations of RCCAs’ Rods Cladding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3 CGN Research Experiences on Magnetic Methods Used to Evaluate the Susceptibility of IASCC . . . . . . . . . . . . . . . 8.3.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2 Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3 Evaluation and Application . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

. . . 857 . . . 867 . . . . .

Stress Corrosion Cracking of Stainless Steel in Polluted Environment or in Occluded Conditions . . . . . . . . . . . . . . . . . . . 9.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 Reactor Pressure Vessel Head—Destructive Examinations Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.1 Destructive Examination of 2 End Cones of Thermocouple Columns . . . . . . . . . . . . . . . . . . . 9.2.2 Synthesis of Destructive Examinations of Canopy Seals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2.3 Destructive Examination of a Lower Omega Seal . . . 9.2.4 Destructive Examination of 2 Upper Omega Seals . . 9.2.5 Leak of Control Rod Drive Upper Housings . . . . . . 9.3 Reactor In-Core Instrumentation—Corrosion of the Guide Tubes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4 Pressurizer: Destructive Examination of a Leaking Pressurizer Heater Sleeve—Results and Remediation . . . . . . . . . . . . . . . 9.5 Piping: Destructive Examinations—Results and Remediation . 9.5.1 Stress Corrosion Cracking in Dead Legs . . . . . . . . . 9.5.2 Destructive Examination of a Reactor Vessel O-Ring Leak-Off Line First Example . . . . . . . . . . . . . . . . . . 9.5.3 Destructive Examination of a Reactor Vessel O-Ring Leak-Off Line—Second Example . . . . . . . . . . . . . . 9.5.4 Destructive Examination of a Reactor Vessel O-Ring Leak-Off Line—Third Example . . . . . . . . . . . . . . . . 9.5.5 Destructive Examination of a Reactor Vessel O-Ring Leak-Off Line—Fourth Example . . . . . . . . . . . . . . . 9.5.6 Destructive Examinations of Cross Over Legs Drain Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.7 Destructive Examinations of Leak-Off Lines of Valves Packing . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.8 Destructive Examination of a Safety Injection System Elbow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.9 Destructive Examination of a Leaking Socket Weld (Xu et al. 2011) . . . . . . . . . . . . . . . . . . . . . . . . . . .

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875 875 876 876 880

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885 895 904 910

. . 939 . . 945 . . 952 . . 952 . . 953 . . 959 . . 967 . . 977 . . 984 . . 998 . . 1008 . . 1013

Contents

xxxi

9.5.10 Destructive Examination of a Reactor Cooling System Cold Leg Sample Line . . . . . . . . . . . . . . . . . . . . . . . 9.5.11 Stress Corrosion Cracking of an Austenitic Stainless-Steel Pipe Weld (Ickes 2019) . . . . . . . . . . . 9.5.12 Small Bore Class 1 Piping Socket Weld Destructive Examination (Hosler et al. 2016) . . . . . . . . . . . . . . . . 9.5.13 Fracture Analysis for Clamp Bolt of Drainage Pipes of #4 Unit in CPR1000+ Nuclear Power Plant . . . . . . 9.5.14 Destructive Examination of Containment Spray System Pipes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.6 Valves: Destructive Examinations—Results and Remediation . 9.6.1 Destructive Examination of a Weld from a Drain Valve of a Crossover Leg . . . . . . . . . . . . . . . . . . . . . 9.6.2 Destructive Examination of the Body of a SEBIM Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.6.3 Destructive Examination of the Flange of a SEBIM Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7 Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.7.1 Laboratory Analysis of Reactor Coolant Pump Seals (Sullivan and Hyres 2011) . . . . . . . . . . . . . . . . . . . . 9.7.2 Fracture Analysis for APA Pump Bolts of Unit 2 in CPR1000+ Nuclear Power Plant . . . . . . . . . . . . . . 9.8 Heat Exchangers, Heaters—Destructive Examinations Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.8.1 Fatigue Failure of a Boron Recycle System Heater . . . 9.8.2 Destructive Examination of 2 Leaking Tubes from a CVCS Non-regenerative Heat Exchanger . . . . . . . . 9.8.3 Destructive Examination of 7 Tubes from a Retired CVCS None Regenerative Heat Exchanger . . . . . . . . 9.8.4 Laboratory Analysis of a Leaking Letdown Cooler (Hyres et al. 2017) . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Rupture and Stress Corrosion Cracking of Martensitic Stainless Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 Destructive Examination Results and Remediation . . . . . . . . 10.2.1 Destructive Examination of an Aged Pressurizer Valve Stem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.2 Destructive Examination of a Failed Reactor Cooling System Valve Stem . . . . . . . . . . . . . . . . . . . . . . . . 10.2.3 Destructive Examination of the 2SV-40 Pilot Valve Stem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.4 Destructive Examination of a Rockwell Valve Stem .

. 1022 . 1028 . 1034 . 1044 . 1055 . 1058 . 1058 . 1064 . 1071 . 1075 . 1075 . 1082 . 1091 . 1091 . 1097 . 1098 . 1098 . 1105

. . 1107 . . 1107 . . 1107 . . 1107 . . 1110 . . 1118 . . 1121

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10.2.5 Destructive Examination of a Shaft Sleeve from 1B Main Feedwater Pump Turbine . . . . . . . . . . . . . . . . . . 1129 10.2.6 Destructive Examination of Valve Nuts . . . . . . . . . . . . 1138 Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1142 11 Atmospheric Corrosion of Stainless Steel . . . . . . . . . . . . . . . . . 11.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 Destructive Examinations Results and Remediation . . . . . . . 11.2.1 Outlet Nozzles of the Reactor Pressure Vessel. Destructive Examination of 3 Specimens Harvested from 2 Dissimilar Metal Welds . . . . . . . . . . . . . . . 11.2.2 Inlet Nozzles of the Reactor Pressure Vessel. Destructive Examination of 5 Specimens Harvested from 2 Dissimilar Metal Welds . . . . . . . . . . . . . . . 11.2.3 Steam Generator Outlet Nozzle. Destructive Examination of 2 Specimens Harvested from the Dissimilar Metal Weld . . . . . . . . . . . . . . . . . . 11.2.4 Pressurizer Relief Valve Nozzle. Destructive Examination of a Specimen Harvested from the Dissimilar Metal Weld . . . . . . . . . . . . . . . . . . 11.2.5 Destructive Examination of Leaking NS Pipes . . . . 11.2.6 Destructive Examination of Containment Spray System Pipes . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2.7 Destructive Examination of a Valve Nut . . . . . . . . Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . 1143 . . . 1143 . . . 1143

. . . 1143

. . . 1148

. . . 1153

. . . 1157 . . . 1160 . . . 1165 . . . 1175 . . . 1178

12 Hydrogen Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.2 Destructive Examinations of Tie Rods and Remediation . . . . 12.2.1 Destructive Examination of 2 Failed RHR Supporting Tie Rods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.2.2 Destructive Examination of Failed Reactor Pit Aseismic Blocks Tie Rods . . . . . . . . . . . . . . . . . . . 12.2.3 Destructive Examination of Steam Generator Support Leg Tie Rods: Example #1 . . . . . . . . . . . . . . . . . . . 12.2.4 Destructive Examination of Steam Generator Support Leg Tie Rods: Example #2 . . . . . . . . . . . . . . . . . . . 12.2.5 Destructive Examination of Reactor Cooling Pump Support Leg Tie Rods . . . . . . . . . . . . . . . . . . . . . . 12.2.6 Conclusion, Remedial Actions . . . . . . . . . . . . . . . . . 12.3 Other Destructive Examinations . . . . . . . . . . . . . . . . . . . . . . 12.3.1 Failure Analysis of a Double-Headed Stud for EAS Spray Pump Connection in CPR1000+ Nuclear Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . 1179 . . 1179 . . 1179 . . 1179 . . 1183 . . 1188 . . 1193 . . 1201 . . 1203 . . 1207

. . 1207

Contents

12.3.2 Hydrogen Embrittlement Fracture of Bonnet Studs . . 12.3.3 Hydrogen Embrittlement Fracture of Diesel Fuel Filter Screws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.4 Hydrogen Embrittlement Fracture of Seawater Pump Cover Studs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Boric Acid Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2 Destructive Examinations Results and Remediation . . . . . . . . 13.2.1 Boric Acid Corrosion of 3 Reactor Coolant Pump Studs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.2 Wastage of 2 Reactor Coolant Pump Studs . . . . . . . 13.2.3 Boric Acid Corrosion of 2 Reactor Coolant Pump Bolts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.4 Search for Boric Acid Leaks of RCS and Associated Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.5 Examination of a Leaking Control Rod Drive Mechanism Along with Reactor Pressure Vessel Head Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Dead 14.1 14.2 14.3 14.4

Legs Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Relevant Systems and Components . . . . . . . . . . . . . . . . . . . Dead Leg Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . Destructive Examination of the First Isolating Component—Results and Remediation . . . . . . . . . . . . . . . . . 14.4.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.4.2 Safety Injection System . . . . . . . . . . . . . . . . . . . . . 14.4.3 Reactor Heat Removal System . . . . . . . . . . . . . . . . 14.4.4 Conclusion for the First Isolating Component . . . . . 14.5 Destructive Examination of the Second Isolating Component—Results and Remediation . . . . . . . . . . . . . . . . . 14.5.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.5.2 Safety Injection System . . . . . . . . . . . . . . . . . . . . . 14.5.3 Reactor Heat Removal System . . . . . . . . . . . . . . . . 14.5.4 Conclusion for the Second Isolating Component . . . 14.6 Analysis of the Degradation Phenomena and of the Influencing Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.6.1 Water Level Lines . . . . . . . . . . . . . . . . . . . . . . . . . 14.6.2 General Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . 14.6.3 Stress Corrosion Cracking . . . . . . . . . . . . . . . . . . . .

xxxiii

. . 1211 . . 1215 . . 1215 . . 1215 . . 1217 . . 1217 . . 1217 . . 1217 . . 1221 . . 1227 . . 1233

. . 1241 . . 1254 . . . .

. . . .

1255 1255 1256 1257

. . . . .

. . . . .

1258 1258 1258 1270 1272

. . . . .

. . . . .

1272 1272 1273 1273 1274

. . . .

. . . .

1275 1275 1275 1277

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14.7 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1279 Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1279 15 Hardfacing Materials Degradation . . . . . . . . . . . . . . . . . . . . . . . 15.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.2 Closure Valves, Destructive Examinations Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.3 Safety Injection Valve Destructive Examination Results . . . . 15.4 Reactor Coolant Pumps Shafts, Destructive Examination Results and Remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.4.1 Molds Taken on the Shaft Journal and on the Radial Bearing of a Reactor Coolant Pump . . . . . . . . . . . . 15.4.2 Destructive Examination of the Journal of a Reactor Coolant Pump Shaft . . . . . . . . . . . . . . . . . . . . . . . . Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Mechanical Fatigue Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2 Destructive Examinations . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.1 Destructive Examination of a Broken Control Rod . . 16.2.2 Destructive Examination of a Rod Cluster Control Assembly Stuck in Its Guide Tube . . . . . . . . . . . . . 16.2.3 Destructive Examination of 5 Thermal Barriers from Reactor Coolant Pumps of 3 Loop PWRs . . . . . . . . 16.2.4 Reactor Cooling Pump, Rupture of a Water Guide Bolt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.5 Reactor Cooling Pump, Fatigue Cracking of the Flow Nozzle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.6 Destructive Examination of an Impeller of a Containment Spray Pump . . . . . . . . . . . . . . . . . . . . 16.2.7 Destructive Examination of an Impeller of a Charging Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.8 Destructive Examination of Small-Bore Piping . . . . . 16.2.9 Destructive Examination of a Leaking Vent Valve . . 16.2.10 Destructive Examination of an RHR Drain Nozzle . . 16.2.11 Destructive Examination of a Manifold Cover Bolt . 16.2.12 Destructive Examination of a Leaking Boron Recycle System Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.13 Fatigue Failure of a Lower Adjusting Ring Pin of a Relief Valve . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.14 Fatigue Failure of 3 Control Rod Drive Shafts . . . . . 16.2.15 Synthesis of the Destructive Examination of Stationary Gripper Locking Screws and of Control Rod Drive Mechanism Housings . . . . . . . . . . . . . . .

. . 1281 . . 1281 . . 1281 . . 1299 . . 1309 . . 1309 . . 1316 . . 1324 . . . .

. . . .

1325 1325 1325 1325

. . 1331 . . 1336 . . 1359 . . 1363 . . 1369 . . . . .

. . . . .

1374 1380 1389 1392 1394

. . 1401 . . 1406 . . 1417

. . 1427

Contents

16.2.16 Fracture Analysis of Pipe on RIS System in CPR1000+ Nuclear Power Plant . . . . . . . . . . . . 16.2.17 Fatigue Failure of a Steam Closure Valve Stem . . . 16.2.18 Fatigue Failure of a Boron Recycle System Heater . 16.2.19 Failure Analysis of the Second-Last Stage Blade of the Low-Pressure Cylinder of Turbine #2 of CPR1000 Nuclear Power Plant . . . . . . . . . . . . . . . 16.2.20 Hydraulic Rod Fract-re and Loosen Cause Analysis of the Hydraulic Snubber H1VVP-514-102 in CPR1000+ Station . . . . . . . . . . . . . . . . . . . . . . . . 16.2.21 Examination of a Steam Generator Broken Ring—Example #1 . . . . . . . . . . . . . . . . . . . . . . . . 16.2.22 Examination of a Steam Generator Broken Ring—Example #2 . . . . . . . . . . . . . . . . . . . . . . . . 16.2.23 Steam Generator Feedwater Pipe Rupture . . . . . . . 16.2.24 Laboratory Analysis of a Leaking Pipe-to-Tube Adapter (Friant et al. 2013) . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

xxxv

. . . 1438 . . . 1442 . . . 1449

. . . 1454

. . . 1454 . . . 1454 . . . 1463 . . . 1465 . . . 1474 . . . 1483

17 Thermal Fatigue Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2 Destructive Examinations Results and Remediation . . . . . . . . 17.2.1 Reactor Coolant Pumps. Thermal Barrier. Housing Labyrinth Seal Cracking from Fatigue . . . . . . . . . . . 17.2.2 Destructive Examination of the Reactor Coolant Pump Thermal Barrier #57 . . . . . . . . . . . . . . . . . . . 17.2.3 Destructive Examination of a Leaking Thermal Barrier Coil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.4 Destructive Examination of a Reactor Coolant Pump Shaft and of Its Thermal Sleeve . . . . . . . . . . . . . . . 17.2.5 Destructive Examination of a Flow Nozzle Labyrinth (1300 MWe Unit) . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.6 Destructive Examination of a Flow Nozzle Labyrinth (1450 MWe Unit) . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.7 Leak of an Elbow of a Reactor Cooling System Auxiliary Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.8 Leak of a Weld Between a HPSIS Check Valve and a Reactor Cooling System Pipe . . . . . . . . . . . . . . . . . 17.2.9 Leak of a Pipe from a Reactor Cooling System Auxiliary Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.10 NDE Indications in a Pipe from a Reactor Cooling System Auxiliary Line . . . . . . . . . . . . . . . . . . . . . . 17.2.11 Destructive Examination of a Letdown Line Elbow . 17.2.12 Destructive Examination of a Chemical and Volume Control System Heat Exchanger . . . . . . . . . . . . . . .

. . 1485 . . 1485 . . 1485 . . 1485 . . 1486 . . 1491 . . 1502 . . 1508 . . 1517 . . 1529 . . 1539 . . 1544 . . 1553 . . 1559 . . 1561

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Contents

17.2.13 Destructive Examination of a Leaking Chemical and Volume Control System Regenerative Heat Exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.14 Leak of a Reactor Heat Removal Elbow . . . . . . . 17.2.15 Thermal Fatigue of Reactor Heat Removal Lines Downstream of the Heat Exchangers . . . . . . . . . . 17.2.16 Destructive Examination, of the RHR Mixing Tee #RRA 011TY of a 3-Loop Unit . . . . . . . . . . . . . 17.2.17 Destructive Examination of a Leaking Steam Generator Drain Nozzle . . . . . . . . . . . . . . . . . . . 17.2.18 Destructive Examination of Steam Generator Feedwater Piping . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Part III

. . . . 1567 . . . . 1573 . . . . 1591 . . . . 1598 . . . . 1606 . . . . 1616 . . . . 1622

Ageing, Irradiation Embrittlement, Wear, BWRs’ Failures, Balance of Plant Issues, Non-destructive Examination and Miscellaneous Issues

18 Thermal Ageing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2 Reactor Cooling System Cast Elbow Destructive Examinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2.1 Destructive Examination of Reactor Cooling System Cast Elbow #38C . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2.2 Destructive Examination of Reactor Coolant System Cast Elbow #49C . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2.3 Destructive Examination of Reactor Cooling System Cast Elbow #43C . . . . . . . . . . . . . . . . . . . . . . . . . . 18.3 Thermal Ageing of TIG Welded Joints in Primary Coolant Pipes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.4 Thermal Ageing of 17–4 PH (Precipitation Hardening) Stainless Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.4.1 Mechanism Identification . . . . . . . . . . . . . . . . . . . . 18.4.2 Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.4.3 Potentially Susceptible Components . . . . . . . . . . . . . 18.4.4 Mechanism Description . . . . . . . . . . . . . . . . . . . . . 18.4.5 Laboratory Investigations of X6CrNiCu17-04 . . . . . 18.4.6 Preventing Thermal Ageing of 17–4 PH . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . 1625 . . 1625 . . 1625 . . 1625 . . 1635 . . 1645 . . 1658 . . . . . . . .

. . . . . . . .

1673 1673 1673 1674 1674 1677 1684 1684

19 Irradiation Embrittlement of RPV Steel . . . . . . . . . . . . . . . . . . . . . 1685 19.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1685 19.2 Surveillance Capsules Mechanical Testing, Destructive Examinations Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1685

Contents

xxxvii

19.2.1 First Surveillance Capsule of a 4-Loop Unit . . . . . . . . 1685 19.2.2 All Surveillance Capsules of a 3-Loop Unit . . . . . . . . . 1690 Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1697 20 Boral™ Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.2 Destructive Examinations Results and Remediation . . . . . 20.2.1 Destructive Examination of 2 Spent Fuel Racks . 20.2.2 Destructive Examination of Replaced Spent Fuel Racks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . .

. . . .

. . . .

. . . .

. . . .

1699 1699 1701 1701

. . . . . 1706 . . . . . 1711

21 Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.2 Wear of Zircaloy-4 Grid Straps Due to Fretting and Periodic Impacting with RV Internals Baffle Plates (Davidsaver et al. 2011) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.3 Destructive Examinations Results and Remediation . . . . . . . . 21.3.1 Wear of a Rod Cluster Control Assembly . . . . . . . . 21.3.2 Broken Control Rod Destructive Examination . . . . . 21.3.3 Wear of 2 Rod Cluster Control Assembly Guide Tubes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.3.4 Destructive Examination of 8 RCCA Guide Tube Cards Harvested in 2013 and 2014 . . . . . . . . . . . . . 21.3.5 Wear of 2 Rods Control Assembly Drive Shafts . . . 21.3.6 RCCA Drive Shaft Wear Assessment . . . . . . . . . . . 21.3.7 Control Rod Drive Mechanism. Wear of Stationary and Movable-Gripper Latch Arms . . . . . . . . . . . . . . 21.3.8 Wear of the Alignment Pins of the Core Support Plate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.3.9 CRDM Thermal Sleeves’ Wear Assessment (ML18143B678, ML18198A275, ML18214A710 and ML18249A107) . . . . . . . . . . . . . . . . . . . . . . . . 21.3.10 Destructive Examination of 8 Thimble Tubes of the in-Core Instrumentation System . . . . . . . . . . . . . . . . 21.3.11 Destructive Examination of Four Thick Thimble Tubes of the in-Core Instrumentation System . . . . . . 21.3.12 Metallurgical Examination of a Boat Sample from Clevis Insert (Dubourgnoux et al. 2018) . . . . . . . . . 21.3.13 Reactor Coolant Pump Seal #2, Destructive Examination of Three Seal Rings Equipped with Graphite Provided by MERSEN . . . . . . . . . . . . . . . 21.3.14 Reactor Coolant Pump Seal #2, Destructive Examination of Four Seal Rings Equipped with Graphite Provided by USG . . . . . . . . . . . . . . . . . . .

. . 1713 . . 1713

. . . .

. . . .

1714 1720 1720 1726

. . 1736 . . 1743 . . 1755 . . 1761 . . 1767 . . 1773

. . 1777 . . 1783 . . 1792 . . 1801

. . 1807

. . 1814

xxxviii

21.3.15 Wear of the Stellite of a Valve . . . . . . . . . . . . . 21.3.16 Other Wear Events . . . . References . . . . . . . . . . . . . . . . . . . . .

Contents

Disk of a Swing Check . . . . . . . . . . . . . . . . . . . . . . . 1831 . . . . . . . . . . . . . . . . . . . . . . . 1836 . . . . . . . . . . . . . . . . . . . . . . . 1836

22 Miscellaneous Degradation Observations . . . . . . . . . . . . . . . . . . 22.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.2 Destructive Examinations Results and Remediation . . . . . . . . 22.2.1 Descriptive Catalogue of Defects Observed in Reactor Pressure Vessel and Reactor Pressure Vessel Head Flanges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.2.2 Destructive Examinations of Reactor Pressure Vessel Seals After Field Leak . . . . . . . . . . . . . . . . . . . . . . 22.2.3 Cavitation of a Reactor Heat Removal Divergent Nozzle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.2.4 Containment Building Liner Corrosion (Dunn et al. 2011; Gordon 2016; Ruminski 2016) . . 22.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 BWRs Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.1 BWRs Cracking History . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.2 Experiences of SCC in Low Carbon SS Components in Japanese BWRs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.2.1 Core Shroud SCC . . . . . . . . . . . . . . . . . . . . . . . . . 23.2.2 Primary Loop Recirculation Piping SCC . . . . . . . . . 23.2.3 Characteristics of SCC in Core Shroud and PLR Piping Made of Low Carbon SS . . . . . . . . . . . . . . . 23.2.4 SCC Mitigation Techniques for Core Shroud and Primary Loop Recirculation Piping . . . . . . . . . . . . . 23.3 Other Field Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.3.1 Review of Intergranular Cracking in Austenitic Stainless-Steel Components of BWR RPV-Internals (Roth 2014) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.3.2 BWR Core Shroud Off-Axis Cracking Inspection Experience (Lunceford et al. 2016) . . . . . . . . . . . . . 23.3.3 Root Cause Analysis of Cracking in Alloy 182 BWR Core Shroud Support Leg Cracks (Bjurman et al. 2017) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.3.4 Jet Pumps Issues (Markham 2016) . . . . . . . . . . . . . 23.3.5 BWR Instrument Penetration J-Groove Weld Examinations – NDE Development and On-site Examination Results (Flesner 2016) . . . . . . . . . . . . . 23.3.6 Failure Examination of an Austenitic Stainless Steel BWR Reactor Coolant Sampling Line (Ruminski 2016) . . . . . . . . . . . . . . . . . . . . . . . . . .

. . 1837 . . 1837 . . 1837

. . 1837 . . 1847 . . 1862 . . 1872 . . 1887 . . 1887 . . 1889 . . 1889 . . 1904 . . 1904 . . 1922 . . 1931 . . 1932 . . 1935

. . 1935 . . 1942

. . 1947 . . 1953

. . 1961

. . 1967

Contents

xxxix

23.3.7 Investigations of a Type 316L Steam Dryer Plate Material Suffering from IGSCC after Few Years in BWR’s (Autio et al. 2014) . . . . . . . . . . . . . . . . . 23.3.8 Laboratory Analyses of Two Leaking Decontamination Ports (Habib et al. 2013) . . . . . . . . 23.3.9 IGSCC in a BWR Steam Line After 30 Years of Operation (Ehrnstén et al. 2015) . . . . . . . . . . . . . 23.3.10 Admiralty Brass Main Condenser Tube Degradation at Fitzpatrick (Bock et al. 2015) . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Review of Non-destructive Testing Techniques Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . 24.1 Background . . . . . . . . . . . . . . . . . . . . . . 24.2 Visual Test . . . . . . . . . . . . . . . . . . . . . . . 24.3 Acoustic Emission . . . . . . . . . . . . . . . . . 24.4 Infrared Thermography . . . . . . . . . . . . . . 24.5 Leak Detection . . . . . . . . . . . . . . . . . . . . 24.6 Dye Penetrant Test . . . . . . . . . . . . . . . . . 24.7 Magnetic Particle Test . . . . . . . . . . . . . . . 24.8 Eddy Current Testing . . . . . . . . . . . . . . . 24.9 Replicas . . . . . . . . . . . . . . . . . . . . . . . . . 24.10 Radiography Test . . . . . . . . . . . . . . . . . . 24.11 Ultrasonic Testing . . . . . . . . . . . . . . . . . . 24.12 ThermoElectrical Power . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . 1971 . . 1978 . . 1989 . . 1993 . . 1999

Used in LWRs . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

25 Balance of Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.1 BOP Example (CP2 Series, 900 MWe, 3 Loops, French Fleet) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.2 Component Cooling System . . . . . . . . . . . . . . . . . . . . . . . . 25.2.1 Destructive Examination of Component Cooling System Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.2.2 Optimizing the Maintenance of Component Cooling System Heat Exchangers with Brass Tubes Through a Better Knowledge of Degradations (Mayos et al. 2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.3 Steam and Water Circuits . . . . . . . . . . . . . . . . . . . . . . . . . . 25.3.1 Steam Generator Blowdown Heat Exchanger Leak . . 25.3.2 Cracking in the Auxiliary Steam Generators Feedwater System . . . . . . . . . . . . . . . . . . . . . . . . . 25.3.3 Corrosion-Erosion in Low-Pressure Reheater . . . . . . 25.3.4 Feedwater Pump Sleeves Stress Corrosion Cracking . 25.3.5 Cracks Detected in an Essential Service Water System/Component Cooling System Plate Type Heat Exchanger . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . . . . .

2001 2001 2002 2003 2004 2006 2010 2012 2015 2021 2022 2025 2033 2035

. . 2037 . . 2037 . . 2039 . . 2039

. . 2046 . . 2057 . . 2057 . . 2059 . . 2061 . . 2063

. . 2065

xl

Contents

25.3.6 Leaking Essential Service Water System/Component Cooling System Plate Type Heat Exchanger . . . . . . 25.3.7 Rust Discovered Into an Essential Service Water System/Component Cooling System Plate Type Heat Exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.3.8 Raw Water System/Conventional Island Closed Cooling Water System Plate Type Heat Exchanger . 25.3.9 Component Cooling Heat Exchanger Leaks . . . . . . . 25.3.10 Venturis Examinations and Inspection Strategy (Chavat et al. 2018) . . . . . . . . . . . . . . . . . . . . . . . . 25.3.11 Flow-Assisted Corrosion of High-Pressure Feed Water Heat Exchangers Low Carbon Steel Tubes (Coste and Rousvoal 2018) . . . . . . . . . . . . . . . . . . . 25.3.12 Examination of Cracks in Pressure Sensing Lines of the Feedwater System and the Strategy of NPP Goesgen for Replacement (Wermelinger and Schinhammer 2019) . . . . . . . . . . . . . . . . . . . . . . . . 25.3.13 Some MSRs Issues . . . . . . . . . . . . . . . . . . . . . . . . . 25.3.14 Feedwater Heaters Drain Recovery System Erosion-Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . 25.3.15 Other FAC Events (Gordon 2016) . . . . . . . . . . . . . . 25.3.16 Hydraulic Rod Fracture and Loosen Cause Analysis of the Hydraulic Snubber H1VVP-514-102 in CPR1000+ Station . . . . . . . . . . . . . . . . . . . . . . . . . 25.4 Condenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.4.1 2013 Destructive Examination of a Brass Condenser Tube, from a Four-Loop Plant . . . . . . . . . . . . . . . . . 25.4.2 2016 Destructive Examination of a Brass Condenser Tube, from a Four-Loop Plant . . . . . . . . . . . . . . . . . 25.4.3 Destructive Examination of Titanium Condenser Tubes from a Three-Loop Plant . . . . . . . . . . . . . . . . 25.4.4 Brass Tubes with Erosion . . . . . . . . . . . . . . . . . . . . 25.4.5 Comparison Between Titanium and Stainless-Steel Tubes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.4.6 Titanium Tubes Exhibiting OD Wear . . . . . . . . . . . 25.4.7 Leaking Ferritic Stainless-Steels Tubes . . . . . . . . . . 25.4.8 Leaking Brass Tubes . . . . . . . . . . . . . . . . . . . . . . . 25.4.9 Arsenical Cartridge Brass Tubes with Erosion . . . . . 25.4.10 Leaking Arsenical Cartridge Brass Tubes . . . . . . . . . 25.4.11 Leaking Titanium Tubes . . . . . . . . . . . . . . . . . . . . . 25.4.12 Tubesheet General Corrosion . . . . . . . . . . . . . . . . . 25.4.13 Channel Head with Rust . . . . . . . . . . . . . . . . . . . . .

. . 2067

. . 2069 . . 2071 . . 2073 . . 2075

. . 2082

. . 2093 . . 2098 . . 2105 . . 2107

. . 2112 . . 2123 . . 2123 . . 2134 . . 2149 . . 2171 . . . . . . . . .

. . . . . . . . .

2173 2174 2176 2178 2180 2181 2183 2186 2188

Contents

25.5 Raw and Raw-Service Water . . . . . . . . . . . . . . . . . . . . . . . . 25.5.1 Galvanic Corrosion of Rubber Lined Service Water Pipes Adjacent to Titanium Heat Exchangers (Matthews 2013) . . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.2 Destructive Examination of Leaking Pipe Segments 4 SEC 004 TY and 4 SEC 002 TY . . . . . . . . . . . . . 25.5.3 Destructive Examination of Non-leaking Pipe Segment 3 SEC 002 TY . . . . . . . . . . . . . . . . . . . . . 25.5.4 Destructive Examination of a Leaking Rolled and Welded Pipe 2 SEC 002 TY Located Downstream the Support SE-11 . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.5 Destructive Examination of Two Pipes 4 SEC 020 SF and 4 SEC 021 SF . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.6 Hydrogen Embrittlement Fracture of Seawater Pump Cover Studs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.7 Study of the Impact of Chemical Cleaning on Essential Service Water System Pipes . . . . . . . . . . . 25.5.8 Destructive Examination of a Rotating Drum Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.9 Cavity Corrosion Into a Firefighting System . . . . . . 25.5.10 Microbially Induced Corrosion in Firefighting Systems—Experience and Remedies (Ehrnstén et al. 2017) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.5.11 Some Buried Piping Issues (Gordon 2016) . . . . . . . 25.6 Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.6.1 Fabrication Defects in a Steam Header . . . . . . . . . . 25.6.2 Thermal Fatigue of an Inlet Valve . . . . . . . . . . . . . . 25.6.3 Shrunk Low Pressure Disks Cracking . . . . . . . . . . . 25.6.4 Low Pressure Disk Cracking . . . . . . . . . . . . . . . . . . 25.6.5 Static Blades Cracking . . . . . . . . . . . . . . . . . . . . . . 25.6.6 Low Pressure Blades Cracking . . . . . . . . . . . . . . . . 25.6.7 Failure Analysis of the Second-Last Stage Blade for the Low-Pressure Cylinder Turbine #2 of a CPR1000 Nuclear Power Plant . . . . . . . . . . . . . . . . . . . . . . . . 25.6.8 Stud Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.7 Main Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.7.1 Stator Hollow Conductor Clogging . . . . . . . . . . . . . 25.7.2 Stator Bar Failure . . . . . . . . . . . . . . . . . . . . . . . . . . 25.7.3 Stator Hydrogen Leak, Example #1 . . . . . . . . . . . . . 25.7.4 Stator Hydrogen Leak, Example #2 . . . . . . . . . . . . . 25.7.5 Rotor Binding Corrosion . . . . . . . . . . . . . . . . . . . . . 25.7.6 Rotor Binding Cracking . . . . . . . . . . . . . . . . . . . . . 25.7.7 Rotor Rear Bearing Thermal Fatigue . . . . . . . . . . . .

xli

. . 2190

. . 2190 . . 2197 . . 2205

. . 2212 . . 2216 . . 2222 . . 2225 . . 2247 . . 2277

. . . . . . . . .

. . . . . . . . .

2279 2285 2288 2288 2291 2293 2296 2298 2300

. . . . . . . . . .

. . . . . . . . . .

2303 2313 2316 2316 2318 2321 2323 2325 2326 2328

xlii

Contents

25.7.8 Rotor Seizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.7.9 Connection Flanges Cracking . . . . . . . . . . . . . . . . . 25.7.10 Hydrogen Cooler FAC . . . . . . . . . . . . . . . . . . . . . . 25.8 Diesels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.8.1 Destructive Examination of the First MIBA Generation of Connecting Rods Bush Bearings of Emergency Diesels . . . . . . . . . . . . . . . . . . . . . . . 25.8.2 Destructive Examination of the Second MIBA Generation of Connecting Rods Bush Bearings of Emergency Diesels . . . . . . . . . . . . . . . . . . . . . . . 25.8.3 Hydrogen Embrittlement Fracture of Diesel Fuel Filter Screws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.8.4 Cracking of the Space Bridging the Valves of Diesel Engines Cylinder Heads of the 900 MWe Fleet . . . . 25.9 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25.9.1 Destructive Examination of an Air Compressor Rotor Blade of a Combustion Turbine . . . . . . . . . . . . . . . 25.9.2 Combustion Turbine; Characterization of Leading Row Blades and of the Stator, Compressor Side (Solders) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . .

. . . .

2330 2332 2334 2337

. . 2337

. . 2341 . . 2354 . . 2364 . . 2375 . . 2375

. . 2380 . . 2387

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2389

About the Author

François Cattant graduated in chemical engineering in 1974 and joined Electricity of France (EDF) in 1975 as a chemical engineer in the Plant Operation Division working on the water and steam conditioning of power plants. Two years later, he moved to the hot laboratory at the Chinon Nuclear Power Plant to examine failures and do root cause analysis of gas-cooled reactor components, including fuel. In 1980, he became the manager of a regional section for water and steam chemistry, chemical cleaning and non-destructive examination in fossil stations. He returned to the Chinon hot laboratory 3 years later where he continued to focus on failure root cause analysis of irradiated or contaminated components, monitoring of reactor pressure vessel (RPV) irradiation programs, examination of steam generator tubes, RPV head penetrations, split pins, pressurizer nozzles, valves, reactor cooling system cast elbows, piping, fuel bundle and rods, rod cluster control assemblies and much more. During 1995–1998, he was assigned as an expatriate engineer the Nuclear Maintenance Application Center of the Electric Power Research Institute in the USA where he worked on nuclear plant maintenance issues. While at EPRI, he also participated as an outside expert on the examination of Ringhals 3 retired steam generator Returning back in France in 1998, François joined EDF R&D Materials and Mechanics of Components Department as a scientific advisor and senior engineer. His work involved chemistry, corrosion, and metallurgy with special attention to primary water chemistry, source

xliii

xliv

About the Author

term reduction, primary water corrosion, corrosion mitigation and repair, fuel cleaning and innovation strategies. He continued to serve as the EDF representative to the EPRI’s Materials Reliability Program. In this capacity, he participated in several destructive examinations such as North Anna Unit 2 RPV head penetrations, South Texas Project Unit 1 Bottom Mounted Instrumentation, Braidwood Unit 1 pressurizer heater #52 and San Onofre Unit 3 CEDM #64. From 2004 to 2008, he was the President of the “Materials, Non-Destructive Testing and Chemistry” section of the “French Nuclear Energy Society” and from 2008 to 2009 he was in charge of the International Partnerships of the Materials Ageing Institute (MAI). Subsequent to his retirement from EDF in 2009, he was commissioned by the MAI to collect details and produce summaries of destructive examinations performed on failures in light water reactor components in France, USA, Japan and Sweden which have now been compiled in this unique handbook. In 2014, the French Nuclear Energy Society awarded its “Grand Prix” to this “Handbook of Destructive Assays”. Ten years later, the MAI asked him to update this handbook, with both domestic and international recent field experience.

Acronyms

ABWR ADG AFNOR AFS AISI ALARA ANG APA APG appm ARE ARMS ASME ASTM ATEM AVB AVT B&PV BAC BCC BFB BMI BMV BSE BWR BWRVIP CCS

Advanced Boiling Water Reactor Bâche Alimentaire et DéGazeur—Feedwater Tank and Gas Stripper System Association Française de NORmalisation Auxiliary Feedwater System American Iron and Steel Institute As Low As Reasonably Achievable Eau alimentaire normale—Main feedwater system (obsolete) Motor driven feedwater pump system Purges de générateurs de vapeur—Steam Generator Blowdown System atoms parts per million Régulation du débit d’eau alimentaire—Feedwater Flow Control System Airborne Radioactivity Monitoring System American Society of Mechanical Engineers American Society for Testing and Material Analytical Transmission Electron Microscopy Anti-Vibration Bar All Volatile Treatment Boilers and Pressure Vessels Boric Acid Corrosion Body Cubic Centered Baffle Former Bolt Bottom Mounted Instrumentation Bare Metal Visual Back Scatter Electron Boiling Water Reactors BWR Vessel and Internals Project Components Cooling System

xlv

xlvi

CE CEDM CEX CF CGN CGNPC CGR CL CMTR CRD CRDM CRF CS CSS CT CVCS CVI CW DAB DE DEL DIC DM DN DO dpa EAC EAF EAS EBSD ECCS ECP ECT EDF EDM EDS EFPY EMAT EOC EPMA EPR EPRI

Acronyms

Combustion Engineering Control Element Drive Mechanism Extraction Condenseur—Condensate extraction system Corrosion Fatigue China General Nuclear China General Nuclear Power Corporation Crack Growth Rate Cold Leg Certified Material Test Report Control Rod Drive Control Rod Drive Mechanism Eau de Circulation (= Circulating Water System) Carbon Steel Containment Spray System or Core Support Shield Compact Tension Chemical and Volume Control System Vide du Condenseur—Condenser vacuum system Cold Work Dispositif Auto Bloquant (locking device for steam generators) Destructive Examination Electrical building chilled water system Differential Interference Contrast DissiMilar (weld) Diamètre Nominal—Nominal Diameter Dissolved Oxygen displacement per atom Environmentally Assisted Cracking Environmentally Assisted Fatigue Containment spray system Electron Back Scatter Diffraction Emergency Core Cooling System Electro-Chemical Potential Eddy Current Testing Electricité de France Electrical Discharge Machining Energy Dispersive Spectroscopy Effective Full Power Year Electro Magnetic Acoustic Transducer End Of Cycle Electron Probe for Micro Analysis Electrochemical Potentiokinetic Reactivation or European Pressurized Reactor Electric Power Research Institute

Acronyms

ESBWR ESWS ET FAC FATT FBR FCC FEA FFWS FIV FME FW FWST GBC GDOS GE GEH GTAW HAZ HE HFR HL HP HPSIS HR HW HX IASCC ICI ID IDSCC IGA IGSCC IHSI IR ISI IT IVVI LAS LOCA LOF LOM LOMI

xlvii

Economic Simplified Boiling Water Reactor Essential Service Water System Eddy current Test Flow-Assisted Corrosion Fracture Appearance Transition Temperature Fast Breeder Reactor Face Cubic Centered Finite Element Analysis Fire Fighting Water System Flow-Induced Vibrations Foreign Material Exclusion Feed Water Fuel pool (refueling) Water Storage Tank Grain Boundary Coverage Glow Discharge Optical Spectroscopy General Electric General Electric Hitachi Gas Tungsten Arc Welding Heat-Affected Zone Hydrogen Embrittlement High Flux Reactor Hot Leg High-Pressure High Pressure Safety Injection System Hot Roll Hot Work Heat eXchanger Irradiation-Assisted Stress Corrosion Cracking In Core Instrumentation Inside Diameter Inter-Dendritic Stress Corrosion cracking Inter-Granular Attack Inter Granular Stress Corrosion Cracking Induction Heating Stress Improvement Infra Red In Service Inspection Infrared Thermography In-Vessel Visual Inspection Low Alloy Steel Loss Of Cooling Accident Lack Of Fusion Light Optical Microscope Low Oxidation Metal Ion

xlviii

LRO LRSS LWR MA MIC MPT MSR MSS MTR NDE NDT NPP NS NSS NSSS NWC OD ODSCC OES PAG PIA PLR ppb ppm PT PVC PWR PWSCC RBMWS RCCA RCC-M RCP RCS RCV REN RFEC RFO RHR RHRS RIS

Acronyms

Long-Range Order Lower Radial Support System Light Water Reactor Mill Annealed Microbial-Induced Corrosion Magnetic Particle Testing Moisture Separator Reheater Main Steam System Material Test Report Non-Destructive Evaluation/Examination Non-Destructive Testing or Nil Ductility Temperature Nuclear Power Plant Nuclear Systems Nuclear Sampling System Nuclear Steam Supply System Normal Water Chemistry Outside Diameter Outside Diameter Stress Corrosion Cracking Optical Emission Spectroscopy Preferential Absorption Gliding Post-Irradiation Annealing Primary Loop Recirculation (piping) Parts Per Billion parts per million Penetrant Test PolyVinyl Chloride Pressurized Water Reactor Primary Water Stress Corrosion Cracking Reactor Boron and Makeup Water System Rod Cluster Control Assembly Régles de Construction et de Conception des Matériels mécaniques Circuit Primaire du Réacteur—Reactor Coolant System or Reactor Coolant Pump Reactor Cooling System or Refroidisseur des Condensats Surchauffeurs (cooling of MSRs’ condensates) contrôle Chimique et Volumétrique du Réacteur—Chemical and Volume Control System Echantillonnage Nucléaire du Réacteur—Nuclear Sampling System Remote Field Eddy Current ReFueling Outage Reactor Heat Removal Reactor Heat Removal System Radiation-Induced Segregation or Injection de Sécurité du Réacteur— Safety Injection System

Acronyms

RPV RPVH RRA RRI RSE-M RT RTNDT RV RVH RWST SAW SCC SCE SE SEC SEM SENB SENT SG SGBS SGR SHE SI SIPA SIPN SIS SMAW SNPI SRO SSRT STR TEM TEP TGSCC TIG TOFD TSP TT TW UT UTS VSM

xlix

Reactor Pressure Vessel Reactor Pressure Vessel Head Refroidissement du Réacteur à l’Arrêt—Residual Heat Removal System Réfrigération Intermédiaire—Component Cooling System Règles de Surveillance en Exploitation des Matériels Mécaniques Radiography Test Reference Temperature for Nil Ductility Transition Reactor Vessel Reactor Vessel Head Refueling Water Storage Tank Submerged Arc Welding Stress Corrosion Cracking Saturated/Standard Calomel Electrode Secondary Electron Eau brute Secourue (= ESWS) Scanning Electron Microscope/Microscopy Single-Edge Notched Bending Single-Edge Notched Tensile Steam Generator Steam Generator Blowdown System Steam Generator Replacement Standard Hydrogen Electrode Structural Integrity Stress-Induced Preferential Absorption Stress-Induced Preferential Nucleation Safety Injection System Shielded Metal Arc Welding Suzhou Nuclear Power research Institute Short-Range Order Slow Strain Rate Test TRansformateur de vapeur—Steam transformer system Transmission Electron Microscope/Microscopy Thermo-Electric Power TransGranular Stress Corrosion Cracking Tungsten Inert Gas (welding) Time-Of-Flight Diffraction Tube Support Plate Thermal Treatment Through Wall Ultra-sonic Testing Ultimate Tensile Strength Vibrating Sample Magnetometer

l

VT VTT VVER VVP WPS WWER YS

Acronyms

Visual Testing Valtion Teknillinen Tutkimuskeskus (Finnish: Technical Research Centre of Finland) Voda-Vodyanoi Energetichesky Reaktor Main Steam System Warm Prestress Shock Water–Water Energy Reactor Yield Strength

Part I

Fundamentals, Degradation Mechanisms, Failures of Nickel Alloys, Heat Exchangers and Cold Worked Stainless Steels

Chapter 1

Introduction

From the end of the 60’s, LWRs have extensively been used in many countries around the world for electricity production. As in many other industrial facilities, some components failures have occurred during operation. This Handbook captures the results of some typical destructive examinations that have been carried out to understand and furthermore mitigate these failures. This Handbook is specific to PWRs from Western design, however, some information on the history of BWRs failures along with some examples are also provided. Furthermore, the materials addressed here are metallic materials, with a focus on the materials for which at least one example of destructive examination is presented in the Handbook. Note also that the treatment of fuel (and by extension the zirconium alloys) are out of the scope of this Handbook. The Handbook is organized by chapters. Following the introduction, the second chapter presents some LWRs basics. The third chapter gives some insights into the relevant failure mechanisms. Next, some properties of the materials having experienced field failures are presented. Regarding materials characteristics, the reference [Materials Handbook for Nuclear Plant Pressure Boundary Applications (2019). EPRI, Palo Alto, CA: 2019. 3,002,016,000.] has provided valuable information. The destructive examinations results are sorted by the main field material issues such as: • • • • • • •

Ni alloys PWSCC; SG tubes issues; Cold work SS SCC; SS IASCC; SS SCC in polluted environment or in occluded areas; Martensitic steels rupture and SCC; SS atmospheric corrosion;

© Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_1

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• • • • • • • • • • • • • •

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Introduction

Hydrogen embrittlement; Boric acid corrosion; Dead legs issues; Hard facing materials degradation; Mechanical fatigue failure; Thermal fatigue failure; Thermal ageing; Irradiation embrittlement; Boral® corrosion; Wear; Miscellaneous; BWRs cracking; NDT techniques; Balance Of Plant.

The SG tubes bundle has a dedicated chapter because the SG has always been given special attention in the industry, for many reasons including the large variety of degradation it has experienced and its significant impact on plant operation (especially on outages duration). The last chapter will be the conclusion.

Chapter 2

Fundamentals of Light Water Reactors

2.1

Background

Light water reactors are of two types, the pressurized water reactors and the boiling water reactors. In the pressurized water reactors, the water cooling the core is kept liquid under high pressure, whereas in the boiling water reactors, the core is cooled by a mixture of water and steam. As a consequence, in a pressurized water reactor, the steam driving the turbine is generated by steam generators whereas in the boiling water reactors, the turbine is driven by the steam generated from the core. More details on these two types of reactors are provided hereafter.

2.2

Basics of Pressurized Water Reactors

Figure 2.1 shows an overview of a typical modern PWR. The condenser is generally cooled by sea, brackish, or river water. However, in this latter situation, when the river flow is too low, cooling towers are used as shown on the picture. Figure 2.2 shows the main plant systems used in normal operation. The flow of primary water (yellow) is maintained by the pressurizer and flowed through the RCS by Reactor Coolant Pumps. The typical RCS water conditions are: • High temperature: between 285 (545 °F, cold leg, reactor pressure vessel inlet) and 325 °C (617 °F, hot leg, reactor pressure vessel outlet); • High pressure: around 155 bars (2248 psi); • Reducing environment for water radiolysis mitigation by hydrogen injection (typically: 30 cc/kg); • Presence of boric acid for the neutronic reaction control. The primary water pH 300 °C is typically adjusted to 7.2 by way of lithium hydroxide injection (a few ppm maximum). © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_2

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Stack

Containment building

Turbine hall

Cooling Tower Transformer Diesel generator

Spent fuel building

Nuclear auxiliary building

Fig. 2.1 Sketch of a PWR presenting the main buildings and facilities (courtesy of EDF)

Containment building

Turbine hall MSR

River

CCS

RHR

ESWS Main generator

Condenser

RCS CVCS

Heat exchanger Cooling tower

RBMWS

Feed water

Fig. 2.2 Main systems used in normal operation (EDF courtesy)

River

2.2 Basics of Pressurized Water Reactors

7

Sometimes, zinc is also added to the RCS either for PWSCC mitigation or for dose reduction, or both. The RCS heat energy is exchanged with the secondary circuit through the steam generator tubes. The secondary water (dark blue) is heated to steam (light blue) which powers the high pressure and low-pressure turbines which turn the main generator for electricity production. The steam is then condensed to water and flows back to the steam generators. For thermodynamic considerations (cycle efficiency), the water is steam-heated before entering the steam generator and the steam is dried and reheated between the high- and low-pressure turbines in the MSRs. At the steam generator outlet, the typical steam conditions are: • Temperature: 286 °C (547 °F); • Pressure: 70 bars (1015 psi). For corrosion and flow assisted corrosion control, the secondary water pH 25 °C is adjusted between 9.1 and 9.8 (depending on the condenser tubes material) using ammonia or various amines such as morpholine, ethanolamine. There are hundreds of various systems in a PWR; some related to the primary circuit are indicated on Fig. 2.2: • RCS: in this system, the pressurized water is heated in the radioactive core and cooled in the steam generators; • CVCS: this system handles the RCS water volume variations, especially during heat up where the water density drops from 1 (room temperature) to about 0.7 (at operation temperature). This system is also used for the RCS chemical conditioning; • RBWMS: this system provides the boron and the water to the CVCS; • RHR: the main usage of this system is the removal of the core decay heat during outages; • CCS: many equipments or components need to be cooled either in operation (i.e.: Reactor Coolant Pumps) or during outage (i.e.: RHR heat exchangers), this is the role of the CCS; • ESWS: this system provides raw cooling water for a large variety of systems or equipments heat exchangers. As shown on Figs. 2.3, 2.4 and 2.5, there are some NSSS design variations depending on the vendor. Another type of PWRs but with major design differences as compared to the hereabove ones is the VVER reactors. VVER reactors are composed of two major series: the VVER-400 units and the VVER-1000 and VVER-1200 units. The main components of all VVER units are constructed using similar materials. The surfaces of the primary circuit in contact with the primary coolant are either made from stainless steel or low alloy steel and carbon steel weld clad with stainless steel. Stainless steel components are normally made from a titanium-stabilized stainless steel, whilst the reactor pressure vessels are weld clad in a niobium-stabilized

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Fig. 2.3 Typical design of Westinghouse1 and Areva NSSSs. The number of primary loops and associated recirculating SGs can be of 2 (Westinghouse), 3 (Westinghouse and Areva) or 4 (both vendors too). The plant electrical output can range from 500 to 1200 MWe for Westinghouse units and from 900 to 1500 MWe for Areva units

stainless steel. With the exception of the Loviisa units, VVER plants do not use components or valves having Stellite®. Thirty-six VVER-440 MWe units have been built. There are two basic VVER440 designs. These are the first generation WWER-440 s, which includes the initial V-179 design, the V-230 design and the V-270 design with enhanced seismic features. The second generation WWER-440 is standard V-213 design with a full accident confinement system (Fig. 2.6). The primary circuit of all the VVER-440 units has six loops, all of which have two main loop isolation gate valves that enable the steam generators and main coolant pumps to be isolated from the reactor pressure vessel (Fig. 2.7).

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Materials Reliability Program: Generic Guidance for Alloy 600 Management (MRP-126), EPRI, Palo Alto, CA: 2004. 1,009,561.

2.2 Basics of Pressurized Water Reactors

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Fig. 2.4 Typical design of Combustion Engineering1 NSSS. Whatever the reactor power, there are only 2 hot primary loops and associated recirculating SGs but 4 cold legs with as many RCPs. The plant electrical output can range from 500 to 1300 MWe

There are a number of VVER-1000 variants, the initial prototype V-187 design, the V-302 and V-338 designs and standard V-320 design. The new export V-392, V-428, V-466, V-412 variants have enhanced safety features, but are otherwise similar to the V320 design. All the WWER-1000 units have a full containment building (Fig. 2.8). All the VVER-1000 MWe units have four primary coolant loops (Fig. 2.9). The early designs were fitted with two isolation gate valves that are fitted to the hot and cold legs of each loop, one between the RPV and SG and one between the RPV and main coolant pump. One of the main differences between the vertical recirculating steam generators and the VVER generators is that the tubes are vertical for recirculating (and once-through) steam generators whereas they are horizontal in VVERs (Figs. 2.10 and 2.11). 08X18H10T stainless steel (08Cr18Ni10Ti, AISI 321) is used for the core structures, main coolant pumps and steam generator tubing, whilst the main loop pipework and steam generator collectors are made from type 10GN2MFA carbon steel, clad internally with 08Cr18Ni10T stainless steel. The pressurizer is also made from 10GN2MFA carbon steel, clad with an inner layer of Sv-07Cr25Ni13 (similar

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Fig. 2.5 Typical design of Babcock and Wilcox1 NSSS. There are 2 hot primary loops and associated once through SGs and 4 cold legs with as many RCPs. The plant electrical output is around 900 MWe

1 4 7 10 13 16

Reactor pressure vessel Cooling pond Reactor Air trap Condenser Preheater

2 5 8 11 14 17

Steam generator Biological shield Localization tower Aerator Turbine hall Turbine Hall Extract

Fig. 2.6 Cross section of a VVER-440 V-213 unit

3 6 9 12 15 18

Refuelling machine Emergency feedwater system Bubbler trays Turbine Deaerator-feedwater tank Control and instrument room

2.2 Basics of Pressurized Water Reactors

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Fig. 2.7 Layout of a VVER-440 V-213 confinement area

1 3 5

Horizontal steam generator Containment building Control rod assemblies

Fig. 2.8 VVER-1000 V-320 containment building layout

2 4 6

Reactor coolant pump Refuelling crane Reactor vessel.

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Fig. 2.9 Layout of VVER-1000 V-320 primary circuit

Fig. 2.10 PGV-1000 steam generator used in VVER-1000 plants

to AISI 309) stainless steel and two layers of Sv-08Cr19Ni10Mn2Nb niobium stabilized stainless steel (similar to AISI 347). The reactor pressure vessel and head is made from the low alloy steel 15Cr2MNFA, also clad with an inner layer of Sv-07Cr25Ni13 stainless steel and two layers of the niobium stabilized stainless steel Sv-04Cr20Ni10Mn2Nb (again similar to AISI 347). Small amounts of other grades of stainless steel and ferritic stainless steel are also present in the core internal structures, but no Stellite® hard facing alloys are present in the primary or auxiliary circuits.

2.2 Basics of Pressurized Water Reactors

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Fig. 2.11 Cut-away view of a VVER PGV-1000 SG showing the tubes and collectors

Although optimized, the water and steam environments are still harsh enough to pose threat to the systems materials, at times leading to corrosion failures. Mechanical loads can also result in mechanical failures, sometimes in conjunction with corrosion like corrosion fatigue.

2.3

Basics of Boiling Water Reactors

Although this Handbook primarily addresses PWR NSSS failures, it is worthwhile to present some BWR materials events as some of these failures are also relevant to PWRs. As shown in this document, some degradation mechanisms are common to PWRs and BWRs (i.e.: IASCC). Moreover, there are a certain number of PWR materials failures for which an oxidizing environment is suspected to be responsible for the cracking (i.e.: areas where oxygen may be trapped at outages, such as CRDMs). In 2018, according to the IAEA, there were 75 operating BWRs worldwide (Table 2.1); the most popular design being the GE design, the following BWRs description will be based on this specific design.

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Figure 2.12 presents the BWR power cycle. Basically, BWR has a lower RPV pressure and simplified steam cycle as compared to PWR. The RPV pressure is around 7 MPa (1,020 psig). The temperature in the RPV reaches 288 °C (550 °F). Table 2.1 World operating BWRs Number of BWRs Source GE

North America

Europe

Asia

Total

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75

Reactor Vessel Moisture Separator Reheater

Main Steam

Low Pressure Turbine Generator

Feedwater

Suppression Pool

High Pressure Turbine

Condenser

Feedwater Pump

Offgas System

CP

High Pressure Feedwater Heater

Stack

Low Pressure Feedwater Heaters

Steam Jet Air Ejector

Gland Steam Condenser CBP Condenser

Condensate Purification System

Fig. 2.12 BWR power cycle. Top figure: old vintage BWR. Bottom figure: Advanced BWR (GE courtesy)

2.3 Basics of Boiling Water Reactors

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As the steam is generated in the RPV, bulk boiling is allowed in BWR core, which puts constrain on possible water/steam chemical conditioning (i.e.: no boric acid or lithium hydroxide injection). Figure 2.13 presents a layout of a typical modern BWR containment. As compared to PWRs, there are major differences. The first one is that BWR RPVs are much larger than PWR RPVs because they contain several systems or components that do not exist in PWRs RPVs like steam dryer and separator; moreover, some RPVs may also contain jets pumps. Another major BWR/PWR difference is that control rod drives enter through the RPV bottom head in BWRs because of the presence of the steam dryer & separator at the top of the vessel. One particular component found in BWRs is jet pumps (Fig. 2.14). Jets pumps provide flow to control reactor power which yields higher power level without increasing the RPV size. Jet pumps also provide part of the boundary required to maintain 2/3 of the core height following a recirculation line break event.

Fig. 2.13 Layout of a typical BWR primary containment (GE courtesy)

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Fig. 2.14 BWR jet pump (GE courtesy)

Figure 2.15 presents a typical BWR lower plenum. As shown on this figure, lower plenum is a busy area with the presence of: • • • • • • •

Control Rod Drive guide tubes; Control Rod Blades; Control Rod Drive housings Stub tubes; In-core housings; Guide tubes; Flux monitor dry tubes.

The multiplicity of components means higher probability of failures occurrence as proven by field experience. Another major component of BWR core internals is the core shroud (Fig. 2.16). The core shroud is a large stainless-steel cylinder surrounding the core. It separates upward flow thorough the core from downward flow in the downcomer annulus. It also provides a 2/3 core height floodable volume. One of the reasons for a BWR RPV being so big is the presence of a steam separator above the core. In a separator, turning vanes impart rotation to the steam/ water mixture causing the liquid to be thrown to the outside. In the RPV illustrated by Fig. 2.17, there are 163 standpipes.

2.3 Basics of Boiling Water Reactors

Core shroud

Fig. 2.15 BWR typical lower plenum (GE courtesy)

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Core Spray Spargers

Eccentric Aligner

Core Plate

Eccentric Aligner

Fig. 2.16 BWR typical core shroud (GE courtesy)

Fig. 2.17 BWR typical steam separator (GE courtesy)

Top Guide

Stud (Typical)

2.3 Basics of Boiling Water Reactors

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Fig. 2.18 BWR typical steam dryer (GE courtesy)

Another big piece of equipment sitting at the top of BWR RPV internals is the steam dryer. Steam dryer provides a 99.9% steam flow to the main turbine. In the dryer, wet steam is forced horizontally through dryer panels: • The steam is forced to make a series of rapid changes in direction (Fig. 2.18); • The moisture is thrown to the outside. Note that initial power uprate plants experienced flow induced vibrations which have been minimized by design improvements. BWRs were first introduced in 1955. The first commercial plant of this first GE series called BWR1 was Dresden 1 which was commissioned in 1960. BWR1 series is composed of 8 similar plants with the following main characteristics: • External or internal steam separation; • Low power density core. BWR1 series have been followed by several other series: BWR2 to BWR6, ABWR and ESBWR. The main characteristics of these reactors are summarized hereafter:

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• BWR2, introduced in 1963, 3 plants: – Internal steam separation; – Low power density core; – Flow control load following. • BWR3, introduced in 1965, 9 plants. This series is the first one equipped with jet pumps: – Low power density core; – Internal jet pumps; – 2 recirculation loops. • BWR4, introduced in 1966, 25 plants. Starting with his series, the core power density was significantly increased: – High power density core; – Mark I or Mark II containment building. • BWR5, introduced in 1969, 8 plants. The main modifications of this series were related to improvement of safeguards and installation of recirculation flow control valves. – Valve flow control load following; – ECCS injection into the core shroud. • BWR6, introduced in 1972, 8 plants. The main modifications brought with this new series of plants concerned: – Addition of fuel bundles, increase of output, improvement of the fuel safety margins (8
8 fuel bundle); – Improvement of the recirculation system performance (valve flow control). • ABWR, introduced in 1991, 4 plants. ABWR is a blend of best features from operating BWRs, available new technologies and modular construction techniques. The mains ABWR characteristic are: – Safety improvement (reduced core damage frequency); – Design life of 60 years; – No external recirculation loops: reactor internal pumps. • Last, ESBWR, currently at the licensing and design stage. The main characteristics of ESBWR are: – – – – –

Passive safety; Natural circulation: no recirculation loops, no pumps; Improved safety: reduced core damage frequency; Design life of 60 years; Larger main generator (*1,600 MWe).

Chapter 3

Failure and Ageing Mechanisms

3.1

Background

There are 2 classes of degradation mechanisms: the mechanisms which are related to failures and the mechanisms which concern materials ageing. Ageing is generally not a cause of failure; however, it can deteriorate the material resistance to one of the failure mechanisms. For example, thermal ageing of 17–4 PH can make this alloy fail by corrosion. In the first category are: corrosion, fatigue, mechanical rupture, wear… In the second category are: irradiation embrittlement, thermal ageing… The reference [L’EXPERTISE METALLURGIQUE appliquée aux centrales thermiques, Pierre Mousset, Electricité de France, 1990, Editions Kirk.] gives the very basics of these degradation mechanisms; the information provided in this handbook supplements these basics.

3.2

Corrosion

There are many types of corrosion, they are listed and briefly described hereafter.

3.2.1

Aqueous Corrosion

Foreword In contact with water or any other aqueous solution, many materials are thermodynamically unstable, especially when oxidizing species are present; their natural tendency to form species with positive oxidation number ends up in “aqueous corrosion”. This oxidation occurs either by dissolution in the environment or by the © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_3

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formation of more or less complex oxides or hydroxides which are more or less adherent to the underlying material. As a consequence of this, there is a loss of material (or thickness) or initiation of localized corrosion (pitting, cracking) which can jeopardize the mechanical resistance of components or induce leaks, or modify the surface properties and furthermore pollute the environment with corrosion products (soluble or insoluble). However, in the case of materials which can passivate (such as SSs which are of wide use in the nuclear industry), the oxidation kinetics is slowed down by the buildup of thin protective oxide films which tend to minimize the risk of components degradation by loss of material. However, SSs are more prone to localized corrosion than to general corrosion. Therefore, the study of the aqueous corrosion of metallic materials relates to the study of reactions and associated processes which lead, depending on the circumstances, to the resistance or to the failure of the materials in contact with aqueous solutions. These studies can refer to the normal operating conditions or to shutdown/startup sequences or even to accidental conditions. These reactions depend on the environment, on the materials and even on the applied mechanical loads or stresses. These last 3 parameters cannot be treated separately as corrosion, especially SCC, is a synergistic mechanism. Corrosion results from tied electrochemical reactions: • One anodic reaction which induces a loss of electrons and results in an oxidation phenomenon, which means either material dissolution or oxide formation, or even both as shown by the following equation: 4 M ! 4 Mn þ þ 4n e • One cathodic reaction which induces an electron gain and results in a reduction phenomenon with hydrogen generation: 2n H2 O þ n O2 þ 4n e ! 4n OH1 4n H þ þ 4n e ! 2n H2

in aerated environment in desaerated environment

Corrosion results from tied electrochemical reactions: One should note that these two reactions, anodic and cathodic are tied together because they must deal with the same number of electrons. Thus, any phenomenon which would limit the number of electrons either generated or consumed, would decrease the corrodion rate. General Corrosion General Corrosion Per Say General (or uniform) corrosion translates into a metal loss which is uniformly distributed on the wetted surface. This metal loss can be measured either by weight gain or loss or by thickness reduction, and periodically monitored on some

3.2 Corrosion

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Fig. 3.1 General corrosion of the tubesheet of a condenser outlet channel head. The tubesheet is made of carbon steel (A42). Note that the corrosion by raw water is deeper around the cartridge brass (70/30) tubes1

operating equipments. Providing an extra thickness has been taken into account at the design stage, this type of corrosion is harmless even if it can result in major financial losses (like in the chemical industries). Figure 3.1 shows an example of general corrosion of carbon steel in raw water. This type of corrosion is a concern for carbon or low alloy steels, when the environment cannot form a protective oxide, for example when chlorides, oxygen or sulfides are present. In general, porous oxide can live with uniform corrosion. Uniform corrosion initiates on active or bare surfaces (without any protective oxide). As concerns iron, this happens when electrical/chemical conditions make Fe2+ stable (acidic environment) or HFeO2− stable (caustic environment). Boric Acid Corrosion Boric acid corrosion is just a particular form of general corrosion or wastage. In PWRs, when there is a primary water leak, boric acid can concentrate at the surface of the leaking component as a consequence of steaming (evaporation). In some cases, boric acid can deposit on a component impinged by the jet resulting

1

L’EXPERTISE METALLURGIQUE appliquée aux centrales thermiques, Pierre Mousset, Electricité de France, 1990, Editions Kirk.

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from a primary water leak; such a typical situation is bolted flanges. However, boric acid concentration can also occur without leak, as for example in some particular flow restricted areas such as dead legs. One identified PWR location where boric acid concentration can occur is the pipe length running between 2 HPSIS closure valves in some reactor’s designs. The environment thus created can be deleterious for many materials because of a particular combination: • Low pH (acid concentration); • Presence of residual water which can be trapped in the deposits; • Presence of more or less oxygen (more when the leak occurs in open atmosphere and less when the leak is confined in a crevice); • Temperature effect. Boric acid deposits can stay hot because of the high temperature of the leaking component. As corrosion is a thermally activated phenomenon, a high temperature implies a high corrosion rate. However, when the temperature drops, acidity increases (boric acid is a stronger acid at room temperature than at RCS temperature) leading to lower pH; • In case of bolted connections, a synergistic effect may occur between the corrosive environment and the mechanical action of the impinging water jet. The main material having been corroded so far as the result of boric acid leaks is the low alloy steel of PWRs pressure boundary components (i.e.: RPV head (Fig. 3.2), pressurizer, SG). Under certain circumstances, the loss of material by boric acid

1

L’EXPERTISE METALLURGIQUE appliquée aux centrales thermiques, Pierre Mousset, Electricité de France, 1990, Editions Kirk.

3.2 Corrosion

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corrosion can be very quick, up to several centimeters per year. As a consequence, boric acid corrosion is a particular threat regarding safe plant operation. Low alloy steel is not the only material susceptible to boric acid corrosion. SSs (Fig. 3.3), high strength materials (bolts, Fig. 3.4) and hardfacing alloys (gate valves, Fig. 3.5) have also suffered from this particular type of general corrosion.

Fig. 3.3 Optical view of the wastage of a SSs gate valve (HPSIS gate valve in contact with a dead leg environment enriched in boric acid)

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Fig. 3.4 PWR, boric acid wastage of a LAS bolt following a flange leak

Fig. 3.5 PWR, HPSIS, gate valve, boric acid wastage of Stellite grade 6

3.2 Corrosion

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Flow Assisted Corrosion FAC General Description FAC is another type of general corrosion which is accelerated by a water flow. FAC occurs when the following conditions are met: • The component is made of carbon steel or very low alloy steel; • The water flow is single phase or de-aerated dual phases (oxygen content 1.5 m/s–5 ft/s); • The temperature is in the following range: 100 °C (212°F) < temperature < 300 °C (572 °F); FAC is a chemical-based phenomenon; it is not a mechanical process such as erosion, cavitation or abrasion which all ends up in thickness loss as well. Mechanism FAC can be roughly described by Fe dissolution in flowing water. FAC is a 4-step process (Fig. 3.6):

Fig. 3.6 Mechanism of FAC

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• Oxidation of Fe into either ferrous ions (Fe2+) or magnetite (Fe3O4) at the metal-oxide internal interface; • Diffusion of soluble species (ferrous iron) through the porous oxide layer; • Dissolution-reduction of the magnetite at the oxide–water external interface; • Transport of iron soluble species to the water flow. FAC occurs only if the metal surface has a magnetite layer. The release of soluble Fe into the water is controlled by the Fe concentration gradient in the diffusion-limiting layer at the oxide/water interface. FAC is a steady state for which the oxide thickness does not change over time. It corresponds to equilibrium between the formation of magnetite at the metal-oxide interface and an oxide reduction at the oxide water interface. FAC has no real incubation or initiation period. However, FAC occurs after a short period of time, period during which the required chemical conditions and thermal hydraulics are established. For example, after a startup following an outage, hematite may be present at the surface. Once the reducing conditions are back again, FAC occurs only when all the hematite has turned back to magnetite. Parameters impact Chemical Parameters • pH The higher the pHt, the lower the Fe solubility, and the lower the FAC rate. Raising the room temperature pH from 9 to 9.5 can divide the FAC rate by 3. • Dissolved oxygen content Even lowest oxygen content slows down the FAC rate considerably. Oxygen favors hematite which is much less soluble than magnetite. 2 to 10 ppb of oxygen are enough for FAC mitigation. • Ferrous ions concentration When the ferrous ions concentration increases, the metal dissolution into ferrous iron and the magnetite dissolution both slow down the FAC rate. • Hydrazine At 235 °C (455 °F), the FAC rate varies with the hydrazine (N2H4) content according to a bell- shape curve between 0 and 500 ppb with a maximum at 200 ppb. Hydrazine concentration has no influence on the FAC rate in the domain of temperature 180–200 °C (356–392 °F).

3.2 Corrosion

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Hydro-dynamical Parameters • Flow rate Flow rate is one of the main parameters controlling the oxide ferrous iron through the water mass transfer coefficient: the higher the flow rate, the higher the FAC rate. • Wall roughness Roughness increases the local water velocity. As a consequence, the thickness of the diffusion layer decreases; it leads to a concentration gradient in this layer. Therefore, the dissolution of magnetite at the external interface is enhanced. • Component geometry The components which geometry disturbs the flow (water velocity increase or turbulences generation) are particularly susceptible to FAC. Figure 3.7 shows an example of FAC induced by a weld. However, straight lines can also experience FAC when the water velocity is high enough. Components geometry impact on the FAC rate is addressed by taking into account a geometry factor.

Fig. 3.7 View of a carbon steel (A42) heat exchanger tube suffering from FAC. Water + steam flow inside the tube, CO2 flows outside. A leak occurred a few centimeters downstream a weld (left picture). Note the typical surface features (right pictures)

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• Steam quality In two-phase systems, only water induces FAC. In other words, FAC cannot exist in dry steam. However, the presence of steam having a tendency to increase turbulences, FAC rate is typically higher when steam is present. Temperature Temperature plays a major role in FAC. Temperature has an impact not only on some chemical parameters (pH, water/steam partition coefficient, iron species diffusion coefficient) but also on hydraulics parameters. When temperature increases, some parameters increase other decrease. Moreover, the kinetics of reactions such as oxidation of iron (metal-oxide interface) and reduction of magnetite (oxide– water interface) is temperature-dependent. Between 100 °C (212 °F) and 300 °C (572 °F), the influence of temperature is a bell-shape effect. Below a critical temperature (150 °C/302 °F), the FAC rate increases with temperature and decreases above 150 °C (302 °F). Above 300 °C (572 °F), the FAC rate is negligible. Metallurgical Parameters Amongst all alloying elements present in low concentration in carbon steels, Cr is the most influential one regarding FAC kinetics. Cr content, even very low, can induce a dissolution and an oxide porosity. When Cr-content rises, the oxide becomes less porous because of the formation of a Fe–Cr spinel oxide. Moreover, the oxide gets enriched in chromium over time. Laboratory tests have shown that 0.2 wt% Cr is enough for achieving a significant reduction of the FAC rate. Also, French field experience demonstrates that FAC has never been observed on components having a Cr content superior to 0.15 wt%. Other alloying elements such as Mo or Cu increase carbon steel resistance to FAC. EDF has launched studies to the aim comparing base metal and weld metal FAC resistances. The first results of these studies show that: • For a same chromium content, and identical chemical and physical conditions, base metal and weld metal behave similarly; • The main parameter governing the FAC rate is the weld metal chromium content; • The assemblies containing both base and weld metals behave the same way as the base metal, indicating the absence of any galvanic coupling effect; • When temperature exceeds 150 °C (302 °F), the weld metal seems to have the same behavior as the base metal (to be confirmed). Preventing FAC • Improving secondary chemistry Secondary chemistry adjustment results from the optimization of keeping under control various failure mechanisms: SCC, FAC, fouling, corrosion of the condenser… SCC risk of A600 SG tubes requires the oxygen content to be as low

3.2 Corrosion

31

as possible (through hydrazine injection). However, extremely low oxygen contents increase the FAC risk. Regarding pH, high values are targeted. For the same pH at room temperature, morpholine allows to reach a higher pHt at service temperature than ammonia; therefore morpholine is used when copper alloys are present. • Materials selection Anytime a pipe is replaced, a minimum Cr-content of 0.15 wt% is required for the new pipe material. • Operating conditions In two-phase areas of the secondary circuit, the main action that can be taken at the design stage is to include steam dryers in order to reduce the water content of steam, and consequently to reduce the FAC risk. FAC Detection and Field Monitoring Piping condition is monitored by periodic inspections. The interval frequency can range from 10 years for the less FAC susceptible components to 2 or 3 years for highly susceptible components. In France, the BRT-CICERO code is used for the screening of components. The code allows to draw attention to the most FAC susceptible locations on which UT thickness measurements are then performed. Also, FAC can be visually recognized because of specific surfaces features as the ones illustrated by Figs. 3.8 and 3.9. FAC can be responsible of catastrophic failures as the ones presented in Figs. 3.10, 3.11, 3.12 and 3.13. Figure 3.14 shows an example of two-phase FAC that occurred at a BWR plant.

Fig. 3.8 View of FAC features on carbon steel in water. Features are flow rate dependent. Left: “orange peel” aspect, right: “cupules” aspect

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Fig. 3.9 View of ‘tiger skin” aspect of FAC observed on a carbon steel in two phases environment

Corrective Maintenance Actions must be undertaken if an unacceptable remaining thickness is detected or if the BRT-CICERO code predicts that one area will not safely operate until the next outage. These actions depend either on the code predictions (whether the FAC kinetics will slow down or not) or on the availability of the replacement components. They should have a Cr-content higher than 0.1 wt%. If no component is available, a refined computation is performed to justify continuing a safe operation despite a local thickness out of requirements. Another solution consists in modifying the geometry of the system in order to minimize the FAC risk.

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33

Fig. 3.10 1986, 46 cm diameter carbon steel condensate system elbow rupture in the secondary side of Surry 2, after 13 years of operation. Conditions: temperature: 185 °C, pressure: 30 bars, water velocity: 5 m/s. Nominal thickness: 12.7 mm, final thickness: 3 mm2

Fig. 3.11 2004, 56 cm carbon steel line rupture at Mihama 3. Conditions: temperature 142 °C, pressure 0.93 MPa, flow velocity 22 m/s, pH 8.6/9.3, operation time 185,700 h. The pipe had dangerously corroded up to 96% to just 0,4 mm from its original 10 mm thickness

2

Gordon B., Other Corrosion Concerns Affecting Life Extension of Light Water Reactors, International Light Water Reactor Materials Reliability Conference and Exhibition 2016, Chicago, Illinois, USA, 1–4 August, 2016.

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Fig. 3.12 1992, FAC rupture of an extraction line at Dukovany VVER

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35

Fig. 3.13 FAC ruptures at two US plants. Top: 1997, high pressure extraction line at Fort Calhoun. Bottom: 1999, feedwater heater shell at point Beach unit 1

Fig. 3.14 Two-phase FAC in a BWR extraction steam line. The flow rate was very high: 72 m/s

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Local Corrosion This chapter gathers various types of local corrosion. Materials are supposed to be in a passive state here. Pitting Pitting is a form of local dissolution which can be very rapid and leads to more or less hemispherical holes. Pits formation in SSs requires the deterioration of the passive film by anions (typically: chlorides). Then, a local dissolution takes place which drives the pit environment to acidic conditions because of the hydrolysis of the dissolved cation. This pH drop enhances the development of pits providing the environment inside the pit turns to oxidizing conditions. Pitting occurs in presence of a more or less passive film, oxygen and deleterious anions such as chlorides. Because of the presence of a passive film, pitting is very localized. From a very local film rupture, larger defects develop, hidden below a surface which seems almost sound. It is a self-accelerating phenomenon which starts from a local film rupture due to the presence of anions such as Cl− or F−, and continue with the formation of an occluded and deaerated environment in the pit. Then, this occluded environment slowly acidifies because of hydrolysis of cations released by the corrosion process (mainly Cr3+): Cr3 þ þ 3H2 O ! CrðOHÞ3 þ 3 H þ The proton excess from the hydrolysis reaction increases the chloride concentration (and other anions) in the pit in order to maintain the electrical balance. When chromium is present, this phenomenon ends in creating a very acidic (pH < 1) and chloride rich environment. As a result, corrosion increases as fed by the oxygen reduction at the outer wetted surface, adjacent the pit. In the end, the mechanism corresponds to the coupling of hydrolysis with differential aeration (Evans effect). Figure 3.15 gives an overview of the pitting mechanism. Hydrolysis can also occur on carbon steel, in the absence of chromium, however with less intensity because of the limited hydrolysis of ferrous ions. The pitting risk increases along with the environment acidity, potential and chlorides concentration. It decreases when the material content in film forming elements such as chromium, molybdenum or copper increases and in deaerated environment. This risk is a potential concern for condenser stainless tubes, however it has never been observed for river cooled plants because of the tubes high chromium content and the limited chlorides concentration of the water. It is different for sea cooled units where stainless-steel tubes are not used because of the high chloride content of sea water and the related high pitting risk. Figures 3.16 and 3.17 show a couple of pits observed in the field. 2 Gordon B., Other Corrosion Concerns Affecting Life Extension of Light Water Reactors, International Light Water Reactor Materials Reliability Conference and Exhibition 2016, Chicago, Illinois, USA, 1–4 August, 2016.

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37

Fig. 3.15 Sketch of the pitting mechanism. Step 1: metal corrosion and pit oxygen consumption. Step 2: generation of a differential aeration cell between the deaerated anodic zone inside the pit and the aerated zone outside the pit. Step 3: hydrolysis of the metallic cations leading to a pH drop into the pit. Step 4: because of the electro-neutrality of the environment into the pit, some anions must diffuse into it, thus increasing its chloride content and impeding any repassivation of the pit surface

Fig. 3.16 View of corrosion pits of a carbon steel, after chemical cleaning of the surface to remove surface oxides

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Fig. 3.17 SG pulled tube, cross section of a pit observed 16 cm (6″) above the top of the tubesheet. IGSCC and IGA have developed from this pit

Crevice or Cavity Corrosion This type of corrosion develops in flow restricted areas (under gaskets, in narrow gaps, under deposits (Fig. 3.18)) because of very limited exchanges with the bulk environment. This corrosion has generally a long incubation period and a fast propagation. Initiation corresponds to the corrosion of a passive metal in a crevice at a slow rate. The Cr3+ ions which are released induce a hydrolysis reaction, followed by a slow pH drop, as for pitting. Following an incubation period which can last several years, the pH drop induces a film instability when the pH drops below the depassivating pH, and eventually the metal corrosion rate sharply increases. It affects preferentially not only stainless steels in aerated environments polluted by chlorides, but also titanium alloys in hot environment containing chlorides, and even carbon or low alloy steels in more or less aerated environments. Figures 3.19, 3.20 and 3.21 show some examples of corrosion related to cavity or crevice corrosion. In the last two examples, it’s the difference of environment (in terms of pollution including oxygen) between the metal surface and the bulk environment which triggered corrosion initiation. Basically, it’s the same mechanism than pitting; however, the origin and the consequences are different. The remedial action consists is avoiding crevices and in using metals which can form highly stable passive films.

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39

Crevice

Gasket Crevice

Crevice

Tube Support Plate Crevice

Tube

Tubesheet

Crevice

Fig. 3.18 Examples of crevices from equipments design. Top: gaskets. Middle top: welds with overlap. Middle bottom: flanges. Bottom: heat exchangers

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Fig. 3.19 Under deposits crevice corrosion of 304 bolt/nut assemblies in an environment containing chlorides and oxygen

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41

Fig. 3.20 Carbon steel (A37). PWR secondary circuit reheater. Stagnant water and deposits at the bottom line of tubes leading to crevice corrosion

Fig. 3.21 Stainless steel (Z2 CN 18.10, 304L). Fire protection system. Stagnant raw water at the bottom line of the pipes leading to crevice corrosion. Left picture: pipe ID with two pin holes close to welds (white arrows). Right: cross section at pin holes location

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Galvanic Corrosion This type of corrosion results from the contact between 2 different materials wetted by the same environment. The corrosion of the less noble metal is accelerated by its contact with the noblest metal which in return is protected (its corrosion rate is decreased). Thus, there is a galvanic corrosion when the potentials of the two metals in contact differ enough, i.e.: Cu and Ni; Ni and carbon steel, Cu alloys with carbon steel (Fig. 3.22). Galvanic corrosion rate increases with oxygen content, is low in reducing environment and decreases with the distance between the 2 metals. Galvanic corrosion is also influenced by the flow rate. Galvanic corrosion mechanism is widely used in the industry for corrosion protection: the metal to protect is coupled with a less noble metal, this later being a sacrificial anode. Off shore platforms, pipelines, boats (hull and other metallic parts or components such as engines) are protected that way, typically with a zinc anode. Figure 3.23 shows the galvanic potentials (as refers to the saturated calomel electrode) of various metals or alloys. This chart allows determining whether a galvanic coupling is possible but gives no information about how active is this potential corrosion. In fact, galvanic coupling is no more than an aggravating factor of the various corrosion phenomena mentioned in this chapter (uniform corrosion, pitting, crevice corrosion, stress corrosion cracking…

Carbon steel corrosion

Cu-Al brass

Carbon steel corrosion

Carbon steel

Fig. 3.22 Carbon steel corrosion in contact with aluminum brass in river water polluted with chlorides. Top: wetted surface view; bottom: cross section. By design, this area was protected by an epoxy coating which failed and broke away

3.2 Corrosion

Fig. 3.23 Galvanic corrosion potential chart for metals

43

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3 Failure and Ageing Mechanisms

Intergranular Corrosion (Sensitization) Intergranular corrosion is a local corrosion of all grain boundaries of a material. For stainless alloys (steels, Inconels®), this type of corrosion is the consequence of grain boundary chromium depletion along with the presence of an oxidizing environment. This Cr-depleted zone becomes a preferential path for corrosion by more or less oxidizing environments, even without any mechanical load. The use of low carbon stainless steels or austenitic-ferritic steels help preventing this type of corrosion. As already mentioned, intergranular corrosion is the consequence of grain boundaries chromium depletion as the result of intergranular carbides precipitation. This precipitation occurs for specific time/temperature domains which are provided by TTS (Time–Temperature-Sensitization) or TTT (Time–TemperatureTransformation) diagrams (Fig. 3.24). As the carbon diffusion is much faster than the chromium diffusion, the intergranular carbides growth sucks the carbon adjacent to the grain boundaries, inducing a local chromium depletion down to 1 meV) and for temperatures in the 150–300 °C (300–570 °F) range; – For steels with high Cu content (Cu > 0.1 at%): The hardening plateau (due to Cu rich clusters) is not dependent upon the flux level. For EDF reactors, the hardening saturation is obtained for 1 to 2  1019 n/cm2;

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RPV Steels Neutron Irradiation Embrittlement

159

The initial hardening evolution due to Cr rich clusters is related to the flux in two domains: at extremely low flux (7  1010 n/cm2/s at 290 °C/554 °F). PWRs operate in the second domain. • Neutron spectrum A French study has demonstrated that there was no noticeable spectrum effect, provided that the embrittlement is determined from the fluence of neutrons with energy higher than 1 MeV. • Microstructure There is rather little literature dedicated to this topic. Forged and rolled materials have different embrittlement kinetics, as do welds and base metals. These two examples show that microstructure plays a role. It is difficult to make clear whether this influence directly impacts hardening or has an indirect impact on the relation between the hardening and the rupture mechanism.

3.15.7 How to Mitigate RPV Steels Neutron Irradiation Embrittlement • Monitoring RPV steel embrittlement is well monitored based on “irradiation surveillance programs”. However, R&D is still needed because some situations may not be entirely covered by the surveillance programs in place (such as high segregation areas and under cladding HAZ). TEP can be used along with the surveillance program to supplement the knowledge, either on irradiation consequences or on the impact of metallurgical anomalies that can be encountered in specimens. However, using TEP on the RPV itself is not possible because of the presence of SS cladding. • Preventing irradiation embrittlement Irradiation embrittlement cannot be avoided. We can only minimize it through optimized core designs (low neutron leaking cores). • Repairing As irradiation defects are generated out of the thermodynamical equilibrium, they are over saturating the material and can be eliminated by a hold at a temperature higher than the irradiation temperature. However, Cu precipitates cannot be eliminated. For low Cu content steels, experimental studies have demonstrated that irradiation embrittlement consequences can be fully eliminated by a 450 °C (842 °F) annealing. So far, annealing is not an option for the EDF fleet. Annealing can be detrimental for zones which are susceptible to thermal ageing such as under cladding coarse grains HAZ; however this drawback effect has still to be quantified.

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3.16

Swelling Under Irradiation

3.16.1 Mechanism Identification • Name: swelling, void swelling. • Related mechanisms: – Irradiation creep: the last creep stage, named stage III, where the creep strain rate sharply increases, it corresponds to a domain where irradiation creep and swelling occur simultaneously. – Ductility drop under irradiation: the fast breeder reactors experience shows that for a few % swelling, the ductility and the tearing resistance drop almost down to zero. • Mechanism type: swelling stems from cavities generation and coalescence under irradiation, these cavities being stabilized by gases.

3.16.2 Application Domain In General Irradiation swelling can affect neutron irradiated stainless steels. This damage is confirmed for stainless steels irradiated in fast breeder reactor conditions at high temperature by remains questionable for steels irradiated in PWR conditions (around 320 °C–608 °F). Domains Studied in the Database Materials Here, the materials potentially susceptible to irradiation swelling are the core lower internals materials (plates, baffle plates, formers, bolts): • 18–10 grade (AISI 304 and 304L): Z2 CN 19–10, Z2 CN 18–10, Z2CN 18–12 and Z3 CN 18–10 with controlled nitrogen and Z6 CN 18–10. • 17–12 Mo grade (AISI 316 et 316L): Z2 CND 17–12 with controlled nitrogen, Z2CND 17–12, Z3 CND 17–12, Z5 CND 17–12 and Z6 CND 17–12. • 308 grade for welds. Temperatures and doses 300 °C (572 °F) < temperature < 380 °C (716 °F). 0 dpa < dose < 80 dpa at the fourth 10-year outage.

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Swelling Under Irradiation

161

0 < stress < around < 600 MPa. 5  1011 N cm−2 s−1 < neutron Flux (E > 1 meV) < 5  1013 N cm−2 s−1 Depending on the component.

3.16.3 Mechanism Description General Description of the Structure Evolution Under Irradiation During irradiation, high energy neutrons create displacement cascades which generate punctual defects (vacancies and interstitials) which can migrate at these temperatures. Depending on the irradiation temperature, these punctual defects can re-combinate, combine, disappear to generate the following microstructural objects: • Regeneration of the initial structure of cold work dislocations, • Black dots/black spots formation, clusters of small punctual defects (2–3 nm), difficult to observe by TEM. Given their small dimensions, it is difficult to state about the interstitial or vacancy nature of these clusters. • Formation of faulted, sessile, interstitial Frank dislocation loops generated by interstitials recombination (under TEM observation, small Frank loops appear as black dots); by growth and transformation, these Frank loops can generate a new dislocation network. • Formation of cavities by voids clustering (and/or gas bubbles in the case of gas formation by transmutation). • Radiation induced segregation at grain boundaries, at cavities surface or at any other sink, with a significant chromium, molybdenum and iron depletion along with an enrichment in nickel and silicon. • Sometimes precipitation of phases (i.e.: c′). • Destabilization of the austenitic matrix (formation of ferrite, martensite…): this destabilization, which is sometimes mentioned in the literature, has never been confirmed during observations of irradiated steels such as 304 or 316, neither in any of the various experimental irradiation tests sponsored by EDF, nor in destructive examinations. Swelling translates as a macroscopic volume increase that can be measured because of the microscopic cavities’ growth by capture of the vacancies generated by irradiation. The large increase of the cavities’ dimensions and the macroscopic swelling of 304 and 316 steels have been studied above 400 °C (752 °F) in the framework of fast breeder reactors research programs. The transfer of the fast breeder reactors experience to PWRs needs some precautions as PWRs operate at a lower temperature and swelling is very susceptible to irradiation conditions (flux, spectrum).

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Fig. 3.124 Swelling evolution law for neutron irradiated steels

For the 300 steels series, swelling is characterized by a two variables law represented at Fig. 3.124. Two parameters characterize this law: • An incubation period (fluence < ƬG) during which microstructural evolutions occur but do not translate in any macroscopic swelling. • An almost steady growth rate (fluence > ƬG) with an almost linear swelling growth rate. Cavities and Gas Bubbles Nucleation and Growth Gas Production A nuclear reactor is characterized by its neutron’s spectrum and flux (Fig. 3.125). The spectrum represents the neutrons distribution in term of energy per square centimetres and second. The flux integrates the spectrum over its entire energies. Thus, the flux represents the quantity of neutrons per surface and time units. The fast neutrons (energy > 0.1 meV) are those responsible for the vast majority of the punctual defects. The unit used to represent the irradiation damage is the dpa (displacement per atom), which means the number of displacements of each atom in the crystal network. During their travel in the core, the moderator and the structures change the energy distribution of the neutrons. In PWRs, water is both coolant and moderator. The elastic collisions between neutrons and water slow down the neutrons, it’s the neutron thermalization. The spectrum seen by the material varies depending on the environment considered. Three energy domains are considered: the low energy thermal neutrons (E < 10–6 meV), the fast, high energy neutrons (E > 0.1 meV) and the intermediate domain where neutrons slow down. A spectrum is said mixed when it combines both thermal and fast neutrons.

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Swelling Under Irradiation

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Fig. 3.125 PWR neutrons spectrum

Thermal neutrons and material atoms interactions generate gases via transmutation reactions: • Helium from Nickel: 58Ni + n ! 59Ni + c followed by 59Ni + n ! 56 Fe + 42He where n is a neutron and c a gamma photon; • Helium from Boron: 10B + n ! 7Li + 42He, which can lead to helium production rates of 10–15 appm per dpa; • Hydrogen: 59Ni + n ! 59Ni + H, which can lead to hydrogen production rates of 10–15 appm per dpa. Other gases are present in the material such as residual oxygen. Cavities nucleation and growth. Cavities are vacancies clusters whereas bubbles contain gas and can have an internal pressure. Cavities appear because of an excess of vacancies in the matrix. This excess can result from interstitials clustering or elimination on material sinks, because of their high diffusion rate. Cavities initiate and grow by free vacancies clustering which migrate in the structure, but also on incoherent surfaces, or by coalescence. As diffusion-based, their formation and growth are thermally activated. Cavities locations are rather intergranular, sometimes at the interface of some precipitates. Bubbles Nucleation and Growth Helium being almost insoluble in the structure, it is going to accumulate on preferential sites to form high pressure gas bubbles. Moreover, interstitial helium has a low migration energy and is easily migrating at PWR temperatures, thus it can be trapped by one or more vacancies to generate gas bubbles. Hydrogen is soluble enough to remain in solid solution and will not generate gas bubbles. However, in presence of helium bubbles, hydrogen atoms migrate to these bubbles and increase their internal pressure.

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At the beginning, bubbles form close to grain boundaries or on dislocations, then in the matrix following dislocations (acting as helium diffusion canals) and at some preferential sites such as precipitates/matrix interface and complex solute atoms. Because of the helium extremely low solubility in steel and of the high internal pressure, bubbles cannot expel vacancies at PWR’s temperatures. Any decrease of the bubbles size results in a pressure increase along with an immediate absorption of free vacancies. There is an equilibrium between internal pressure and surface tension. Thus, the only way for bubbles to grow is capturing gas atoms. So, bubbles are cavities which are stabilized by an internal gas pressure. Gas bubbles can grow by vacancies clustering if there is an excess of free vacancies or by clustering of gas bubbles if the temperature is high enough (at least 400 °C). In the first case, the internal pressure of gas bubbles drops, the bubbles turn to cavities. In the second case, the smallest bubbles will disappear to the benefit of the bigger ones. Increasing the helium nucleation rate favours the generation of gas bubbles. If the distribution is uniform in the material and the bubbles small, these bubbles act as sinks and absorb free punctual defects. Above a critical dimension (in the order of a few nanometres), bubbles can turn to cavities and can increase in size just by absorbing the excess of vacancies, without any need of being stabilized by an internal gas pressure. For a given temperature, the cavities growth rate is likely to be superior to bubbles growth rate as in the early life, the quantity of vacancies in excess is superior to the helium one. Thus, a significant swelling of PWR internals components would imply a transition from gas bubbles to a cavity’s regime. Mechanism Effects Macroscopic Volume Increase For metallic structures with heterogeneous irradiation and temperature, local swelling can generate heterogeneous deformations, thus internal stresses. These stresses could be partially relieved by irradiation creep. However, these stresses could increase bolt stresses and thus increase the IASCC risk. Besides this, one would observe a creep increase with swelling: the creep rate doubles for a swelling rate of 0.02% dpa. Anticipating the consequences of local swelling of the reactors internals remains difficult: by definition, the flux and temperature distributions in baffle plates is very heterogeneous. This heterogeneity is likely to generate internal stresses (“constrained swelling”), deformations that can impact the life of the relevant components (bolts rupture or components embrittlement). Impact on Mechanical Properties Various studies indicate that even a small material macroscopic swelling can impact mechanical properties:

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Swelling Under Irradiation

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• Work done at CEA on modified 316 (by Ti addition) irradiated in the 400–500 ° C (752–932 °F) domain shows that swelling modifies tensile and impact toughness properties: decrease of the uniform and total elongation, necking suppression for 6% swelling, total ductility loss for 10% swelling. • Similar results have been obtained by others for a Fe–18Cr–10Ni–Ti steel irradiated in Bor-60 at 400–500 °C. Critical swelling leads to embrittlement, depending on the material type and on the irradiation temperature. • Work on pressurized tubes shows that fracture becomes fragile for significant swelling. However, quantification of swelling impact on mechanical properties is a domain with scarce data, where a lot remains to do. List of Influents Parameters Operating Parameters Studies conducted in the framework of a fast breeder reactors program show that swelling is governed by a series of independent parameters: irradiation temperature, neutrons flux, neutrons spectrum and stresses if any. Impact of Neutrons Fluence The impact of the neutrons fluence (or irradiation dose) is visible from a swelling increase with neutrons fluence. Figure 3.126 shows the swelling domains associated to SA304-304L and CW316-316L steels irradiated in fast breeder reactors at temperatures ranging from 385 (725) to 400 °C (752 °F). The swelling evolution with irradiation dose is growing and monotonic for the whole series of 300 steels irradiated in fast breeder reactors. Impact of Irradiation Temperature Figure 3.127 presents the influence of irradiation temperature on swelling of a SA316 stainless steel. Swelling shows a peak around 450–500 °C (842–932 °F). The position of this peak varies according to several factors. PWRs’ operation temperatures (290–370 °C/554–698 °F) correspond to the tail of the peak. Significant swelling is possible only if part of the bubbles merge to cavities, which could happen mostly at the highest temperatures of the range (350–370 °C/662– 698 °F). The bell shape of the swelling curve seems to hide two opposed mechanisms, the first one active at low temperature and the second one active at high temperature. So, at low temperature, when their diffusion rate is low, punctual defects (interstitials and vacancies) formed in displacement cascades quickly recombine. At high temperature, punctual defects rapidly move to materials sinks and disappear there. So, these two temperature domains do not allow any excess of vacancies in the material, thus impeding any significant swelling.

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Fig. 3.126 Swelling domains for 304 and 316 steels irradiated in fast breeder reactor between 300 (572) and 400 °C (752 °F)

Fig. 3.127 Impact of the irradiation temperature on SA316 swelling

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Swelling Under Irradiation

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Fig. 3.128 Swelling laws versus fluence and temperature

Swelling evolution versus fluence for different irradiation temperatures is presented at Fig. 3.128 for a 316 stainless steel irradiated in the fast breeder reactor EBR-II. The higher the irradiation temperature, the more significant the swelling. When temperature increases, the incubation time decreases and the swelling rate increases. Impact of the Neutrons Flux The influence of the neutrons flux on swelling could strongly depend on irradiation temperature. Neutrons flux decrease could generate two parallel and opposite effects: a shift of the swelling peak towards lower temperatures on one hand and a decrease of the swelling peak amplitude on another hand. Combining these two effects would lead to the existence of a swelling peak for a given flux and a given temperature. This effect is still poorly understood and nobody knows the possible impact of flux on the swelling incubation time at PWRs operation temperature. Impact of the neutrons spectrum The spectrum is the energy or velocity distribution of neutrons in a given environment. The spectrum governs part of the helium production mainly from nickel transmutation and to a lesser extent, from boron transmutation. However, the influence of the helium production rate remains mostly unknown, especially in the 300–400 °C (572–752 °F) range. A swelling peak could exist depending on the helium rate production: • For very low helium production rates, the residuals gases present in the matrix could be in too low concentration to trigger gas bubbles nucleation and growth, which could delay cavities’ generation. • Opposite, a high helium production could lead to a high density of very small diameter gas bubbles that could limit cavities nucleation, thus swelling generation. These bubbles would act as vacancies and interstitials symmetrical sinks.

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In the absence of such bubbles, the dislocation lops can absorb interstitials ending in an excess of vacancies. • The swelling peak could move towards high helium production rates when the neutrons flux decreases. Impact of Stresses Many results show that applied stresses increase swelling. In the 300–400 °C (572– 752 °F) domain, the impact of stress could be weaker than at higher temperatures. Incubation time could be decreased by applied stresses, however, the swelling rate would remain the same. Thus, for CW316 irradiated at 400 °C (752 °F) under increasing stresses (from 0 to 293 MPa), the swelling rate is almost steady (varies from 0.037 to 0.048% per dpa), whereas the incubation time decreases from 30 to 20 dpa. Both tensile and tension stress would have an impact. It is worth noting that stresses can stem from operation. Stresses can even belong to the material. Materials Parameters Figure 3.126 shows SA304, SA304L, CW316 and CW316L steels swelling domains obtained in fast breeder reactors at temperatures ranging from 385 (725) to 400 °C (752 °F). The two steels behave differently. At 400 °C (752 °F), SA304 and SA304L mean incubation times are around 10– 15 dpa whereas there are 30–40 dpa for CW316 and CW316L steels. Swelling rates (for doses exceeding incubation doses) are around 0.2%/dpa for SA304 and SA304L steels and around 0.06%/dpa for CW316 and CW316L steels. Microstructure impact Every microstructural object which can enhance the vacancies and interstitials recombination acts as a swelling limiter: • Some elements in solution or precipitates extend the swelling transient domain. So, a fine dispersion of small precipitates (TiC…) prevent dislocations migration (stabilization of the initial dislocation structure regarding regeneration). • A network of dislocations; because they stabilize the initial dislocation structure, some elements in solution or precipitates delay swelling. • A low density of dislocation loops could limit the preferential absorption of interstitials and thus prevent an excess of vacancies. • A very high density of fine helium bubbles allows limiting steel swelling by enhancing vacancies-interstitials recombination. So, any element enhancing the generation of small helium bubbles can potentially limit material swelling: cold work, fine intragranular precipitation of some phases (MC or FeTiP) etc.… The destabilization of the austenitic matrix, by phases precipitation, could anticipate or go with cavities generation and so induce a swelling increase. This applies to the c’ phase (Ni3X with X = Al, Si, Nb).

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Swelling Under Irradiation

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Chemical Composition impact The influence of the alloying elements is temperature dependent. Carbon, silicon, phosphorus, molybdenum, manganese, nickel, titanium and niobium in solution are swelling inhibitors by enhancing vacancies and interstitial recombination. By contrast, a high chromium content would enhance swelling (decrease of the incubation dose) by decreasing the carbon mobility (by trapping part of the carbon in solution). The chemical composition variation impacts the incubation dose, the swelling rate along with the position and the value of the swelling peak maximum. Cold Work Impact Most of data show that cold work delays swelling (higher incubation dose) around 400 °C (752 °F). A high dislocations density favours the suppression of punctual defects and favours the heterogeneous nucleation of gas bubbles. Dislocations act as diffusion channels for gas atoms. In these circumstances, the bubbles are smaller and more abundant and the cavities nucleation and growth is more difficult. Under irradiation, these dislocations can evolve or disappear by mutual annihilation or on interfaces (material regeneration), which makes easier swelling initiation. Potential Concerned Components Swelling can affect PWR austenitic stainless steels irradiated at high temperature. Thus, the potentially concerned components are the most irradiated and hot reactor internals (baffle plates, formers, core barrel, core barrel weld, bolting, core support plate).

3.16.4 Preventing Swelling Monitoring Swelling is well-known to occur in fast breeders’ reactors but has not been observed in PWRs so far. Monitoring can lead to develop swelling detection and in-situ follow-up techniques. EPRI studies the relevance of UT or electrical techniques along with their application on components harvested from the field for investigation. Analysis of the deleterious impact of swelling on internals mechanical behaviour: the question is setting a swelling acceptance criterion taking into account the heterogeneities which are typical of this mechanism (flux and irradiation temperature distribution, materials susceptibility scatter).

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Prevent Swelling Occurrence Swelling is thermally activated with a fluence threshold, any temperature and fluence drop will decrease the probability of its occurrence, so is the replacement of 304 SS with 316 SS.

3.17

Cast Stainless Steels Thermal Ageing

3.17.1 Mechanism Identification Name: thermal ageing, spinodal decomposition, Cr unmixing, Cr precipitation. Type: mechanism based on thermal diffusion. Short description: Fe–Cr ferritic solid solution unmixing and precipitation.

3.17.2 Application Domain In general: Fe–Cr solid solution unmixing occurs for holding temperatures inferior to 500 °C in cubic centered SS with high Cr contents such as: • Martensitic SS containing 13–17% Cr; • Steels containing significant Cr rich ferrite such as austenitic-ferritic cast SSs and SS welds. This chapter is limited to austenitic-ferritic cast SSs, especially the Z3 CN 20.09 M (or CF8 without Mo) and the Z3 CND 19.10 M (or CF8 M, with Mo) steels which contain 10–30% ferrite (Fig. 3.129).

3.17.3 Mechanism Description Phenomenon Description The Cr unmixing of the cast SSs ferritic phase induces impact toughness decrease, transition temperature increase and toughness decrease, all along with the dual phase steel and its ferritic phase hardening (Fig. 3.130). Nevertheless, aged cast SSs fracture remains ductile with low rupture energy. Finer Scale Description During Cr unmixing or spinodal decomposition, a nanometric microstructure appears. This microstructure initiates in the original ferritic phase, by very slow and steady growth of the amplitude wavelengths of new variation of the Cr and Fe concentrations.

3.17

Cast Stainless Steels Thermal Ageing

171

Fig. 3.129 Overview of the structure of a cast SS containing 30% ferrite (dark phase)

270

30

260 25

HV 30

250 240

20

230 220

15

210 10

200 190

5

180 0 103

104 t 325 (h)

10 5

170 106

Vickers Hardness (HV30)

Impact Toughness (daJ/cm2 )

Fig. 3.130 Evolution of the impact toughness and of the hardness of an austeniticferritic SS versus its holding time at 325 °C

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3 Failure and Ageing Mechanisms

Fig. 3.131 Atomic probe concentration profiles of ferrite aged during 10,000 h at 400 °C: Fe rich a zones and Cr rich a′ zones

This microstructure has a “sponge” shape with alternance of Fe (a) and Cr (a′) rich zones (Fig. 3.131). For higher holding temperatures or high Cr contents, phase a′ formation in the ferrite occurs under a precipitation mechanism. These phenomena can come along with precipitation: • Of intermetallic phases (especially G phase: Ni16Ti6Si7 with a face cubic centered structure where Cr, Fe, Mo and Mn can replace Ti and Ni.) in the ferrite; • Of carbides (M23C6) at ferrite–austenite interfaces. These precipitations frequency and importance increase with holding time and/or rise in temperature. Precipitations occurring at 450 °C can also occur at 400 °C providing a holding time extension. Hardening as a result of spinodal decomposition and of precipitation can lead to steel embrittlement. It is noteworthy to mention that austenite is not affected by holds at temperatures inferior to 500 °C. This is mainly due to the fact that elements diffusion rates are much slower in austenite (face cubic centered structure) than in ferrite (cubic centered structure).

3.17

Cast Stainless Steels Thermal Ageing

173

3.17.4 Mechanism Consequences Spinodal decomposition and precipitation in ferrite lead to its hardening and embrittlement. Because of this, the cast SS is going to harden and becomes brittle. The consequences are an impact toughness decrease and an impact test transition temperature increase. Cast SS rupture at room temperature starts with the transgranular brittle fracture by cleavage of the hardened ferrite. Cleavage initiation depends on the angle between the loading direction and the ferrite and austenite orientations. Then, austenite deformation generates cavities between which the final rupture occurs either by tearing or by shearing (Fig. 3.132). When the ferrite is very hard or the temperature at which the load is applied increases, the ferrite rupture can partially occur by albite twinning.

Fig. 3.132 SEM view of the rupture of an unaged (left, ductile with cupules) and of an aged (right, ferrite cleavage and austenite tearing) austenitic-ferritic SS

3.17.5 List of Influent Parameters Parameters Needed for the Phenomenon to Occur • Steel high content in a generating elements (Cr, Mo, Si); • Holding temperature: the mechanism is thermally activated: it typically appears for temperatures lower than 500 °C. It also can appear for lower temperatures but for longer holds. Parameters Impacting the Mechanism Kinetics • Ageing conditions (temperature and holding time). For given steel, the higher the holding temperature or the longer the holding time, the more significant the impact toughness decrease and the hardness

174

3 Failure and Ageing Mechanisms

Fig. 3.133 KCV320°C impact toughness evolution kinetics of an austenitic-ferritic SS for various holding temperatures

increase (Fig. 3.133). For very long holding times, the impact toughness decreases down to the same value, whatever the holding temperature, providing it is 0.90 wt% to P < 0.005 wt% for Mo = 0.10 wt%); – A tempering temperature  600 °C (1112 °F).

3.19

Low Alloy Steels and Carbon Steels Thermal Ageing or Temper Embrittlement

3.19.1 Foreword Two different types of mechanisms can be considered regarding the thermal ageing of LASs: thermal ageing by grain boundaries segregation of elements making the material brittle and thermal ageing after deformation by free interstitials trapping on dislocations. The deformation ageing appears as soon as the reactor starts (typically: 30 min at 250 °C/482 °F) and then stops progressing. Although this phenomenon must be taken into account at the design stage of systems or components, there is no need to consider it for life assessment studies. In the end, the only long-term ageing mechanism to be considered for temperatures lower than 350 °C (662 °F) is the chemical species segregation at grain boundaries. This mechanism is described hereafter.

3.19.2 Mechanism Identification Name: temper embrittlement or intergranular embrittlement. Mechanism type: diffusion based thermal ageing mechanism. Short description: segregation at the steel grain boundaries of chemical species.

3.19.3 Domains of Relevance Temper embrittlement is observed on LASs (and also on some Martensitic steels) quenched, tempered or not, which are maintained between 575 (1067) and 350 °C (662 °F) during long periods of time, or slowly cooled down in this temperature range. For long term ageing between 350 (662) and 300 °C (572 °F), temper embrittlement can also occur, however with a very slow kinetics.

184

3 Failure and Ageing Mechanisms

3.19.4 Phenomenon Description One consequence of the temper embrittlement is an impact toughness transition temperature shift towards higher temperatures without any associated hardness increase. In parallel, the rupture switches from transgranular to intergranular. At a finer scale, temper embrittlement is characterized by certain alloying elements segregation at grain boundaries. Grains cohesion is therefore modified, some element strengthening it, other decreasing it. The steel can become brittle by this later phenomenon.

3.19.5 Mechanism Consequences The intergranular segregation of specific chemical species can drop the grain cohesion (which favors the intergranular rupture), or make grain boundaries corrosion susceptible (in case of chromium depletion). Embrittlement consequences are an increase of the impact toughness transition temperature along with a modification of the rupture mode in the fragile domain: the rupture mode switches from cleavage to intergranular (Fig. 3.137). The transition temperature increases linearly with the concentration at grain boundaries of elements making the material brittle, and this without any hardness increase.

Fig. 3.137 SEM view of an intergranular brittle rupture of a tempered 35 NCD 16 steel (KCV specimen tested at −20 °C (−4 °F))

3.19

Low Alloy Steels and Carbon Steels Thermal Ageing …

185

3.19.6 List of Influent Parameters Parameters Needed for Temper Embrittlement Occurrence • Steel content in segregating elements (P, Sn, Sb, As…) Temper embrittlement occurs only if certain specific impurities are present in the metal. The main impurities having a strong tendency to grain boundary segregation along with an embrittlement power are Sb, P, As and Sn. Among these, P has the strongest effect with a significant embrittlement power from contents as low as 0.005 wt%. • Holding temperature. Temper embrittlement is thermally activated, starting in the 575–350 °C (1067– 662 °F) domain. It also can occur at a lower temperature but for very long holding times, in the order of several hundred thousand hours. It is noteworthy mentioning that the segregation rate increases with the holding temperature as opposed to the segregation amplitude which decreases when the holding temperature rises. Parameters Impacting the Mechanism Kinetics • Alloying elements content. Transition metals series can also segregate at grain boundaries, so can strongly impact the temper embrittlement initiation and amplitude. These elements are effective only when their content exceeds 1 wt% for Ni, Cr, Mn and 0.1 wt% for Mo, Ni, Cr and Mn are deleterious regarding embrittlement whereas Mo, V and W can slower or even arrest it. Ni and Cr association is particularly deleterious. Carbon steels, without alloying elements (contents < 0.5 wt%) can be immune to temper embrittlement. • Mo effect. Mo strongly delays temper embrittlement, with an optimum content of 0.7 wt% (Fig. 3.138). For higher concentrations, Mo carbides precipitation at grain boundaries decreases this grain boundaries mechanical resistance and so impairs the beneficial effect of the lower P segregation. Out of the chemical composition which is of first order magnitude influence on the temper embrittlement, grain size and structure also strongly influence the grain boundaries segregation. • Microstructure impact: The embrittlement amplitude is strongly structure dependent; it increases with the metal quenching speed. The embrittlement amplitude is more important for a martensitic tempered structure than for a bainitic structure which itself is more significant than for a ferritic-perlitic structure.

186

3 Failure and Ageing Mechanisms

Fig. 3.138 Mo impact on the temper embrittlement of steels

• Grain size effect: Increasing the grain size will result in increasing temper embrittlement susceptibility. The grain size impact can be explained by specific grain boundary surface. For large grains, segregation sites are fewer so concentrate more segregation. It is noteworthy to mention that from a practical industrial standpoint, the most susceptible areas are HAZs because they combine two unfavorable factors: a large grain size and a martensitic structure. Note also that these two factors are linked because coarse grain structures temper more easily than finer grain structures; in other words, martensite is obtained even with slow cooling rates with coarse grains.

3.19.7 Susceptible Components Potential components that may suffer from temper embrittlement include those made of LAS and operating close to 350 °C (662 °F) like the pressurizer, especially the coarse grain HAZs (welds).

3.19

Low Alloy Steels and Carbon Steels Thermal Ageing …

187

3.19.8 Preventing and Mitigating Temper Embrittlement • Monitoring There is no temper embrittlement NDE technique, so far. A field component temper embrittlement monitoring would require periodical harvest of small coupons and/or Auger analyses. However, the segregation makes the grain boundaries susceptible to specific etchings, such as picric acid-based etchants. • Preventing temper embrittlement A restriction of the P content associated to and optimum of the Mo concentration will strongly minimize temper embrittlement. Moreover, the fabrication of welds without coarse grains HAZ drastically decreases the risk of thermal ageing. • Repairing temper embrittlement Temper embrittlement can be reversed: heating the aged steel above 600 °C (1112 °F) and cooling it quickly (water quench) will regenerate its original properties.

3.20

Thermal Ageing of 30% Chromium Nickel Base Alloys, Ordering

3.20.1 Mechanism Description Alloy 690 Metallurgy Fabrication The alloy is melted in an electric arc or high frequency furnace, then re-melted by Electro Slag Re-melting. The objectives of the consumable electrode re-melting are: • Metal purification; • Control of the ingot solidification in order to suppress major segregations; • Better homogeneity of the ingot structure. Depending on the component, the manufacturing sequence varies but it contains thermal-mechanical treatments followed by a solution annealing treatment around 1100 °C (2012 °F) and by a final heat treatment at 715 °C (1320 °F) during 5 h. Manufacturing governs chemical composition; some elements increase or decrease ordering and precipitation. The more or less ordered state in the as-received condition depends on the fabrication process. No data exist regarding the impact of fabrication on ageing.

188

3 Failure and Ageing Mechanisms

Table 3.8 Evolution of the Alloy 690 chemical composition Element

FM 387 (1985)

FM 631 (1990)

FM 684 (1993)

C Si max Mn max S max P max Ni min Cr Fe Cu max Co max Co min target Ti max Al max B max Nb max N max

0.01–0.04 0.5 0.5 0.015 0.025 58.0 28.0–31.0 7.0–11.0 0.5 0.1 0.05 0.5 0.5

0.01–0.03 0.5 0.5 0.015 0.025 58.0 28.0–31.0 7.0–11.0 0.5 0.1 0.05 0.5 0.5

0.01–0.03 0.5 0.5 0.01 0.015 58.0 28.0–31.0 8.0–11.0 0.5 0.035 0.018 0.5 0.5 0.003 0.1 0.05

Microstructure and Chemical Composition Alloy 690 has a cubic face centered structure. The final annealing leads to a total recrystallization with a low dislocation density. The microstructure can be characterized by the grain size, the inclusions and the precipitates. The chemical composition of reference varies according to field experience and to regulation evolution. Alloy 690 composition has been tuned to optimize chemical and mechanical resistance. In the 90s, the RCC-M has been modified in order to increase the minimum iron content from 7 to 8 wt% to take into account the long-range ordering risk (Table 3.8). The carbon range has been reduced to minimize the scatter of the mechanical properties. The carbon maximal content allows a total dissolution of the carbides during the annealing treatment along with high impact test properties. The minimum carbon content is sufficient to generate enough intergranular carbides precipitation and meet the required mechanical properties. The [Ti]/[C + N] ratio is going to determine the carbon amount available for chromium carbides precipitation. During thermal ageing, the chromium carbides precipitation is limited by the amount of free carbon in solution. Alloys 152 and 52 Metallurgy Fabrication 30 wt% chromium weld metals are:

3.20

Thermal Ageing of 30% Chromium Nickel Base Alloys, Ordering

189

• Coated electrode 152 (ENiCrFe-7) for arc welding; • Wire 52 (ENiCr-7) for TIG and SAW. The main difference between the base metal and the weld metal is the higher manganese content for this latter. For welds acceptance tests, the stress relief thermal treatment is 16 h at 610 °C (1130 °F), with a heating rate of 55 °C (100 ° F)/h and a maximum cooling rate of 55 °C (100 °F)/h. For reactor pressure vessel head penetrations, the thermal treatment, which covers all buttering stress relaxation thermal treatments, is 20 h at 550 °C (1022 °F) + 16 h at 610 °C (1130 °F) with maximum heating and cooling rates of 55 °C (100 °F)/h. Microstructure In as-received conditions, Alloys 152 and 52 are composed of an austenitic matrix of cubic face centered structure. Titanium nitride carbides likely containing chromium and/or niobium are visible, with sizes ranging from a few micrometers to a few dozen micrometers. Unfrequently, a fine M23C6 type chromium carbides precipitation can be observed into the grains and in the grain boundaries. This precipitation is not observed in single-pass welding. Phenomena Description Chromium-Rich Carbides Precipitation In the as-received conditions, carbon can be found in titanium nitride carbides, chromium carbides Cr23C6 and in interstitial solid solution. During thermal ageing, chromium carbides precipitate into the matrix and in the grain boundaries. The amount of precipitation is limited by the free carbon content. Ordering This transformation is relevant to substitution solid solutions where B atoms can replace A atoms in the crystal mesh in case of a binary alloy. For many alloys, atoms are randomly distributed, which is called disordered solid solution. When the atoms distribution is not random anymore, an ordered phase shows up. Two ordered structures exist: short-range order (SRO) and long-range order (LRO). Short Range Order SRO exists when the closest neighbour atoms can be determined with a rather high degree of confidence. However, in SRO, determining the nature of distant atoms it almost impossible (Fig. 3.139). SRO occurs after a few hours at 475 °C (887 °F) and likely at the operation temperature. Long Range Order LRO corresponds to an ordered distribution of the atoms: it is possible to determine with a high level of confidence the nature distant atoms (Fig. 3.140). LRO can occur only for temperatures lower than a critical temperature Tc.

190

3 Failure and Ageing Mechanisms

Fig. 3.139 Sketch of the SRO arrangement

Fig. 3.140 Sketch of the LRO arrangement

In the as received conditions, a 30% chromium nickel-based alloy has a solid solution disordered austenitic structure which results from the solution annealing thermal treatment (Cr and Ni atoms are randomly distributed). At operational temperature the atoms are going to order themselves. The final heat treatment changes the precipitation but has no significant effect on the alloy order. Depending on the alloy chemical composition, ordering can affect the whole material or only some domains separated by disordered solid solution. Typically, LRO follows SRO.

3.20

Thermal Ageing of 30% Chromium Nickel Base Alloys, Ordering

191

Chemical Composition Influence LRO leading to the formation of Ni2Cr is observed only in nickel-based alloys for which the Ni/Cr ratio is close to 2. LRO can occur in alloys containing 1 meV) of 2.73 and 6.0  1019 n/cm2. All irradiated specimens exhibit LRO. A 50 Vickers hardness increase is measured along with a yield stress increase ranging from +29 to +74 MPa. In this experiment, the fluence received by the keys are about 10 times the real field fluence. The fluence for which LRO has been observed in this study is too high as compared to the field real one for two reasons. First, the iron content of the tested material is at the upper range of the Alloy 690 specification. Second, the exposure to a given fluence is more damaging for longer integration periods. In conclusion, irradiation strongly enhances the LRO kinetics.

196

3 Failure and Ageing Mechanisms

Cold Work Influence The results of studies carried on 10% CW Alloy 690 and on 30% CW Ni2Cr show that CW accelerates LRO. After 60,000 h at 420 °C (788 °F), LRO is detected on a 20% CW steam generator tube, whereas LRO is detected after 70,000 h when this tube is CW free. Thermal Treatments Influence Very few data are available regarding the influence of fabrication thermal treatments, moreover, the relevant materials are too different from the 30% Cr alloys used in PWRs to be of any help. Potentially Concerned Components The components which may suffer from LRO in 2.5″/
4″: 448
586

SA 105 SA 216 Gr. WCC SA 302 grade B SA 350 grade LF2 SA 350 grade LF3 SA 508 grade 2 Classes 1&2

Elongation over 2″ (%) 

YS (MPa) 

UTS (MPa)

Room temperature

187 HB

197 HB 197 HB

30 35 Cl 1: 38 Cl 2: 35 38

Hardness


30 35

Reduction in area (%) 

Table 4.14 Carbon steels and low alloy steels for pressure vessel applications (reference: AISI). Mechanical properties

4.4 Carbon and Low Alloy Steels 217

SA A 105 E240 SA A 106 grade B–TU42C SA A 106 grade C SA A 134/SA A 283 Grade C SA A 182 grade F11 Class 1 SA A 182 grade F22 Class 1 SA A 216 grade WCB SA A 234 grade WP 11 Class 1 SA A 335 grade P11 SA A 335 grade P22 SA A 516 grade 70 (%C thickness dependent) a If specified

0.60–1.05

0.29–1.06

0.29–1.06


0.90

0.30–0.60

0.30–0.60


1.00

0.30–0.60

0.30–0.60

0.30–0.60

0.85–1.20


0.30


0.35


0.24

0.05–0.15

0.05–0.15


0.30

0.05–0.15

0.05–0.15

0.05–0.15

0.28–0.30

Mn


0.35

C

0.035

0.025

0.025

0.030

0.040

0.040

0.030

0.035

0.035

0.035

0.035

P


0.035

0.025

0.025

0.030

0.045

0.040

0.030

0.04

0.035

0.035

0.040

S


0.50

1.90–2.60


0.50 0.15–0.40

1.00–1.50

1.00–1.50


0.50

0.50–1.00

0.50–1.00


0.60

2.00–2.50


0.40


0.40


0.30

Cr


0.50 0.30

0.40

0.40

0.40

Ni


1.00–1.50

0.20a

0.40

0.40

0.40

Cu


0.50–1.00


0.40

 0.10

 0.10

0.10–0.35

Si

0.87–1.13

0.44–0.65

0.44–0.65


0.20

0.87–1.13

0.44–0.65


0.15


0.15


0.12

Mo

0.03

0.08

0.08

0.05

V


Table 4.15 Carbon steels and low alloy steels for piping applications (references: AISI and AFNOR). Chemical composition (Weight %) 0.02

Nb


218 4 Materials Properties

4.5 Hard-Facing Alloys

219

Table 4.16 Carbon steels and low alloy steels for piping applications (reference: AISI). Mechanical properties Room temperature

UTS (MPa)

YS (MPa) 

Elongation over 2″ (%) 

Reduction in area (%) 

Hardness

SA A105

 483

248

30

30


187 HB

SA A 106 grade B

 414

241

SA A 106 grade C

 483

276

SA A 134 grade C SA A 182 grade F11 Class 1 SA A 182 grade F22 Class 1 SA A 216 grade WCB SA A 234 grade WP 11 Class 1 SA A 335 grade P11 SA A 335 grade P22 SA A 516 grade 70

379–517  414

207 207

30 Axial 16.5 Transverse 30 Axial 16.5 Transverse 25 20.0

45.0

 414

207

20.0

35.0

121–174 HB
170 HB

483–655

248

22

35

414 – 586  414

207

 414

207

483–655

248

30 Axial 20 Transverse 30 Axial 20 Transverse 30 Axial 20 Transverse 20

38

4.5

207

Hard-Facing Alloys

Hard-facing alloys have been selected for LWRs applications mainly because of the following properties: • • • •

High wear resistance; High mechanical properties; Good corrosion resistance; Good thermal shock resistance.

The typical chemical composition of some hard-facing alloys is provided in the following Table 4.17.

Ni

2.2
3 Bal Bal Bal 4.4 4.2 4.4 0.8 0.6 0.7

Typical

Stellite 6 PTA Stellite 12 Deloro 40 CIC Deloro 50 CIC PY150 CIC Norem® 02 A TIG Norem® 02 PTA Norem® 02 CIC Z2 50 CDV 25.4 CIC Delchrome 910 PTA Everit 50 TIG

2.7
3 3.0 3.4 10.2 Bal Bal Bal Bal Bal Bal

Fe

0.2

0.05

0.04

Bal Bal

Co 28.3 26/32 9.6 12.2 29.1 25.7 25.4 25.6 27.9 25.3 25.6

Cr 1.3 1.2/1.7 0.22 0.07 1.63 1.1 1.17 1.2 2.3 3.2 2.3

C

Table 4.17 Hard-facing alloys. Typical chemical composition (Weight %)

1.4 2.4

needs attention to design detail to avoid bombarding certain sections of tubing with high velocity droplets); • High heat transfer rate (thin wall thickness tubes) (the thermal conductivity is not as good as copper alloys so that re-tubing needs a lot of attention to design); • High mechanical properties. The chemical composition and mechanical properties of the most popular titanium alloys are provided in the following Tables 4.20 and 4.21.

Table 4.20 Chemical composition of the most popular titanium alloys (Wt%) ASTM grade

C

H

O

N

Fe

Others

Grade Grade Grade Grade Grade Grade Grade

0.10 0.10 0.10 0.10 0.10 0.10 0.10

0.015 0.015 0.015 0.015 0.015 0.015 0.015

0.18 0.25 0.35 0.40 0.25 0.18 0.25

0.03 0.03 0.05 0.05 0.03 0.03 0.03

0.20 0.30 0.30 0.50 0.30 0.20 0.30

Pure Titanium Pure Titanium Pure Titanium Pure Titanium Pd: 0.12–0.25 Pd: 0.12–0.25 Mo: 0.2–0.4; Ni: 0.6–0.9

1 2 3 4 7 11 12

4.7 Titanium Alloys

223

Table 4.21 Mechanical properties of the most popular titanium alloys Room temperature

UTS (MPa)

YS (MPa)

Minimum elongation (%)

Grade Grade Grade Grade Grade Grade Grade

241 345 441 552 345 241 483

172 276 379 483 276 169 379

24 20 18 20 20 24 12

1 2 3 4 7 11 12

Ti alloys can be supplied as: • • • • • • • • • •

Bar; Billet; Extrusions; Plate; Sheet; Strip; Wire; Rod; Pipe; Tubing (welded seam and seamless).

4.8 4.8.1

Materials Forbidden in the Containment Building Materials in the Containment Building Atmosphere

Mercury is strictly forbidden and aluminum is severely limited. As regards mercury, its main impacts are: • Stress corrosion cracking of stainless steels, nickel-based alloys and copper alloys; • Toxicity when hot; • Can be neutrons-activated. In the same category are included the gallium and alloys which are liquid at room temperature. The relevant equipments are: instrumentation, electrical systems, lightning… Aluminum situation is different as the concern is accidental conditions because aluminum is reacting in caustic environment (spray system) to generate hydrogen. Thus, aluminum should not be used in safety equipments.

224

4 Materials Properties

The relevant equipments are: sensors, electrical cables, lightning (reflector), crane… Note that zinc, which corrodes in caustic environment, is not considered as dangerous, because its general corrosion is very slow. Thus, the use of galvanized steel is not limited.

4.8.2

Polluting Materials

The systems pollutants are: sulphur, lead, zinc, mercury, chlorine, arsenic, fluorine. Relevant products or tools: labelling & marking products, coatings, oils and greases, packaging or cleaning products, organic solvents, machining and handling tools, drying products…

Chapter 5

Nickel Base Alloys

5.1

Background

Nickel base alloys have been widely used mainly for their corrosion resistance (chloride induced corrosion, general corrosion, PWSCC) and their rather high mechanical properties as compared to stainless steel. Here are some examples of components made of or containing some nickel alloys, sometimes designated as Inconel (“Inconel” is a registered trademark of the Special Metals Corporation; formerly Huntington Alloys and INCO Alloys International): • Reactor Pressure Vessel: Butt Welds, Bottom Mounted Instrumentation or Bottom Mounted Nozzles, core support lugs; • Reactor Pressure Vessel head: J-Groove Welds, CRDM, CEDM (CE units), penetration tubes; • Reactors internals: split pins; • Pressurizer: Butt Welds, heaters sleeves, instrumentation nozzles; • Reactor Cooling System piping: Butt Welds, instrumentation nozzles; • Steam Generator: divider plate, Butt Welds, instrumentation taps, drain lines… A very detailed list is not necessary here as destructive examinations have very likely not been conducted on every Reactor Cooling System component made of Inconel or on every equipment having some part made of Inconel. The main nickel alloys used in PWRs RCS are Alloy 600 and 690 base materials. In this regard, Alloys 82 and 182 are the Alloy 600 type weld metals for GTAW (also known as TIG welding) and SMAW, respectively, and Alloys 52 and 152 are the corresponding Alloy 690 type weld metals. These materials are used to weld Alloys 600 and 690 to themselves, to austenitic stainless steels, and to carbon and low alloy steel parts. In addition, these alloys are used as buttering and welds on carbon and low alloy parts, especially where these materials are joined to stainless steel piping, such as at nozzles. © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_5

225

226

5

Nickel Base Alloys

Table 5.1 A600 various structures Structure Type Class I

a or ′ b or″

II

a or ′

III

b or ′ ′ c or ′ ″ –

Carbide precipitation Continuous intergranular precipitation without intragranular precipitation None continuous intergranular precipitation with light intragranular precipitation Mixed intergranular and intragranular precipitation with ghost structure visible Prevalent intragranular precipitation with ghost structure visible Heavy intragranular precipitation with ghost structure visible Heavy intragranular precipitation, more uniformly distributed than in the type IIc structure, the ghost structure is hardly or not visible

In order to rank the various A600 components regarding their PWSCC resistance, a structure classification has been developed at EDF (Table 5.1). Experience with nickel-base alloys in pressure boundary service in nuclear power plants has been good in some applications. However, in other applications some nickel-base alloys have experienced significant degradation; some examples related to RPV, pressurizer and SGs issues are presented in this chapter.

5.2 5.2.1

Destructive Examinations Related to Reactor Pressure Vessel Issues—Results and Remediation Reactor Pressure Vessel Outlet Nozzle Cracking

Plant main characteristics: Westinghouse PWR, 915 MW, 3 loops, Sweden. Equipment/Component: RPV, outlet nozzle to safe end welds. Operating conditions: 325 °C (617°F), primary water. Time of operation: 20 years. Failure discovery: two defects of reportable size were reported during the outage of 2000. Both were located in the outlet nozzle oriented at 265°. The results indicated that both defects were oriented in the axial direction of the safe-end, i.e. in the transverse direction of the weld. A flaw tolerance analysis, verified that operation of the reactor could continue for another cycle, leaving the defects as they were. In 2001 the defects were re-inspected and boat samples from both locations were removed (Fig. 5.1). No increase in the defect sizes could be detected between the inspections, however the relative depth appears to have increased by less than 5 mm (0.2″), corrected for tolerance effects in the depth sizing. In addition, a third

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

227

Fig. 5.1 Sampling geometry of the 265° RPV outlet nozzle

defect was detected in the outlet nozzle oriented at 25 °C during this inspection and a boat sample was removed from this location as well. Similar event frequency: only a handful of RPV butt welds cracking worldwide. Specimen/sample characteristics: a sketch of the relevant weld is shown in Fig. 5.2. All indications were detected in welds produced in the shop. These A182 welds are not heat treated. Prior to welding the safe-end to the RPV nozzle, a weld buttering was applied on the nozzle. After various inspections (ultrasonic inspection, dimensional check, and X-ray radiography), resulting in acceptable results, the nozzle was machined to final dimension. Subsequently, the safe-end was welded to the nozzle. When the weld was completed, it was ground, PT, and inspected by X-ray radiography. There are no documented repairs for the nozzle to safe-end welds. The respective sizes of the three defects, as determined by the ISI during 2001, are shown in Table 5.2. DE goal: characterization of the NDT indications contained in the boat samples.

228

5

Nickel Base Alloys

Fig. 5.2 RPV outlet nozzle. Sketch showing the nozzle to safe end weld (dimensions in mm)

Table 5.2 RPV outlet nozzle. Sizes of indications according to the in-service inspection Nozzle

Location of the indication

Indication length on the safe end weld ID

Depth

Distance from the surface

25°

28°

8 mm (0.31″)

Not determined

265°

299°

18 mm (0.71″)

265°

323°

20 mm (0.79″)

8 mm (0.31″) 13 mm (0.51″) 16 mm (0.63″)

Surface breaking Surface breaking

Results Three boat samples were removed. EDM was used to take out the boat samples. A low machining speed was used in order to achieve a fine surface. Subsequent to machining, all EDM surfaces were inspected by ECT. The sample examined here comes from the nozzle oriented at 25°. As indicated by Fig. 5.3 a small portion of the stainless steel safe-end was included in the boat sample. PT and subsequent inspection by stereo microscopy of the inner surface of the sample (wetted surface) revealed a small surface penetrating defect. No crack or other defect could be observed on the surface. The stainless-steel portion of the boat sample was cut off, and the alloy 182 surface (Surface A) was ground, polished and examined in a LOM. No cracks were detected on this surface. This surface was then ground and polished in steps of 0.5 mm (0.02″), with intermediate examination in LOM, until 8 mm (0.31″) had been removed and the distance to the surface penetrating defect was 3.4 mm

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

229

Fig. 5.3 RPV outlet nozzle. a photograph of the boat sample. Note that the right-hand photograph shows the back of the boat sample, i. e. the EDM surface. b Photograph of the defect on the inner surface of the boat sample

Fig. 5.4 RPV outlet nozzle. Cross section showing surface A and the crack tip region of one of the cracks. A detail of the crack tip region is shown to the right

(0.13″). Two cracks were observed on this surface. Figure 5.4 shows the crack tip region of one of the cracks. The cracks are interdendritic with a width less than 5 µm (0.2 mil). The depth of the crack is *4 mm (0.16″) in this cross section. EDS revealed that the cracks contained oxide, suggesting that the cracks were in contact with primary water during operation. The surface opposite to Surface A (Surface B) was examined in steps in the same way as described above. A very tight crack was observed when the distance to the surface penetrating defect was 3.0 mm (0.12″). The depth and the width of the crack in this cross section were 4.4 mm (0.17″) and 0.1 µm (0.004 mil), respectively. The crack is interdendritic and a detail of the crack tip region is shown in Fig. 5.5a. An overview of the boat sample after grinding and polishing the two surfaces is shown in Fig. 5.5b. This figure also indicates the surface penetrating defect and its distance to the two surfaces.

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Fig. 5.5 RPV outlet nozzle. a detail of crack tip on surface B. The square spot on the right-hand tip is carbon contamination caused by the electron beam from the SEM. b Overview of the inner surface of the boat sample after grinding and polishing the two surfaces. The distances of each surface to the surface penetrating defect (denoted PT-indication), as well as the position of the crack are indicated in the figure

Cracking may have initiated from the surface penetrating defect, probably a weld defect. It should be noted that, except for the surface penetrating defect, no cracks or crack like features could be observed on the inner surface of the weld. In addition, it is likely that the cracks observed on the two surfaces (Surfaces A and B) are connected. Since the cracks observed were interdendritic and branched, as well as oxidized, it is likely that the propagation was caused by interdendritic stress corrosion cracking. This is consistent with the conclusion from the examination of the boat samples removed from the sister unit. Remedial actions Continued operation was justified based on updated fracture mechanics analyses. This analysis was performed to determine allowable defect sizes and the time required for a postulated crack to reach the critical size. As input for the analysis, a relationship between the crack growth rate and stress intensity was established. This was done by compiling available laboratory crack growth data on alloy 182 in PWR primary water, assessing the data quality, and then using data passing a set of screening criteria. Re-inspections and repairs were performed during the following outages.

5.2.2

Reactor Pressure Vessel Outlet Nozzle Repair Cracking

Plant main characteristics: Westinghouse PWR, 915 MW, 3 loops, Sweden. Equipment/Component: RPV, outlet nozzle to safe end welds.

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

231

Operating conditions: 325 °C (617°F), primary water. Time of operation: 21 years. Failure discovery: during the 2000 RFO In-Service Inspection of the nozzle to safe end weld of the Hot Leg Reactor Pressure Vessel Nozzles, axially oriented defects in the Alloy 182 weld metal were detected. This weld, although made in the shop, is not heat treated. The defects were initially considered as being embedded and thus left for future consideration, whereas the defects also detected in the sister Unit were judged as being surface breaking and removed by EDM (Electro Discharge Machining). During the RFO 2001, the defects were also removed by EDM without applying any surface treatment subsequent to the sampling. The cavities were inspected using a standard ET technique for manufacturing control before the plant was allowed to return to service. After one cycle of operation, the cavities resulting from the boat sampling were inspected by ET and UT and indications of renewed, shallow cracking were identified. The indications were pre-dominantly axially oriented, of limited depth and with surface breaking lengths varying from 4 to 18 mm (0.16 to 0.71″). To investigate the cause of this cracking, it was decided to remove a second series of small boat samples from the areas with indications, prior to implementation of a permanent repair. Similar event frequency: only a handful of RPV butt welds cracking worldwide. Specimen/sample characteristics: three mini samples were removed manually in 2003, using a small axial grinder. The sampling was performed after nozzle decontamination and used a dry nozzle access system that had been specifically developed for the nozzle repair. In order to correctly locate the areas of interest for failure analysis, the ET and UT information obtained from the previous ISIs were reviewed and analyzed. In addition to the ISI data, a manual PT was performed to confirm the presence of surface indications. A picture of the PT indications on one of the nozzle cavities is shown in Fig. 5.6. The mini-sample that was later removed from the area with PT indications is also shown in Fig. 5.6. It is noted that this particular location corresponded to the only area inside the nozzle cavities that also revealed UT indications, indicating there was some depth to the defect. In general, the PT indications corresponded well with the locations where ET surface indications were observed, although some of the ET indications could not be confirmed by the manual PT. Following the PT examination, the cavities were marked to facilitate the correct positioning of the removal locations. The overall dimensions of the samples were approximately 7
45 mm (0.3
1.8″) for the samples on the left-hand side of Fig. 5.7 and approximately 18
10 mm (0.7
0.4″) for the square-shaped sample on the right-hand side. The cross sections of the samples were of triangular shape, with a maximum height of approximately 3 mm (0.12″).

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Fig. 5.6 PT of the 265° RPV outlet nozzle cavity prior to boat sampling

Fig. 5.7 RPV outlet nozzle. Mini samples removed from EDM surfaces at 3 different nozzle locations

DE goal: characterization of the NDT indications contained in the boat samples. Results The general surface appearance of the EDM surface is shown in Fig. 5.8 left. The so-called re-cast layer has the typical morphology as resulting from the spark erosion process with its localized solidification. At larger magnifications, micro fissures, as may result from the EDM process, were clearly visible, Fig. 5.8 right. A subjective description of the general fissure frequency is that “they are quite numerous but the fissure density is not very high”. The micro fissures general length was varying between 0.1 and 0.7 mm (0.004–0.03″). The general fissure width was 0.5–1.0 lm (0.02–0.04 mil). A few fissures were wider (between 5 (0.2) and 10 lm (0.4 mil)).

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

233

Fig. 5.8 Left: RPV outlet nozzle. General appearance of the EDM surface observed on the boat samples. Right: RPV outlet nozzle. Microcracks resulting from the EDM process observed on the boat samples

On one of the samples, i.e. the rectangular sample of Fig. 5.7, more pronounced surface defects were observed that directly correlated to the UT, ET and PT indications revealed prior to sample removal. These larger surface defects were found to have an appearance that was quite different from the generally present micro fissures and are shown in Fig. 5.9. They also resulted in more clearly discernable PT indications. The position of the defects was close to the area where the last ligament connecting the original boat samples to the outlet nozzle was sectioned, a situation known to lead to process difficulties as the distance between the electrode and the sample is no longer perfectly controlled. The visible length of the defects was in the order of 2.5 mm (0.1″). The general micro fissure density in the vicinity of these larger defects was, in general, higher than what was observed on the other sample areas. It is noted, however, that surface areas with larger micro fissure density were observed on all three boat samples and that these areas generally corresponded to the areas where the ISI ET signals identified surface defects. Following the surface examinations, the samples were embedded and metallographically examined using LOM. The general aspect of the cross sections revealed many small surface breaking incipient cracks. In general, the depth of the fissures was 30–100 µm (1.2–4 mils), although deeper cracks with depths ranging from 200–260 µm (8–10 mils) were also observed. Typical cross sections of the samples at locations with micro fissures are shown in Fig. 5.10. Examination of various cross sections on the square sample, revealed larger defects, especially in the area where the larger surface defects were observed. As the square sample was severed for examination of different cross section, a through-sample defect was observed that extended over the length of the sample portion. The cross-sectional view of the square sample at the through-sample defect location is provided in Fig. 5.11. The defect extended approximately 3 mm (0.12″) into the Alloy 182 weld metal and the defect length was limited by the length of the sample portion under investigation, or approximately 4 mm (0.16″). To allow for fractographic examinations, it was decided to open the sample, breaking it into two

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Nickel Base Alloys

Fig. 5.9 RPV outlet nozzle. SEM image of sample at location of large surface defects

Fig. 5.10 RPV outlet nozzle. General cross-sectional aspect of the EDM micro fissures (LOM scale bar = 100 µm–4 mils)

pieces along the faces of the crack. One side was retained for etching and metallography and the other side was used for fractography. The left part of the cross section shown in Fig. 5.11 was electrochemically etched to reveal weld structure and to study and illustrate the grain boundary branching of the surface breaking cracks in the cross section. The severe mechanical damage that has been forced

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

235

Fig. 5.11 RPV outlet nozzle. Cross section of the square sample showing the through wall defect

upon the area during the sampling is noted and can be seen in the bottom portion of the sample in Fig. 5.11. An image of the etched cross section is presented in Fig. 5.12. The larger surface defects discussed earlier can clearly be seen at the top of the image. The crack path directly below the EDM defects indicates, however, that a service-induced damage mechanism initiated from some of the EDM defects, equally practically extending through the thickness of the sample. The crack propagation mechanism was clearly intergranular and could indicate renewed PWSCC of the Alloy 182 safe end weld, possibly as a result of the larger surface defects, resulting from process irregularities during the implementation of the EDM process.

Fig. 5.12 RPV outlet nozzle. Cross section of the square sample after electrochemical etching

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Nickel Base Alloys

Fig. 5.13 Left: SEM observation of the crack surface of through sample crack. Right: SEM fractography showing torn dendritic arm

Results of the SEM fractography performed on the right-hand side of the sample (Fig. 5.11) are shown in Fig. 5.13. The relative ease by which the sample could be opened was consistent with the observations that the two fracture surfaces were only held together by a few unbroken ligaments (dendritic arms, Fig. 5.13 right). Examination of the fracture surfaces revealed that cracking was intergranular. The macroscopically observed character of the surface revealed a fracture typical of stress corrosion cracking in Alloy 182, i.e. PWSCC. The fracture surface was found to have a sharp topography. Secondary cracking between the dendrite arms was also present. There were minor areas on the fracture surface that may have been related to hot cracking. These areas appeared to be flatter than the other parts of the fracture surface. In addition, these areas also appeared to be smoother. Despite the observation of some minor hot cracks, the conclusion was that the crack propagation mechanism was predominantly PWSCC. Remedial actions Several observations resulted from the failure analysis of three small boat samples removed from the. Alloy 182 nozzle to safe end weld, directly before the permanent 2003 nozzle repair. The most important are: 1. The Evidence that the EDM process consistently leaves Numerous crack-like indications in the form of micro fissures at the surface. 2. The indications of re-occurring SCC crack growth initiating at the EDM surface, in particular in areas when the process has left larger surface defects, possibly related to process irregularities. A quantification of the reduction in crack initiation time as compared to a surface subject to mechanical or other removal methods is impossible to make with the information obtained from the samples. However, certain aspects of the localized surface condition resulting from EDM combined with the unfavorable recast

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

237

structure seem to have led to SCC initiation and possibly the growth of a defect with a depth of at least 3 mm (0.12″) over 2 operating cycles. The general service experience of Alloy 182 under PWR operating conditions has been far more positive than this, pointing towards the negative influence of the EDM process. This is consistent with laboratory data on SCC performance of Alloy 600 type of materials with EDM surface finish. As stated previously and based in the observations presented here, it can hardly be recommended to leave EDM surfaces of susceptible Alloy 600 type of materials exposed to PWR service conditions for an extended period of time, unless the process has been validated for acceptable surfaces. On the other hand, EDM remains an attractive material removal technique in support of failure analyses on operating nuclear power stations. Research on adequate post EDM surface conditioning techniques or possibly improving the EDM process relative to the SCC performance of the as-delivered post EDM surface is therefore recommended to ensure that this attractive sampling technique can still safely be applied on Alloy 600 type of materials.

5.2.3

Reactor Pressure Vessel Outlet Nozzle Dissimilar Weld Cracking

Plant main characteristics: MHI PWR, 1180 MW, 4 loops, Japan. Equipment/Component: RPV, outlet nozzle to safe end weld (Fig. 5.14). Operating conditions: 325 °C (617°F), primary water. Time of operation: 17 years.

Fig. 5.14 RPV outlet nozzle dissimilar weld design

SS safe end LAS nozzle

Stainless steel cladding

OD: 882 mm (34.72’’)

A600 base Ni alloy weld

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Nickel Base Alloys

Failure discovery: during the 2008 RFO, an eddy current test was carried out for checking prior to the implementation of waterjet-peening treatment of the reactor vessel inlet/outlet nozzles weld. This action was part of the preventive maintenance measures, based on the events of stress corrosion cracking which occurred at nickel-based Alloy 600 welds in Japan and foreign countries. As a result, significant signal indications were identified at one location on the dissimilar butt weld of the loop-A outlet nozzle. No significant ECT indication was identified on the welds of reactor vessel loopA inlet nozzle and loop-B, -C and -D inlet/outlet nozzles. Similar event frequency: only a handful of RPV butt welds cracking worldwide. Specimen/sample characteristics: no specimen was harvested from the defective nozzle. The weld was ground down to the sound underlying metal. Examination goal: characterization and removal of the ECT indications observed at the weld surface. Results NDE (ECT, VT and UT) The ECT inspection discovered a 10 mm long linear indication in the A600 weld (Fig. 5.15). A VT with a submarine camera confirmed the presence of a 3 mm (0.12″) long branched crack, similar to the PWSCC cracks already observed in some other units (Fig. 5.16). Therefore, an ultrasonic test was conducted to measure the depth of the flaw at the location where significant signal indications were confirmed from ECT and it was estimated to be a shallow flaw whose depth could not be measured. Hence, it was decided to proceed with step grinding, with ECT inspection between each step. The Fig. 5.17 shows the 3.4 mm (0.13″), 3.6 mm (0.14″) and 4.6 mm (0.18″) steps inspection results.

SS clad ID LAS nozzle

Length: about 10 mm (0.4íí) Depth: not measurable

SS safe end

74.6 mm (2.94íí)

Fig. 5.15 RPV outlet nozzle dissimilar weld. Result of the ECT and UT inspections

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

239 Nozzle side

Indication sketch

~3 mm (0.12”)

Safe end side Machining marks

Fig. 5.16 RPV outlet nozzle dissimilar weld. Optical view and sketch of the ECT indication

Clearing the flaw At the location of the defect, the weld was 74.6 mm (2.94″) thick. The minimum weld thickness specified in the original plant specifications was 70 mm (2.76″). However, later refined calculations dropped this minimum thickness specification to 64 mm (2.52″). In order to know the depth of the defect, the concerned area was ground to this target depth of 64 mm (2.52″). At 64 mm (2.52″), the defect being still detectable, the grinding sequence was resumed. Eventually the ECT indication disappeared after 20.3 mm (0.8″) of weld thickness has been ground (Fig. 5.18). The detailed investigation of the cracking cause led to the following conclusion: during the reactor vessel fabrication, high residual tensile stresses were generated by the welding of the reactor vessel-A loop outlet nozzle to the safe end, and the final machining. Based on previous domestic and international experience, it is assumed that PWSCC could initiate and propagate. Waterjet-peening was applied to the ground cavity in order to generate compressive residual surface stresses and the unit could restart for one cycle (Fig. 5.19). A repair using welding buildup of A152/52 type material was planned to be implement at the next periodic inspection. As a further response, based on the fact that flaw depth had not been evaluated, the knowledge about flaw depth evaluation technology will be enhanced by strengthening the detection capability of tip diffraction echo, including the usage of echo from the opening of a flaw, which could be easily detected in comparison with the tip diffraction echo.

240

5

Nickel Base Alloys

VT inspection results after grinding the surface by ~3.4 mm (0.13”) depth

~13 mm (0.51”)

Sketch of the flaws VT inspection results after grinding the surface by ~3.6 mm (0.14”) depth ~13 mm (0.51”)

Sketch of the flaws

VT inspection results after grinding the surface by ~4.6 mm (0.18”) depth ~12.5 mm (0.49”)

Sketch of the flaws

Fig. 5.17 RPV outlet nozzle dissimilar weld. VT inspection results after grinding. At -3.4 mm (0.13″) the indication is *13 mm (0.51″) long, −3.6 mm (0.14″) the indication is also *13 mm (0.51″) long. At -4.6 mm (0.18″) the indication is 12.5 mm (0.49″) long

5.2 Destructive Examinations Related to Reactor Pressure Vessel … Ground cavity

SS clad

The flaw is a branched PWSCC crack; assumption was made its propagation was interdendritic.

Direction of the weld dendrites

241

Nozzle

Safe end

A182 type butter Sketch of the flaw cross section

SS clad

A182 type weld Ground cavity

SS clad

Approximately 21 mm (0.83’’)

Approximately 20.3 mm (0.8’’) Approximately 74.6 mm (2.94’’)

Shape of the flaw

LAS nozzle

Safe end

Safe end

LAS nozzle A182 type butter

A182 type weld

A182 type butter

A182 type weld

Fig. 5.18 RPV outlet nozzle dissimilar weld. Sketch of the ground cavity and of the flaw Conclusion, remedial actions

Spray nozzle Water Water jet Spray nozzle

LAS nozzle

Weld

Safe end

LAS nozzle

Safe end

SS clad

Weld

Fig. 5.19 RPV outlet nozzle dissimilar weld. Sketch showing the implementation of water-jet peening to the ground cavity

242

5.2.4

5

Nickel Base Alloys

Reactor Pressure Vessel Outlet Nozzle Leak

Plant main characteristics: Westinghouse PWR, 933 MWe, 3 loops, USA. Equipment/Component: RPV outlet nozzle, dissimilar butt weld. Figure 5.20 presents the design and fabrication of the leaking butt weld. Figure 5.21 shows the actual weld joint configuration. Operating conditions: primary water, 618°F (326 °C). Time of operation: 18 years. Failure discovery: in October 2000, the plant was shut down for a scheduled refueling outage. During a containment inspection, a large quantity of boron was discovered on an RCS hot leg pipe at the primary shield wall penetration. This boron had originated from a weep hole discovered on the DM weld of a RPV outlet nozzle (Fig. 5.22).

Inconel® weld ENiCrFe-3; ERNiCr-3 RCS hot leg nozzle SA-508 class 2

RCS piping SA-376 forged 304N, 34’’ OD

2.33’’ (59.2 mm) minimum

SS cladding Inconel® butter ENiCrFe-3

Fig. 5.20 RPV outlet nozzle, DM weld. Left: original design. Right: as built configuration after repair

Fig. 5.21 RPV outlet nozzle, DM weld. Cross section macrography of the nozzle to pipe junction

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

243

Fig. 5.22 RPV outlet nozzle, DM weld. 3/16″ (4.8 mm) diameter weep hole at the origin of a primary water leak

The leak was not discovered during operation because the total unidentified RCS leak rate was well below the maximum 1 gpm (227 l/h) technical specification leak rate limit. Fuel integrity was and had been very tight for many cycles so containment radiation monitors were unable to detect an increase in radioactivity. After the fact, detailed analysis of RCS leak rate data during the operating cycle did identify a very slight step increase in RCS leak rate that the operator projected to be the initiation of through wall leakage. Similar event frequency: no other similar reported event. Specimen/sample characteristics: a 12-inch (305 mm) spool piece containing the affected nozzle weld was sectioned off and sent to a hot laboratory for root cause assessment (Fig. 5.23). The material properties are (room temperature/619° F–326 °C):

Fig. 5.23 RPV outlet nozzle, DM weld. Removed spool piece. Left: as received at the hot laboratory. Right: layout of the sectioned pieces

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5

Nickel Base Alloys

• Hot leg piping (304 forging): YS = 215/159 MPa, UTS = 536/492 MPa; • RPV nozzle (508 class 2 forging): YS = 345/289 MPa, UTS = 517/517 MPa; • Weld (Alloy 182): YS = 379/300 MPa, UTS = 552/552 MPa. DE program and goal: failure (leak) root cause assessment. The program included: surface examinations, UT, ECT, metallography, SEM, EDS, microprobe analysis, micro hardness, residual stresses measurements. Results: Surface examination of the as-received pipe showed evidence of approximately 2.5″ (63 mm) long axial crack of a 2.0″ (51 mm) long circumferential crack in the nozzle (Alloy 182) cladding below the nozzle corner, on the ID corresponding to the weep hole position on the OD (Figs. 5.24 and 5.25). Surface examination of the decontaminated spool piece revealed the presence of a circumferential crack on the ID surface in the nozzle Inconel® cladding intersecting the axial crack (Fig. 5.26). UT and ECT examinations confirmed the locations of several axial ECT indications in addition to the two main cracks. Majority of the eddy current indications were oriented along axial direction and exhibited cracking morphology similar to the axial crack. The eddy current indications were positioned in the Alloy 182 clad/

Fig. 5.24 Appearance of the crack at 7° clock location on the ID Surface of the spool piece in the as-received condition

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

245

Weld

Nozzle

Fig. 5.25 RPV outlet nozzle, DM weld. ID surface showing axial (2.5″, 63 mm) and circumferential (2″, 51 mm) cracks

1 cm

butter region on the ID suggesting that the axial through wall crack may have been initiated in the Alloy 182 clad/buttering. The metallographic examinations suggested multiple crack initiation sites seen on the ID in the axial crack. Hot cracking may be present in the weld as suggested by micro-fissuring. Cracking followed micro-fissuring and interdendritic morphology (Fig. 5.27). The circumferential crack on the ID was initiated in the Inconel® buttering of the DM weld and progressed up to the interface but not into the ferritic steel. The cracking morphology of the circumferential crack and the ECT indications resembled the morphology of the axial crack. Fractographic examinations confirmed the interdendritic morphology of cracking (Fig. 5.28) and further showed that the main axial crack went through-wall at the weep hole (Figs. 5.29 and 5.30).

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5

Nickel Base Alloys

Fig. 5.26 Appearance of circumferential and axial cracks

1 mm

Fig. 5.27 RPV outlet nozzle, DM weld. Left: morphology of the through wall axial crack in the bulk butter/weld. Right: morphology of this crack at the ID surface

Fractographic examinations also confirmed that the axial crack in the weld generally followed the ferritic steel interface on the nozzle side and stainless-steel interface on the pipe side. No cracking either of the ferritic steel or of the SS pipe (only some minor cracking in HAZ) have been observed. Some minor wastage, 120 µm (4.58 mils) deep and between 20 (0.8 mil) and 40 µm (1.6 mils) wide, has been observed at the tip of the circumferential crack (Fig. 5.31).

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

247

Fig. 5.28 RPV outlet nozzle, DM weld. Fracture morphology of an ECT indication

4 mm (0.16’’)

Fig. 5.29 RPV outlet nozzle, DM. Fracture morphology at the weep hole region. The main axial crack breaks the OD surface over a 4 mm (0.16″) distance

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5

Nickel Base Alloys

Fig. 5.30 RPV outlet nozzle, DM weld. Shape of the axial crack in the wall thickness in the weld

Fig. 5.31 Wastage in the carbon steel at the tip of the circumferential crack (polished and etched)

5.2 Destructive Examinations Related to Reactor Pressure Vessel … Fig. 5.32 RPV outlet nozzle, DM weld. Cross section of the through wall axial crack. Crack has initiated in A182 and propagated in A182 and A82

249

OD

A82

A182

ID

Approximate chemistry traverse measurements across the wall thickness in the weld showed that Alloy 182 was deposited on the ID and Alloy 82 on the OD; on the section of Fig. 5.32, Alloy 82 was predominant deposit in the weld. Net tensile residual hoop stress was estimated in the weld by displacement measurement technique. Conclusion, remedial actions: The RPV outlet nozzle leak is due to an axial through-wall PWSCC crack. One circumferential crack and other axial cracks have also been observed in the vicinity of the main through-wall axial crack. The leak occurred through a weep hole. High residual stresses can originate from the way this DM was repaired in fabrication.

250

5

Fig. 5.33 RPV outlet nozzle. Sketch of the repair with a spool piece

Nickel Base Alloys

A52 buttering

RPV nozzle

SS spool piece

Nozzle to spool piece weld

SS pipe

Spool piece to pipe weld

The nozzle was repaired with a spool piece, welded in narrow gap for residual stresses reduction, and with improved materials (such as A52 which is much less prone to PWSCC than alloys 182/82) (Fig. 5.33). The nozzle DM weld was further remediated from ID stress initiators of PWSCC by applying the Mechanical Stress Improvement Process (MSIP®), which is a patented process by Westinghouse.

5.2.5

Destructive Examination of a Boat Sample Removed From a Leaking Bottom Mounted Instrumentation Nozzle at a W Plant

Plant main characteristics: Westinghouse PWR, 1250 MWe, 4 loops, USA. Equipment/Component: RPV bottom head, BMI made of A600. Operating conditions: primary water, 560°F (293.3 °C). Time of operation: *100,000 h. Failure discovery: during a visual inspection of the instrument penetrations at the bottom of the reactor vessel, a small amount of white residue was discovered around the outer circumference of two (#1 and #46) of the 58 BMI penetrations (Fig. 5.34). Subsequent analysis revealed that the residue contained boron, indicating that the source of the residue may have been from the reactor coolant system. No corrosion wastage of the reactor vessel was observed. Similar event frequency: low occurrence, 6 events: three BMIs’ leaks at two plants, one BMI with PWSCC and two BMIs with NDE indications of PWSCC at two different plants worldwide so far. Specimen/sample characteristics: boat samples (one each from #1 and #46) were removed. However, only the BMI #1 boat sample could be retrieved and analyzed. On Fig. 5.35, a circumferential crack location corresponds to a helium leak location.

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

251

Boric Acid Deposits

Boric Acid Deposits

1.5" (38 mm)

1.5" (38 mm)

Fig. 5.34 Site photograph showing boric acid deposits adjacent to nozzle #1 (left) and nozzle #46 (right) OD at the bottom of the reactor vessel

The sample measured approximately 1.3`` (33 mm) long by 0.4'' (10 mm) wide by 0.3`` (7.6 mm) thick. The circumferential crack was jagged in nature and measured approximately 0.2'' (5.1 mm) in length. No other cracks were observed on the wetted surface of this boat sample. A crescent-shaped split measuring approximately 0.25`` (6.35 mm) in length was observed on the convex EDM surface of the boat sample. This split was identified as defect #1. Also, present were a nozzle axial flaw and a smaller, similarly-shaped opening measuring approximately 0.07'' (1.8 mm) in length. This opening, identified as defect #2, was filled with yellow deposits. Rather extensive branched cracking was observed between defect #1 and defect #2; however, these defects were not connected by the cracking on the EDM surface. DE goal and program: failure (leak) root cause analysis. The examinations included: visual inspections, stereo visual inspections, X-ray radiography, high resolution replication, SEM, EDS, and metallography.

Nozzle axial flaw

Defect #1

Defect #2

1 cm

Fig. 5.35 Left: low magnification photo of the wetted (concave) surface of the nozzle #1 boat sample. The location of a circumferential crack is indicated. Right: low magnification photograph showing convex EDM surface of the nozzle #1 boat sample. The locations of defect #1, defect #2, and the nozzle axial flaw are indicated

252

5

Nickel Base Alloys

Results Three distinct lack-of-fusion cavities (defects #1, #2, and #3) were identified in the J-groove weld along the BMI nozzle OD surface and the J-groove weld interface (Fig. 5.36). These three cavities were elongated in the circumferential direction along the nozzle OD surface. However, part of cavity of defect #1 was seen between two passes of weld metal. The evidence from the boat sample indicates that these three cavities were internal (i.e., below the wetted weld surface) and not likely exposed to the primary water in the as-fabricated condition. A large axial crack was identified in both the BMI nozzle and the J-groove weld portions of the boat sample. This axial crack intersected the tip of defect #1 at the nozzle OD to Jgroove weld interface. Although the axial crack and the circumferential crack did not directly intersect each other, they were linked through defect #1. In addition, defect #3 was intersected by a branch of the axial crack; hence it too was connected to defect #1 and the circumferential crack. The largest lack-of-fusion cavity, defect #1, was approximately 0.25`` (6.4 mm) in length circumferentially along the nozzle OD surface. A short circumferential crack was also present on the wetted surface of the J-groove weld above defect #1. This circumferential crack traversed the 0.080'' (2.0 mm) depth of weld metal between the wetted J-groove weld surface and the cavity wall of defect #1. A dark yellowish substance was found entrapped in defects #2 and #3. EDS analysis results indicate that the substance consisted of C, Ca, F, O, Si, Ti, and Al, which are typical elements in the flux coating used for Alloy 182 weld rods. Hence, the lack-of-fusion cavities were at least partly due to inclusion entrapment in the weld pool during fabrication. A small amount of residual deposits was also found on the cavity wall (weld metal side) inside defect #1. These deposits were consistent with flux composition as Al and Ti elements were identified by EDS analysis. Because defect #1 was part of the leak path (as it was intersected by both the axial and circumferential cracks), most entrapped flux inclusions would have been dissolved or removed by the leaking primary water. On the other hand, it is also possible that these deposits were originally from defect #3. The weld materials adjacent to the three defects were consistent with Alloy 182. No weld repairs by

Nozzle axial flaw Nozzle

Defect #1 Defect #2

Defect #3 J-Groove Weld 1 cm

1 cm

Fig. 5.36 BMI #1 boat sample. Left: positive X-ray image showing defect locations and axial flaw in nozzle #1. Defect #1, defect #2, and the nozzle axial flaw were open to the EDM surface; defect #3 was not. Right: low magnification BSE mosaic of the EDM surface. The dashed line indicates the interface between nozzle and the J-groove weld

5.2 Destructive Examinations Related to Reactor Pressure Vessel … Fig. 5.37 BMI #1 boat sample. Photograph showing section locations. The white line shows the helium leak location on the wetted surface of the boat sample for orientation purposes

253

Cut #1 Cut #2 Cut #3 Cut #4

1A

1B

1C

1D

1E

0.25" (6.4 mm)

Alloy 82 were identified. The SEM/EDS examinations did not reveal any evidence of hot cracking in the J-groove weld, either adjacent to or near the three lack-offusion cavities or in the remainder of the boat sample specimen evaluated. The boat sample was sliced according to Fig. 5.37 for internal defect examination. The cut faces are presented on Fig. 5.38. Very shallow intergranular cracks of approximately 1 grain deep (typical depth 0.4 mil or 10 µm) were present on the cavity walls of defects #1, #2, and #3 (Fig. 5.39). The same shallow intergranular cracks were found on both the BMI

(b)

(a) Nozzle

J-groove weld

Nozzle

J-groove weld Defect #1

Defect #1

(c) Nozzle

Defect #3

(d) J-groove weld

Nozzle

J-groove weld

Defect #2

Fig. 5.38 BMI #1 boat sample. Photographs showing a the cut #1 surface on piece 1A (the edge of defect #1 is visible); b the cut #2 surface on piece 1B (the edge of defect #1 is visible); c the cut #3 surface on piece 1C (defect #3 is visible) and d the cut #4 surface on piece 1D (defect #2 is visible)

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40 µm

Fig. 5.39 BMI #1 boat sample. Left: upper left portion of defect #1 showing shallow intergranular penetrations into J-groove weld (as-polished). Right: BSE micrograph taken of the upper portion of defect #1. The oxide layer was approximately 1–2 microns thick. Several shallow intergranular penetrations are visible as well

nozzle and the J-groove weld of the cavity wall. Hence, they were not due to hot cracking. These shallow intergranular cracks appear to be consistent with corrosion due to ingress of primary water. It cannot be determined if the dissolved flux in the primary water could have increased the corrosion potential inside these cavities. Under certain conditions, the shallow intergranular cracks observed on the cavity walls could have served as initiation sites for stress corrosion cracking from the defect inside surfaces into both the BMI nozzle base metal and the J-groove weld metal. The circumferential crack was approximately 0.22`` (5.6 mm) long at the wetted weld metal surface, which is about the same length as defect #1. On the wetted J-groove weld surface, grinding marks perpendicular to the circumferential crack were visible under a stereo microscope, but not visible by unaided human eyes. Metallography performed on the cross section of the boat sample revealed no discernable cold worked layer from the grinding on the wetted J-groove weld surface. The entire wetted J-groove weld surface contour in the boat sample is smooth and shows no evidence of abusive grinding. This circumferential crack was opened into two halves for SEM fractography (Fig. 5.40) and metallography (Fig. 5.41). However, the crack surfaces were covered by a layer of oxide corrosion product tenaciously attached to the substrate weld metal. An attempt to remove this oxide layer without damaging the substrate weld metal was unsuccessful. The SEM fractography of the wetted J-groove weld surface of the circumferential crack indicated cracking to be intergranular. No definitive evidence of fatigue was observed. Oxide thickness measurements made along the 0.080'' (2.1 mm) ligament show significant scatter and therefore did not provide any conclusive evidence regarding the crack propagation direction.

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Wetted Surface

0.5 mm

Wetted Surface 1B1

1B2

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1B1

1B2

Fig. 5.40 BMI #1 boat sample. Left: piece 1B cut #1 surface. Right: piece 1B cut #2 surface. The dotted white line indicates the fracture location

Wetted Surface

1 mm

100 µm

Crack in nozzle 1 mm

Fig. 5.41 BMI #1 boat sample. Left: ground face #1 for specimen 1B1. 5% nital etch. Right: Micrographs showing the main defect fracture surface. 5% nital etch

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Fig. 5.42 BMI #1 boat sample. Two-frame mosaics of specimen 1D showing defect #3 and a crack in the nozzle emanating from the EDM surface. 5% nital etch

1 mm

A short intergranular crack was identified on the cavity wall of defect #3 (Fig. 5.42). The tip of this crack was approximately 0.020`` (0.51 mm) into the Jgroove weld, significantly deeper than the shallow intergranular cracks (typically 0.0004'' or 10 µm deep) on the cavity walls. Even though this crack did not break the wetted J-groove weld surface, its orientation was the same as the circumferential crack connecting defect #1 to the wetted J-groove weld surface. Defect #3 was located approximately 0.180`` (4.6 mm) below the wetted Jgroove weld surface. The extent of the axial crack and its branch in the boat sample was revealed by progressive grinding and metallography (Fig. 5.43). The axial crack and its branch in the BMI nozzle and J-groove weld were intergranular and the crack morphology was consistent with PWSCC observed in Alloy 600 CRDM nozzles and other Alloy 182 welds in PWRs. The branch of the axial crack intersected defect #3 perpendicularly to the circumferential orientation of the defect. The branch of the axial crack gradually disappeared on the J-groove weld side of defect #3. In addition, metallography shows the same crack branch in the nozzle, extending from the EDM surface in a direction toward defect #3. All these findings demonstrate that this branch of the axial crack was propagating toward defect #3 from the BMI nozzle side and was blunted by its intersection. In the nozzle portion of the boat sample, the axial crack was longer toward the nozzle inner diameter (ID) than the nozzle OD. The upper extent (i.e., toward the upper RV head) of the axial crack did not penetrate the nozzle OD surface above the toe of the J-groove weld. Hence, the through-nozzle-wall portion of the axial crack was below the J-groove weld wetted surface. In the J-groove weld, the axial crack front was also well below the wetted surface of the J-groove weld.

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1 mm

Nozzle

J-Groove Weld

Fig. 5.43 BMI #1 boat sample. Left: 1st face (specimen 1C) of the polishing grinding. Red line indicates nozzle/weld interface. Cracking extended through the entire specimen in this plane. As-polished. Right: summary of crack depth in progressive grind faces. The crack pattern indicates crack propagation was from the nozzle ID to nozzle OD (i.e., left to right in the photo). There was no evidence that a through wall crack was present in the nozzle above the J-groove weld

Conclusion and remedial actions: PWSCC and LOFs have been observed on the BMI #1 boat sample. Based on the findings of this DE, it appears that the axial crack in the limited material of the boat sample propagated in a direction from the nozzle ID toward the nozzle OD and into the J-groove weld. However, given that the boat sample contained only 1/3 of the nozzle wall thickness from the OD, no definitive conclusion can be drawn regarding the initiation side (ID or OD) of the BMI #1 cracking. Both leaking nozzles (#1 and #46) have been repaired using the half nozzle repair technique (Fig. 5.44). Note that in this repair, the bottom head low alloy steel is exposed to the primary water, the junction between the top and bottom nozzles not being tight. However, no significant risk of corrosion has been evidenced.

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Mechanical plug used during repairs (not shown)

Existing BMI nozzle

Original structural weld

Alloy 52 weld pad

Alloy 52 J-Groove weld

Alloy 690 replacement nozzle

NiCrFe socket weld

Fig. 5.44 Sketch of the BMI half nozzle repair

Original BMI Thimble Guide Tube

Nickel Base Alloys

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5.2.6

259

Laboratory Analysis of a Boat Sample Removed From a Leaking Bottom Mounted Instrumentation Nozzle at a CE Plant (Hyres 2015)

Plant main characteristics: Combustion Engineering PWR, 1300 MWe, 2 loops, USA. Equipment/Component: RPV bottom head, BMI made of A600. Operating conditions: primary water, 565°F (296 °C). Time of operation: 16.15 EFPYs. Failure discovery: on October 6, 2013, during unit end-of-cycle 17 refueling outage, white boric acid crystals were discovered on the bottom head of the rector pressure vessel around the annulus of bottom-mounted instrumentation nozzle #3 (Fig. 5.45). The remaining 60 BMI nozzles were clean. After the discovery, ultrasonic examinations were performed on nozzle #3. In addition, an eddy current examination of the nozzle inside diameter surface was performed. No indications were found on the Alloy 600 nozzle ID surface by UT or ECT. However, the UT examinations revealed four long axial indications that spanned the height of the J-groove weld, multiple short axial indications, and a band of inclusions near the J-groove weld wetted surface (Fig. 5.46). Azimuthally, these features spanned an arc of *80° on the outside diameter of the 7.6 cm (3'') diameter nozzle near the uphill side of the J-groove weld. The same UT and ECT were performed on the remaining 60 BMI nozzles from the nozzle ID side without finding any unacceptable indications. Similar event frequency: low occurrence, 6 events: three BMIs’ leaks at two plants, one BMI with PWSCC and two BMIs with NDE indications of PWSCC at two different plants worldwide so far.

Fig. 5.45 BMI nozzle #3 visual inspection in 2010 (left) and in 2013 (right)

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Fig. 5.46 Left: BMI nozzle #3 UT indications, 4 large axial flaws #1 through #4, 6 small axial flaws #5 through #10, and an inclusion band denoted by solid red box. Right: section view of UT axial flaw profile

Specimen/sample characteristics: to pinpoint the nozzle #3 leak location on the wetted surface, a helium leak test was performed by pressurizing the nozzle #3 annulus to about 0.28 MPa (40 psi) while inspecting the inside wetted surface for exiting helium bubbles. Helium bubbles were observed rising from a location at 40° (referenced to the vessel centerline) near the upper toe of the J-groove weld (Fig. 5.47). A boat sample centered at 40° was cut with electrostatic discharge machining. The boat sample was intended to capture the observed helium bubble exit point, at least one axial indication, a portion of the inclusion band, and nozzle base metal and weld metal (Fig. 5.48).

Fig. 5.47 BMI nozzle #3 helium leak test found exiting bubbles near 40°

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Fig. 5.48 The boat sample was centered at (40°) to capture helium bubble exit location (dimensions in inches)

DE goal and program: leak root cause analysis. Results Figure 5.49 shows the as-received nozzle #3 boat sample viewed from four different angles rotated along its longitudinal axis. The boat sample contained a mixture of J-groove weld metal and nozzle base metal. Its external surface consists of the original wetted surface by RCS coolant and the EDM cut surface. The approximate interface between the nozzle base metal and J-groove weld is discernable on the wetted surface and the EDM cut surface (Fig. 5.49). One large void and one axial crack (axial flaw #4) on the EDM cut surface were immediately noticeable. A small void to the upper left of the large void was also seen on the EDM cut surface.

Fig. 5.49 As-received nozzle #3 boat sample viewed from four different angles rotated along the long axis. Top left: original surface wetted by RCS coolant: the dotted line indicates nozzleto-weld interface. Top right: side view of EDM cut surface: mostly nozzle base metal in this view; the large void was at the nozzle-to-weld interface; the white arrows indicate axial flaw #4. Bottom left: bottom view of EDM cut surface: nozzle-to-weld interface was visible. Bottom right: side view of EDM cut surface: mostly J-groove weld metal in this view

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Fig. 5.50 No surface breaking crack was found in the helium bubble exit area, except a grinding lap from original manufacturing.

The wetted surface was carefully examined by stereo microscopy and by scanning electron microscopy. However, no surface breaking cracks were found by stereo visual or SEM surface examination or by subsequent destructive examination to account for the observed helium bubbles. The area corresponding to the presumed helium exit point contained only a grinding lap (Fig. 5.50). Subsequent progressive grinding confirmed that there were no surface breaking cracks in this area. Voids and cracks on the EDM cut surface were examined by SEM and stereomicroscopy. The large void appeared to be a lack-of-fusion weld defect located at the weld-to-nozzle interface, which was confirmed during the subsequent destructive examinations. Cracks were visible on the weld metal surface inside the large void (Fig. 5.51). It should be noted that the axial crack (axial flaw #4) on the EDM surface was in the Alloy 600 nozzle base metal. Additional fine cracks emanating from the large void became apparent on the EDM surface after lightly sanding off the recast layer using 600 grit SiC paper. One branch crack extended from the large void toward axial flaw #4 (Fig. 5.52).

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Fig. 5.51 Cracks were visible on the weld metal surface inside the large void

A high-resolution replica was made of the large void with Microset® replication material. From the replica, the depth of the large void was estimated to be approximately 1.6 cm (5/8``), indicating the axial flaw #4 intersected the large void which curved behind the axial crack in Fig. 5.52. Subsequent metallography confirmed the void was intersected by the axial flaw #4. Hence, all axial cracks (axial flaws in Fig. 5.46) were likely either connected directly or indirectly through the large void or other voids not captured in the boat sample. Based on the visual examination and NDE, the boat sample was initially sectioned into four pieces by making the three parallel cuts shown in Fig. 5.53. Cuts #1 and #3 were trim cuts. Piece B targeted the two voids. Piece C targeted the axial flaw #4, one end of the large void, and the upper tip that contained the presumed helium bubble exit point. All cuts were performed dry using a slow speed cut-off saw outfitted with a thin abrasive blade with a kerf of approximately 0.76 mm (0.030''). Piece A Cut #1 was within the Alloy 82/182 J-groove weld. Examination of the two cut #1 faces on piece A and piece B showed no cracking or voids; hence no further examinations were performed on piece A.

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Fig. 5.52 Several fine cracks emanated from the large void in addition to the large axial crack (axial flaw #4) on the EDM cut surface. The axial crack intersected the large void which curved behind the axial flaw

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Fig. 5.53 Initial boat sample sectioning into pieces A, B, C, and D. The recast layer on the EDM cut surface was removed by 600 grit SiC abrasive paper

Piece B The piece B, cut #2 face was mounted and examined in the polished and etched condition (Fig. 5.54). Electrolytic etch with 10% oxalic acid at 6 V for *10 s revealed individual weld beads. The large void had a triangular cross-section and was located at the nozzle-to-weld interface. The large void corresponded to a single weld bead and was consistent with a lack-of-fusion weld defect. One crack emanated from the void top side and was contained within a single weld bead. This crack extended toward the J-groove weld wetted surface for *0.76 mm (*0.030``), but was still below the wetted surface. Cracking was not intergranular. The crack location and orientation suggest it to be a solidification crack. Another crack emanated from the void bottom corner, which was highly branched and intergranular. Once the crack crossed into the nozzle base metal, it

Fig. 5.54 Piece B cut #2 face: the large void corresponded to a single weld bead; cracks emanated from the large void top surface and bottom corner

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Fig. 5.55 Left: piece B cut into pieces B1 and B2. Mid top: piece B2 as-cut surface. Mid bottom: surface ground until *0.005.inch below the void bottom corner. The red-dashed line indicates that nozzle to-weld interface. Right: extensive intergranular cracks below the void bottom corner

became less branched but clearly intergranular. To the lower left of this crack, another fine intergranular crack was found in the nozzle base metal. To further characterize the extent of cracks emanating from the large void, piece B was cut by wire EDM into pieces B1 and B2 (Fig. 5.55). Examination of piece B2 at low magnification indicated cracking along the entire length of the void bottom corner. Piece B2 was mounted and ground progressively into the paper (Fig. 5.55) until *125 lm (*0.005'') below the void bottom. The polished surface then showed extensive intergranular cracking predominantly in the axial orientation. Once within the nozzle base metal, cracks reoriented in the radial-axial orientation. Piece B1 was cut *3.2 mm (*1/8``) from cut #2, resulting in pieces B1A and B1B (Fig. 5.56). The crack extending toward the wetted surface in piece B1A

Fig. 5.56 Left: sectioning piece B1 into pieces B1A and B1B. Mid: pre-existing crack in piece B1A opened up for SEM fractography. Right: egg crate morphology of the pre-existing crack surface

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Fig. 5.57 Left: sectioning piece C into pieces C1, C2, and C3. Mid: pre-existing crack in piece C1 opened up, piece C1A for SEM fractography and piece C1B for progressive grinding. Right: progressive grinding direction of piece C1B, which showed no evidence of crack connected to the wetted surface

(Fig. 5.54) was opened up for SEM fractography. The egg crate morphology of the crack surface and evidence of a liquid film (Fig. 5.56) were consistent with solidification cracking or hot cracking from weld shrinkage stress. Piece C Piece C was transversely cut above and below the void, resulting in pieces C1, C2, and C3 (Fig. 5.57). The upper portion of axial flaw #4 in piece C1 was opened, resulting in piece C1A for open crack SEM fractography and piece C1B for mounted specimen. The dark appearance of the in-service crack surface contrasted the bright fresh laboratory fracture surface. Fractography of piece C1A and progressive grinding of piece C1B showed no evidence that the crack was connected to the wetted surface. Piece C2 was cut resulting in pieces C2A and C2B (Fig. 5.58). The axial flaw #4 in piece C2B was opened up for fractography, resulting in pieces C2B1 and C2B2. The void was intersected by the axial flaw #4 and extended *1.6 mm (*1/16'') into piece C2B2. The axial crack was clearly intergranular. The polished surface of piece C3 was below the weld void (Fig. 5.57), with similar orientation as piece B2. Figure 5.59 shows the axial flaw #4 in the nozzle base metal below the void. Cracking was intergranular and in the radial-axial orientation within the nozzle base metal similar to piece B2 in Fig. 5.55. Piece D Piece D was transversely cut as shown in Fig. 5.60, resulting in pieces D1 and D2. The cut elevation was selected to maximize the nozzle base metal in the mounted specimen of piece D2. No evidence of cracking was found in the specimen cross section. However, small lack-of-fusion voids at the nozzle-to weld interface were

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Fig. 5.58 Left top: sectioning piece C2 into pieces C2A and C2B. Left bottom: open up of pre-existing crack (axial flaw #4) in piece C2B for SEM fractography. Right: intergranular cracking in the nozzle base metal

Fig. 5.59 Axial flaw #4 in Piece C3 below the large void bottom corner

noted (Fig. 5.60). The polished surface was dual etched to reveal carbide distribution. The surface was first etched in concentrated phosphoric acid to reveal the carbides, and then etched in 5% nital to reveal the grain boundaries. Electrolytic etching (3 V for 15 s) was used in both steps. Figure 5.61 shows that the Alloy 600 nozzle base metal had extensive intragranular carbides and a grain size of ASTM 6– 7. Near the nozzle-to-weld interface, the base metal was almost completely devoid of intergranular carbide coverage.

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Fig. 5.60 Left: sectioning piece D into pieces D1 and D2. Mid and right: polished surface of piece D2 showing lack-of-fusion voids

Fig. 5.61 Dual etched microstructure in piece D2. Left: nozzle base metal, right: nozzle-to-weld interface area

No cold work was observed in the nozzle base metal. A Vickers microhardness traverse (500-g load) was performed on the D2 specimen across the nozzle-to-weld interface. There was little hardness variation from the weld metal to the base metal. The hardness averaged *220 HV, which was typical of solution annealed Alloy 600. Conclusion Although the helium exit location was not captured by the boat sample, based on the boat sample laboratory analysis and on-site NDE results, the BMI nozzle #3 leak was most likely triggered by the lack-of-fusion void(s) at the nozzle-to-weld interface. At some point, the void became exposed to the RCS coolant. Although the surface breaking mechanism could not be conclusively established by the laboratory analysis of the boat sample, it is plausible that the void broke the

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J-groove weld surface by fatigue from plant pressurization and depressurization, and heat-up and cool-down cycles, and probably propagated from an existing solidification crack on the void surface. Subsequently, PWSCC initiated from the bottom corner of the void and propagated toward the nozzle base metal in the radial axial orientation. Leakage occurred after one of the axial cracks extended below the J-groove weld root, completing the leak path from the wetted J-groove surface to the BMI nozzleto-vessel annulus.

5.2.7

Laboratory Analysis of a Bottom Mounted Instrumentation Nozzle at an Areva Plant (Derniaux 2018)

Plant main characteristics: Areva PWR, 900 MWe, 3 loops, France. Equipment/Component: RPV bottom head, BMI made of A600. Operating conditions: primary water, 290 °C (554°F). Time of operation: 31 calendar years at the time of the NDE indications discovery (2001). Failure discovery: the BMIs of this unit were first inspected by NDE in 2001. Two longitudinal flaws (A1 and B) attributed to heterogeneities lines inherited from manufacturing were detected in nozzle #4. They are located respectively at less than 2 mm from the inner wall and at 5 mm (0.2″) from the inner wall. The BMI nozzles were inspected again by UT in 2011. Two indications (A2 and A3) were detected in nozzle#4 in addition of A1 and B manufacture flaws. A2 indication was considered as a longitudinal crack attributed to PWSCC, with the deepest point at 10 mm (0.4″) from the inner wall from conservative assessment. The analysis of A3 signal was complex because of the presence of B and A2. A3 indication was thus classified as a longitudinal crack by conservatism. For both A2 and A3 indications, the diffraction signal ends clearly before reaching the outer diameter, in accordance with acoustic testing and VT from the pit (no leak path during operation and hydrotests). The four indications detected and characterized by NDE in the nozzle #4 are illustrated in Fig. 5.62. In 2011 again, high definition VT were performed on the inner wall of BMI nozzle #4. A linear indication was discontinuously observed from 0 mm (top of the nozzle) to 344 mm (13.5″) at the same angular position as the A1 UT indication (Fig. 5.63). Starting from elevation 323 mm (12.7″), around A2 elevation, the indication looks like a crack (Fig. 5.64). Moreover, at some elevations some flaws looking like cavities are seen along the linear indication.

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Angles

Fig. 5.62 Conservative contours of the BMI nozzle #4 indications, from 2011 NDE

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Fig. 5.63 2011 VT examination of the BMI showing an ID surface breaking indication

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Fig. 5.64 View of the length of the 2011 VT ID indication looking like a crack

Cavity like indication

Indication length looking like a crack

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During the next scheduled outages, follow-up NDE were performed after unplugging BMI nozzle #4: UT TOFD in 2013, 2014 and 2015 and VT in 2013 and 2014. No evolution of the indications was detected by NDE, confirming the efficiency of the temporary plugging to stop crack propagation. Similar event frequency: low occurrence, 6 events: three BMIs’ leaks at two plants, one BMI with PWSCC and two BMIs with NDE indications of PWSCC at two different plants worldwide as of 2019. Specimen/sample characteristics: this unit BMIs tubes are made of alloy 600 and manufactured from forged bars, hot rolled to a diameter of 51 mm (final temperature around 1050 °C/1922°F). A strain softening heat treatment at 800 °C (1472° F) for 1 h was performed on the heat after hot rolling, followed by air cooling. After insertion at nitrogen temperature, the nozzles are welded to RPV cap by manual shielded metal arc welding with Alloy 182. The BMI nozzle finally benefited from the final RPV heat treatment performed at 610 °C for 8 h. BMI #4 is a central nozzle, with a set-up angle of 12°. According to end of manufacturing reports, this nozzle #4 was not cold-straightened after heat treatment (after installation of the RPV). The tube inner surface finish is drilled. The external surface of the tube is finish-turned above the collar and grinded under the collar and also on the weld area to get a surface roughness compliant for PT inspection. DE goal and program: characterization of the NDE indications. Results Visual examinations of BMI nozzle upon receipt The BMI nozzle #4 was received at EDF hot laboratory in two pieces (Fig. 5.65). Several materials composed the pieces received: the nozzle in Alloy 600, a small

Fig. 5.65 View of the two BMI nozzle #4 parts received at EDF hot laboratory. Top of the BMI nozzle (left) and bottom of the BMI nozzle (right)

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275

Fig. 5.66 View of flaws evidenced in the weld. View from the 0° position

part of the J-groove weld in Alloy 182, a small part of the RPV in bainitic steel and the socket welding of the stainless-steel guide tube of core instrumentation to the BMI nozzle. The top of the nozzle shows a blackish coloration at the outer surface due to Alloy 600 oxidation in primary water. Some scratches induced by the tools used for repair are visible. The visual examination of the EDM cut surface of the weld reveals the presence of volume defects (Fig. 5.66). The size of these weld defects ranges from 1 to 5 mm (0.04 to 0.2 ′′). BMI nozzle material characterization The microstructure is similar at several elevations along transverse and longitudinal directions. The equiaxial grain size is quite homogenous in the wall thickness and

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Fig. 5.67 LOM micrographs in transverse direction. At mid-wall (left) and at ID (right)

the average grain size is estimated at ASTM #6. The chromium carbide distribution is predominantly intergranular, with some intragranular carbides (Fig. 5.67). A study of the grain boundaries carbide distribution was conducted with SEM. The grain boundary coverage with chromium carbides is estimated to nearly 20%. A cold-worked layer composed of very small grains is present at the inner wall. The thickness of the cold-worked layer is approximately 50 lm (2 mils). A part of this layer is composed of very small grains with a diameter in the range of 1 lm (0.04 mil) to 10 lm (0.4 mil). The cold-worked layer is due to the deep-drilling process during the nozzle fabrication. The presence of very small grains is probably due to the final RPV heat treatment that conducted to a grain recrystallization in a part of the cold-worked layer. The chemical composition of the BMI nozzle complies with the specifications and is in good agreement with the MTR. Vickers hardness tests were carried out on cross sections under 500 and 100 g. A cartography under 500 g load was made across the nozzle wall thickness, with 500 lm (20 mils) indent spacing (Fig. 5.68, left). Vickers hardness is heterogeneous in function of azimuthal position (difference of 15 to 20 HV0.5). However, symmetry axes seem visible in the cartography. Vickers hardness is homogenous in the thickness for given azimuthal positions. For other azimuths, hardness increases from 210HV0.5 near the inner diameter to 230HV0.5 close to the outer diameter. These mechanical properties heterogeneity is observed over the whole length of the nozzle. It is probably inherited from the manufacturing process and in particular from hot rolling steps. Three microhardness line scans were performed on cross sections under 100 g load to identify the mechanical properties evolution close to inner diameter surface. The hardness indent spacing was 100 lm (4 mils). The mean curve is presented in Fig. 5.68 (right). The hardness is the highest in the cold-worked layer. No cold-worked layer was revealed with this technique at the outer diameter surface.

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90ºPFC

180ºPFC

0ºPFC

270ºPFC

Fig. 5.68 Vickers hardness tests. Cartography across the nozzle wall thickness under 500 g load (left) and cross section line scan under 100 g load (right)

NDE indications characterization Characterization of the indication observed with high definition televisual inspections. Visual examinations confirm the presence of a defect at the inner surface of the BMI nozzle (Fig. 5.69). Transverse scratches are also noticed. They stem from the deep-drilling process during the BMI nozzle fabrication.

Fig. 5.69 Views of the inner diameter surface

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Fig. 5.70 SEM photographs of the defect at various elevations

SEM investigations show clearly that the defect is a crack from 309 to 328 mm (12.2 to 12.9″) elevations (Fig. 5.70). A1 indication A1 indication was characterized at various elevations of the BMI nozzle (Fig. 5.71). This indication corresponds to a band of oxide inclusions with a longitudinal orientation. This manufacturing defect is present in the whole length of the nozzle and located between the inner surface and a depth lower than 3 mm (0.12″). From 0 to 131 mm (5.2″), the inclusions band breaks the inner surface of the nozzle. From 143 mm (5.6″) to the bottom of the nozzle, the band is embedded below the surface. The inclusions are composed of magnesium, aluminium, oxygen, titanium and nitride. The size of each inclusion is smaller than 5 lm (0.2 mil) (Fig. 5.72). Along the weld, the band is open due to welding stresses. A good correlation is observed between destructive examinations and UT results (nature and localisation of A1).

a)

c)

b)

d)

ID ID

ID

ID

Fig. 5.71 LOM view of A1 indication at various elevations: 16.5 mm (0.65″) (a), 143 mm (5.6″) (b), 296.8 mm (11.7″) (c) and 331.9 mm (13.1″) (d)

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Fig. 5.72 SEM views of A1 indication at elevation 269.5 mm (10.6″)

Fig. 5.73 LOM view of B indication at elevation 296.8 mm (11.7″)

B indication This indication also corresponds to a band of oxide inclusions with a longitudinal orientation. This defect is present at mid-thickness of the nozzle from 190 mm (7.48″) to the bottom of the component. The inclusion chemical composition is the same as for A1 indication. As for A1, the band is also open along the weld, due to welding stresses (Fig. 5.73). Destructive examinations are in good agreement with UT results for this indication (nature, sizing and localisation). A3 indication No defects or singularities were observed at A3 location by destructive examinations. A3 indication is thus an UT false call, as suspected by NDE experts from 2013. However, due to the difficulties of A3 UT signal interpretation (complicated by the presence of A1 and B), UT experts decided to classify A3 as a crack by conservatism during non-destructive examinations.

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Nickel Base Alloys

Fig. 5.74 LOM view of A2 indication at elevation 318.8 mm (12.55″)

A2 indication A cross section was performed at elevation 318.8 mm (12.55″) as considered to be the altitude where A2 indication is the deepest according to UT results (Fig. 5.74). LOM reveals the presence of A1 and B indications. An intergranular crack is observed between the nozzle inner surface and the closest extremity of A1 inclusion band, as well as between the other extremity of the band and a depth of 9.7 mm (0.38″) from the inner surface. Other micrographic examinations confirm that the crack is not though wall, the maximum depth of the branched crack being 9.7 mm (0.38″). The crack profile was drawn from cross sections and compared to the envelope profile identified by UT (Fig. 5.75). A2 indication can be separated into two cracks: (1) a first crack observed between the nozzle inner surface and the closest extremity of A1 indication, with a “semi-elliptical” shape indicating a propagation from the inclusions band toward the inner diameter surface, (2) a second crack located between the other extremity of the band and a depth of 9.7 mm (0.38″) from the inner surface, also with “semi-elliptical” shape indicating a propagation from the inclusions band toward the outer diameter surface. The two axial cracks seem to be initiated from the inclusions band. As a matter of fact, on some cross sections, a crack is propagated from the oxide band toward the inner surface diameter without breaking the surface (Fig. 5.76). Optical micrographs show a strong relation between the A1 band of oxide inclusions and the crack. This observation is confirmed by the fracture surface study of a 2 mm (0.08″) longitudinal section of the crack, opened in laboratory (Figs. 5.77 and 5.78).

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281

Fig. 5.75 Comparison between the A2 profile drawn from the destructive examinations and the A2 envelope profile determined from UT

Fig. 5.76 LOM views of the crack between the nozzle inner surface and the closest extremity of the A1 inclusions band: 309 mm (12.2″) (left) and 329.7 mm (13″) (right)

Fracture surfaces observed along the cracks and the inclusions band are not similar. An intergranular fracture pattern is observed on the cracks. The fracture surface of the inclusions band reveals the presence of an oxide layer with a high density of inclusions smaller than 5 lm (0.2 mil). No ductile shearing is observed at the interface between the inclusions band and the cracks.

282

5

Nickel Base Alloys

Fig. 5.77 Fracture surface of a small part of the crack after opening (numerical optical microscope)

Fig. 5.78 Fracture surface of a small part of the crack after opening (SEM)

Destructive examinations show that the morphology of this indication is typical of PWSCC. A182 weld characterization Cross sections of the A182 weld reveal the presence of several weld defects such as lacks of fusion.

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283

Fig. 5.79 LOM views of welds defects at the base metal/weld metal interface. Cross sections at elevations: a 277,8 mm (10.94″); b 281,3 mm (11.07″); c and e 296,8 mm (11.69″) and d 300,8 mm (11.84″)

They are located at the base metal—weld metal interface, and distributed all around the BMI circumference (Fig. 5.79).

284

5

Nickel Base Alloys

Fig. 5.80 LOM view of a weld cross section at elevation 277.8 mm (10.94″). Oxalic acid etching

They are small with a maximum size of 5 to 6 mm (0.2 to 0.24″) along the interface. The weld has a dendritic structure from solidification (Fig. 5.80). The grain size is heterogeneous. EBSD examination shows long or columnar grains which pop up at the weld wetted surface (Fig. 5.81). The very surface does not exhibit any recrystallized layer. The hardness line scans of Fig. 5.82 show the presence of a cold work layer at the weld surface stemming from the fabrication grinding. For these line scans, the hardness load is 25 g and the prints pitch is 45 µm. The first print is 38 µm (1.5 mils) distant from the wetted surface. The thickness of the cold work layer ranges from 100 µm (4 mils) to 200 µm (8 mils).

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285

Fig. 5.81 Weld cross section. EBSD map at elevation 277.8 mm (10.94″)

Fig. 5.82 Weld surface hardness line scans showing the presence of a 100/200 µm (4/8 mils) thick cold work layer stemming from the fabrication grinding. X axis: depth into the weld from the wetted surface (µm). Y axis: HV25g

286

5

Nickel Base Alloys

Discussion Optical micrographs show that IGSCC initiated from the A1 inclusions band. The inclusions bands being subsurface in the cracking area, the primary water has supposedly migrated inside A1, from an elevation where A1 is opened to the inner wall (above 143 mm (5.6″)), to the cracking area. SEM observations performed on A1 inclusions band at various elevations suggest that the primary water migrated inside the manufacturing defect by means of bridges between inclusions and broken inclusions (Fig. 5.83). Moreover, intergranular oxide penetrations constituting the signature of the first stages of SCC initiation are visible and initiated from A1 inclusions band. Those penetrations seem to demonstrate that the primary water has migrated inside the manufacturing defect. Conclusion The laboratory examinations suggest that the most plausible cracking scenario is the following: • Primary water ingress into the inclusions band in areas where the band is ID surface breaking; • Primary water migration inside the inclusions band through bridges between inclusions and broken inclusions; • SCC initiation close to the J-groove, at the two extremities of the inclusions band that constitute privileged areas for cracking initiation (stress concentration and higher strain); • SCC propagation: • from the inclusions band toward the nozzle outer surface; • from the inclusions band toward the nozzle inner surface.

Fig. 5.83 SEM photographs of the A1 inclusions band at various elevations: 16.5 mm (0.65″) (left and middle) and 190 mm (7.5″) (right) from the top of the nozzle

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5.2.8

287

Synthesis of the Destructive Examinations Carried Out on EDF Reactor Pressure Vessel Head Penetrations

Plants main characteristics: Framatome PWRs, 900&1300 MWe, 3&4 loops, France. Equipment/Component: Reactor Pressure Vessel Head, A600 penetrations (see penetrations location on Fig. 5.84). Operating conditions: primary water, temperature ranging from 290 °C (cold heads) to 300 °C (hot heads) (564 to 572°F). Time of operation: from 37,800 to 170,000 h. Failure discovery: during the 10-year RPV hydro pressure test of one CP0 series unit, on September 23, 1991, a leak was first detected by the acoustic monitoring system, and then visually at the outer diameter of the head, at the 207 bars (3002 PSI) pressure hold. Visual examination of the relevant head area, with the RCS pressurized to 25 bars (363 PSI), confirmed the presence of water and crystalline boric acid at the base of a peripheral penetration (#54). Once the head was removed and the CRDM and the thermal sleeve dismantled, a series of inspections revealed ID cracks at the weld elevation of this penetration. This event triggered a vast campaign of inspections, repairs and eventually heads replacements. Similar event frequency: many RPV head penetrations have cracked in France, USA, Japan, Sweden, Belgium, UK… Fortunately, only a small number leaked in operation. 0°

0°

90°

180°

270°

180°

Fig. 5.84 RPV head. Location of penetrations. Left: 900 MWe, 3 loop reactor. Right: 1,300 MWe, 4 loop reactor

288

5

Nickel Base Alloys

Specimen/sample characteristics: the EDF hot laboratory of Chinon has carried out destructive examinations on samples that originated from 29 RPV head penetrations associated with 8 units (5 three loops and 3 four loops). Five different types of specimens have been removed from the field, depending on the plans for the destructive examination and whether the head was retired or still in service; these various types of specimens are presented later in the DE summary. DE goal and program: over the period 1991 to 2006, an intensive destructive examination program of the leaking unit penetration, and other defective penetrations, has been undertaken to gain insights into the degradation mechanism, to improve the knowledge of the various features encountered in reactor vessel head assemblies and to evaluate the NDE field performance. Results Various types of samples Hour glass sample (Fig. 5.85) This type of sample is obtained using a milling machine equipped with a spherical cutter. The compact size of the machine allows the sampling of the ID and of the OD of the penetration. Such samples have been used for the microstructure characterization and for the assessment of NDE capability and sizing of shallow cracks.

1 cm

Fig. 5.85 RPV head. Hour glass sample. The penetration axis is horizontal. Left picture is the penetration ID; right picture is the cut face. Note the penetration machining marks in the left picture

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289

Typical dimensions of the ‘hour-glass’ sample are: • Length: 20 mm (0.8″); • Width: 30 mm (1.2″); • Thickness: 2 to 3 mm (0.08 to 0.12″). The resultant shallow, smooth profiled, depression in the nozzle penetration can usually be justified for continued operation without the need for rectification or repair. Penetration bottom end For those penetrations with cracks that are confined to the wrought nozzle material, i.e., do not propagate into the attachment weld, only the bottom-end of the penetration needs to be cut. A high-pressure water–jet cutting technique has been successfully applied that provides a very neat cut as shown in Fig. 5.86. Sample removal of this size and at this location enables repair of the nozzle to be undertaken, as required.

Uphill

Water jet cut surface Downhill

1 cm

Fig. 5.86 RPV head. Penetration bottom end sample. In this case, some of the J-groove weld material has also been sampled with the penetration base metal

290

5

Nickel Base Alloys

Compared with the ‘hour-glass’ sample, the bottom-end sample provides significantly more material, and hence additional investigations can be undertaken with such a sample, including the examination of the entire surface of a TW crack, together with mechanical testing. Sample from a partial core drilling of the head When the J-groove weld is sampled, then a hole larger than the penetration OD has to be bored into the head, and the penetration cut above the weld (Fig. 5.87). This technique includes some low alloy steel, thus allowing lower annulus leak path investigations. This sampling method still allows the repair of a vessel head.

Towards the core

Towards the top of the RPV head

Water jet cut under the head

1 cm Weld and buttering Head low alloy steel Machine cut in the head

Uphill

Fig. 5.87 RPV head. Sample removed by a head core drilling technique

Sample including a substantial amount of head material For retired heads, restrictions on sample size imposed by consideration of head repair are no longer of concern. As such, larger samples can be obtained from a retired head using a variety of techniques including core drilling (Fig. 5.88) or by sawing (Fig. 5.89). Benefits of such large samples include the provision of material for mechanical and corrosion testing programs.

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291

Buttering

Thickness of the head

5 cm

Fig. 5.88 RPV. Example of a penetration that includes head material. Zone A = zone under the head. Zone B = head thickness. Zone C = zone above the head

Canopy seal CRDM Dissimilar weld 304L Penetration Dissimilar weld Alloy 600

LAS

Head

10 mm

SS clad A182 butter

Laboratory cut

A182 weld

Thermal sleeve

Head

SS clad

Fig. 5.89 RPV head. A whole penetration together with ferritic steel from the head

292

5

Nickel Base Alloys

Over head sample When the focus of the work to be carried out on the sample is not cracking investigation but only material characterization (including mechanical testing and corrosion tests), there is no need to cut the penetration under or in the head. Access is much easier above the head and contamination less of an issue. Nevertheless, the kind of sample illustrated by the Fig. 5.90 may not be free of activation, especially

Fig. 5.90 RPV head. Penetration section from above the head

Canopy seal

A600/SS dissimilar weld

10 cm

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293

if the penetration is at the periphery of the head. As for an example, the 60Co activity of the leaking penetration #54 after 80,000 h of operation was about 7 Bq/g (2.10–4 µCie/g) a few centimeters (inches) above the head (it is activation, not contamination). Destructive examination main findings Field leak and cracking root cause analysis Historically, the first destructive examinations that have been undertaken at the EDF hot laboratory at Chinon were on specimens of the type illustrated in Figs. 5.86 and 5.87 from the #54 leaking penetration in late 1991. The objectives of the work were to answer two questions, namely: • What was the root cause of the leak? PWSCC was suspected given the identification of significant ovalization by the silastic molds; • Was the hydrotest involved in the leak? One hypothesis was that the leak could result from the crack tip ductile tearing of a non-TW crack under the high stresses stemming from the high pressure hydrotest. The answers to these questions are contained in Fig. 5.91 which represents the TW crack that was at the origin of the leak. The main characteristics of this crack are: • It’s a PWSCC crack (intergranular, Alloy 600 susceptible material, primary water, residual stresses, temperature…); • The crack is planar in the longitudinal and radial planes; • The crack is located towards the 30° angle on the penetration circumference; • Crack initiation is at the top of the counterbore. Around the initiation site, the surface may look different but it is just a color difference coming from a variation of the surface deposits and oxidation; • The maximum crack length is 51.5 mm (2.03″); • The crack is surface breaking on the entire lower half but surface breaking only on 1.7 mm (0.07″) on the upper half above the counterbore; in other words, the crack propagates 24.3 mm (0.96″) under the surface. Severe ID cold work inducing surface compressive stresses can explain such behavior; • The OD surface emergent crack was 2 mm (0.08″) long; • Crack propagation extended 2.7 mm (0.11″) into the weld metal, along a 15 mm (0.59″) crack front. This weld crack becomes surface emergent at the annulus, thus providing a second leak site, this time in the weld metal, effectively increasing the 2 mm (0.08″) leak path; • The main crack path crosses a shallow circumferential crack in the base metal that had initiated at the weld root; • There is no ductile tearing; the hydrotest did not produce any ductile tearing; • Based on the OD circumferential crack depth, the assumption has been made that this crack initiated and propagated TW in about 60,000 h, with a CGR of 3.5 µm/h (0.14 mil/h).

294

5

Nickel Base Alloys

Top of the crack

Ferritic steel (removed) None ID surface breaking area of the crack

TW spot

Bottom of the annulus

Initiation, top of the counter bore

Crack propagation in the weld

Bottom of the crack 1 cm

Fig. 5.91 RPV head. TW fracture surface of the PWSCC crack at the origin of the leak of the penetration #54. Penetration ID on the left

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295

Another failure analysis has been undertaken on the penetration #63 of the unit which experienced the leak. In service inspection identified that this penetration contained longitudinal cracks in the ID. These cracks were dressed-out by grinding and the resultant depression partially refilled with Alloy 82 material before the unit went back on-line for one more cycle (Fig. 5.92). A silastic mold taken of the penetration ID after the repair shows the resultant profile of the various surfaces (Fig. 5.93). Grinding did not remove the deepest crack tips, which remained embedded below the Alloy 82 welded material. After one cycle, a new PT evidenced a new OD longitudinal crack in the 350°–0° region, just in front of the repair (Fig. 5.94). Thus, a destructive examination was performed in order to:

Welded and machined alloy 82 patch

Top of the counterbore

Cross section

As left ground area

1 cm

Fig. 5.92 RPV head. View of the ID of the penetration #63 after grinding and weld repair. Cut at 90° and 270° angles

296

5

Nickel Base Alloys

Weld repair A82 patch

Top of the counterbore

As left ground area

1 cm

Fig. 5.93 RPV head. Silastic mold of the ID of the penetration #63 after repair

• Confirm the absence of flaw in the Alloy 82 weld; • Search for any connection between the embedded and the OD cracks; • Characterize the OD crack (Fig. 5.94). The ID PT of the Alloy 82 welded material after one cycle of operation did not reveal any defect indications. A cross section from the penetration (see location of the cut on Fig. 5.92) showed that there was no connection between the old embedded flaw and the new PWSCC OD crack. This means that the 8 mm (0.3″) long OD crack initiated and propagated 2.85 mm (0.11″) deep within one cycle (no crack was present at the OD the cycle before). So, we can conclude that after the alloy 82 patch repair, the weld residual stresses at the OD of the penetration were high enough to initiate PWSCC in less than one fuel cycle.

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Fig. 5.94 RPV head. Location of the OD longitudinal crack (pointed at by white arrows) discovered at the opposite of the ID alloy 82 patch shown on Fig. 5.92

Crack

Downhill

Uphill

Surface characterization Sometimes, the PT shows spots of penetrant which are due to craze cracking, as can be seen on the Fig. 5.95. In case of craze cracking, PT may not be able to separate the individual cracks. To better see this craze cracking, one usual technique is to flatten the sample. However, this is not always easy because the penetrations are thick and made of very tough material. Thus, the penetration wall may need to be thinned before flattening. As the RPV head penetrations have been machined and ground, surface cold work is commonly found on these components. The Fig. 5.96 shows a typical cold work layer close to the weld; this cold work is related to the weld dressing operations. The hardness can be as high as 270 HV2 just beneath the surface. The thickness of some cold work layers has been measured and are reported in the Table 5.3. Another major parameter regarding PWSCC initiation probability is the level of the surface residual stresses. OD residual stresses have been measured using X-rays on 3 penetrations; the results are summarized in the Table 5.4. The Table 5.4 shows that the surface residual stresses are compressive. The EDF head penetrations (base metal) have suffered from a very few OD initiated cracks under the head.

298

5

Nickel Base Alloys

Fig. 5.95 RPV head. View of ID craze cracking after flattening of the sample

20 µm

Fig. 5.96 RPV head. OD surface cold work close to the weld

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Table 5.3 RPV head. Cold work depth measurements Unit

Penetration #

Location—Cold work thickness

B4

65 45 64 65 26

Base metal ID—22 µm/0.9 mil Base metal OD—70 µm/2.8 mils Base metal ID—40 µm/1.6 mils Base metal ID—60 µm/2.4 mils Base metal OD—150 µm/6 mils Weld—200 µm/8 mils Base metal OD—50 µm/2 mils Weld—100 µm/4 mils

B1 F1

55

Table 5.4 RPV head. OD residual stresses measurements using X-rays Unit

Penetration #

Location

Value (MPa)

B3 F1

63 26

F1

55

Base metal OD Base metal OD at azimuth 0°, 90° and 180° Base metal OD at azimuth 180°, at 125 µm (5 mils) deep Base metal OD at azimuth 0°, 90° and 180° Base metal OD at azimuth 0°, at 700 µm (28 mils) deep

Compression: −300 to −600 Compression: −20 to −710 Tensile stresses: axial stresses = 270 and hoop stresses = 345 Compression: −20 to −900 Tensile stresses: axial stresses = 100 and hoop stresses = 260

Head wastage In 1991, when the RPV head leak occurred, little was known about the impact of the media generated by a primary water leak in the annulus, on head wastage. At that time, there was a lack of knowledge of the composition of the media generated by a leak in the annulus. To evaluate wastage of ferritic steels in this penetration annulus geometry and material combination, samples have been obtained that include the ferritic steel annulus (see Fig. 5.97). Figure 5.97 presents the leaking penetration #54 at the location of the surface emergent TW crack at the OD surface. The alloy 600 surface is coated with black oxides and deposits. In order to view the effect of the annulus leak on the ferritic steel side of the annulus, the carbon steel of the sample type shown in Fig. 5.87 has been “peeled” (like a “banana”) using a combination of 6 longitudinal cuts, some transverse cuts and also a cut around the ferritic steel- J-groove weld interface.

300

5

Nickel Base Alloys Top

Vertical axis of the penetration

Annulus bottom

Fig. 5.97 RPV head. Leaking penetration. OD view of the penetration #54 in the area of the TW PWSCC crack. The two white arrows point at the crack

A montage of the ferritic steel annulus surface, thus obtained is presented in Fig. 5.98. The ferritic steel leak path is highlighted by white arrows. The leak path starts at specimen 2, which corresponds to the surface emergent leak point on the penetration side of the annulus. The leak path then moves upward into specimen 9, then specimen 6, followed by 7 and back to 6, Finally, the path crosses the specimen 4 moving towards the top of the head. It was established from the various cross sections that the maximum depth of wastage depth associated with the leak path was 60 µm (2.4 mils) deep. The ferritic surface was coated with a duplex corrosion product layer up to 65 µm (2.56 mils) thick. As the EDF maintenance policy was targeted to prevent any occurrence of TW cracks, penetration #54 of Fig. 5.98 is the only one to have leaked.

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301

60 µm (2.4 mils) deep wastage

Fig. 5.98 RPV head. Leaking, penetration #54. View of the leak path on the ferritic steel in the annulus. These specimens have been obtained by cutting the head low alloy steel which can be seen Fig. 5.87. Bottom left image: cross section of the leak path showing a 60 µm (2.4 mils) deep wastage of the ferritic head steel

302

5

Nickel Base Alloys

ID circumferential cracking The only circumferential cracking was found in the step between the top of the counter bore and the nominal ID. It was a rather shallow crack (300 µm, 12 mils deep), 1 mm (0.04″) long, and obviously linked to the counter bore machining (Fig. 5.99).

Nominal ID surface of the penetration

Counter bore Bottom of the nozzle

50 µm

Top of the nozzle

OD surface of the penetration

Fig. 5.99 RPV head. Leaking penetration #54. ID circumferential PWSCC crack located in the step between the top of the counter bore and the nominal ID

OD circumferential cracking. Annulus region As penetration #54 of Fig. 5.91 is the only penetration to have leaked in French PWRs, OD circumferential cracking in the annulus is limited to this penetration. Circumferential cracking was found in the base metal and in the weld root, at the bottom of the annulus in each case; this means the TW crack leaked the time necessary to initiate the OD cracking observed. In the base metal, the circumferential crack was located in the vicinity of the uphill position. The crack was inclined approximately 45° to the base metal surface;

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

303 Top

Penetration vertical axis

Buttering

Annulus

Penetration base metal 1 mm

Fig. 5.100 RPV head Leaking penetration #54, OD circumferential cracking in the weld

2.3 mm (0.091″) (in the crack direction) and 1.75 mm (0.069″) (perpendicular to the surface) deep. Circumferential cracking was manifest in the weld root, that extended around a 110° arc and penetrated up to 3.5 mm (0.138″) (in the crack direction). Hot cracking might have contributed to the extent of cracking (Fig. 5.100). Given that when assembled, the penetration is shrunk into the head to provide an interference fit, the crack mouth at the weld root was surprisingly wide (100 µm (4 mils) on Fig. 5.100). It can also be seen from Fig. 5.100 that the shape and the aspect of the weld root suggests that at least at some time in the past, the annulus gap was closed. It is possible that some relaxation of the specimen has occurred during cutting. However, Fig. 5.105 (when observed at a higher magnification) shows that this gap still exists in much stiffer specimens. Under the head In accordance with EDF maintenance policy (up to the period 1996/1997) all the replaced heads welds were PT inspected in order to validate the operational assessment (which judged the heads to be acceptable). The PT zone covered the weld plus one inch on each side. This PT was to find any indication, which is different from fabrication PT which aims at accepting or rejecting a part or component. In several instances, linear circumferential PT indications were observed. Some of the concerned penetrations were removed and supplied to the hot laboratory for characterization of the PT indications. The PT linear indications were always located close to the weld—base metal interface as shown on Fig. 5.101. Investigation of the PT indications established

304

5

Nickel Base Alloys

500 µm Fig. 5.101 RPV head. Surface defect having generated a circumferential PT indication at the weld —penetration OD interface

that the PT-call was due to a surface artifact, generally induced by grinding, as a metal lap, for example, but not associated with PWSCC. Hot cracking Although a study of hot cracking was not one of the prime objectives of the destructive examinations that have been performed on the RPV head penetrations specimens at the Chinon laboratory, hot cracking has often been observed in Jgroove and ‘buttering’ microsections. Figure 5.102 shows micrographs of interdendritic propagation perpendicular to the weld surface in a penetration having been in service for 170,000 h. This defect is not SCC but from hot cracking. On this same penetration, a A182 weld patch has been observed in the SS clad (Fig. 5.103). This area has been detected from the multidirectional PT indications it exhibited.

100 µm

Fig. 5.102 RPV head. Hot cracking observed in A182

50 µm

5.2 Destructive Examinations Related to Reactor Pressure Vessel … RPV head

305

200 µm

5 mm

Stainless Steel cladding

A182 weld overlay

200 µm

50 µm

Fig. 5.103 RPV head. A182 weld overlay penetrating into SS clad and generating hot cracking

Fig. 5.104 RPV head. Area of Fig. 5.103. Typical image of hot cracking. Note the niobium enriched “flower” on the right image

This weld overlay is 2 mm deep. Its composition is a mix of A182 and underlying SS: 19 Wt% Cr, 30/33 Wt% Ni, 45 Wt% Fe, 1 Wt% Nb and 5 Wt% Mn. The PT indications are hot cracks. One of these cracks has been broken open for SEM examination. The crack face exhibits features typical of hot cracking such as molten aspect and niobium rich “flowers” (Fig. 5.104).

306

5

Nickel Base Alloys

Other weld defects The weld root triple-point (penetration—buttering—weld root), especially at the uphill position, is a difficult region to weld due to geometric and access restrictions. As such, it is not unusual for these locations to contain weld defects welds defects there is not surprising or unusual. Figure 5.105 shows an example of a typical defect. A cavity from a lack of penetration can be seen. For the same reason, destructive examination was performed on the penetration shown in Fig. 5.106 right. This penetration also gave a circumferential PT indication at the interface between the base metal and the weld. Once again, the PT indication was not related to PWSCC but further a manifestation of a weld induced defect. At the bottom of this defect, was shallow, oxide filled, penetrations (Fig. 5.107 left). Note the large pore in one of the capping runs.

10% electrolytic oxalic acid etching

RPV head penetration top

1 mm Weld + buttering

RPH penetration OD

Penetration base metal

Fig. 5.105 RPV head. Leaking penetration #54, cavity at the triple point at angle 0°. Oxalic acid etch

Weld 1 mm Lack of bond

Weld

20 µm

Base metal

Circumferential PT indication

Base metal

Fig. 5.106 Left: RPV head. Lack of bond at the interface between the penetration base metal and the weld run-out. Right: RPV head. The white arrow identifies the location of a circumferential PT indication (at the interface between the penetration and the weld run-out under the head)

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307

Weld Lack of bonding filled with oxides Circ. PT indication

20 µm

Base metal

200 µm

Fig. 5.107 Left: RPV head. Oxide filled weld defects in the area of the PT indication of Fig. 5.106 right. Right: RPV head. A step in a weld that generated a circ. PT indication

A final example of a weld defect induced circumferential PT indication is presented in Fig. 5.107 right. The most frequently encountered welds defects were weld-metal cavities. Figure 5.106 right and Fig. 5.108 left to Fig. 5.109 present examples of such cavities. Figure 5.110 left presents an inclusion or a void located in the center of a weld bead. Note that this weld defect has a very flat profile, which is different from a PWSCC crack. Figure 5.110 right presents another example of a PT circumferential indication promoted by a weld defect. The PT indication was generated by a lack of bonding between two weld passes, close to the weld—base metal interface. Coincidently, the step stemming from the weld defect, contained a particle of dimensions 200
80 µm (8
3 mils). Microprobe analysis revealed that this particle was composed of pure chromium.

40 µm 100 µm

Fig. 5.108 Left: RPV head. Weld metal cavity adjacent to the penetration base metal. Right: RPV head. Typical cavity in the weld material

308

5

Nickel Base Alloys

Base metal

Cavity

Weld pass A

Weld pass B

1 mm

Fig. 5.109 RPV head. Inter-run cavity between two weld passes

200 µm 100 µm

Fig. 5.110 Left: RPV head. Flat inclusion or void in the center of a weld bead. Right: RPV head. Lack of bonding having generated a PT indication, and pure chromium particle entrained in the weld at the OD of a penetration under the head

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309

Partially surface breaking cracks The crack presented in Fig. 5.91 was through wall over approximately half of its length. It is believed that this behavior was associated with the presence of a compressive surface layer, probably from machining, preventing the defect from propagating to the ID surface above the counter bore. Figure 5.111 illustrates another configuration of a crack running below the surface. In this example, the compressive stresses were weld-induced. The defect is a longitudinal PWSCC crack that initiated in the penetration OD base metal and propagated approximately 2 mm (*1/10″ inch) under the weld but without reaching the weld—parent metal interface.

The micrograph shows what the crack looks like on a cross section at elevation 3 mm

C

3,5

Weld

Weld C

A PWSCC

Elevation (mm)

3 2,5

B

Base metal Left photo view

2

Crack surface

1,5 1

Top OD Penetration ID

0,5

B

A

0 0

1 2 3 Penetration thickness (m m )

4

250 µm

Fig. 5.111 RPV head. Profile of a PWSCC crack (a, b) in the penetration base metal propagating towards, but not reaching the J-groove weld interface (c). The top of the crack a is at 1.36 mm (54 mils) from the weld interface (c)

Structure characterization Material susceptibility is one of the key parameters controlling PWSCC. As the microstructure may be known from fabrication records or from field replicas, correlating head penetrations microstructures with the PWSCC field behavior is of particular interest in evaluating the risk of PWSCC initiation in field components. With this in mind, EDF has derived a carbide-distribution based classification, Table 5.5.

310

5

Nickel Base Alloys

Table 5.5 RPV head. Carbide distribution-based head penetration material classification Structure Type

Class

I = low

a

PWSCC susceptibility II = medium PWSCC

b

susceptibility

c

a b

III = high PWSCC susceptibility

Carbides Distribution Full grain boundary coverage without intragranular precipitation Intergranular precipitation not fully covering grain boundaries with slight intragranular precipitation Intergranular and intragranular precipitation with ghost grain boundaries Mostly intragranular precipitation with ghost grain boundaries Heavy intragranular precipitation with ghost grain boundaries Heavy intragranular precipitation, more uniform than for IIc type structure, ghost structure hardly visible

Table 5.6 RPV head. Structure classification of the penetrations destructively examined in the EDF hot laboratory at Chinon Structure type

Cracked penetration

Sound penetration

Total

I—Low susceptibility II—Medium susceptibility III—High susceptibility

1 15 1

3 5 0

4 20 1

According to the classification in Table 5.6, most of the penetrations destructively examined (16 out of 17), because of PWSCC presence, belong to a PWSCC susceptible structure type. Hardness measurements Hardness measurements have been performed either for cold work assessment or for material properties evaluation (Fig. 5.112). There were no significant hardness differences between the three structure types. For Type I structure, the range was 191/220 HV2, for Type II structures, 169/246 HV2; 218 HV2 has been measured for a Type III structure. This means that hardness is of a lesser influence as concerns PWSCC initiation than carbide precipitation for example. However, Fig. 5.113 suggests that the probability of early PWSCC initiation is higher for material with surface hardness’s greater than *200 HV. The hardness figures from Fig. 5.113 are not surface measurements but have mostly been taken in the bulk base material of retired penetrations or specimens.

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

311

~1.5 cm (0.6’’)

RPV head

RPV head Penetration Penetration

Butter

Butter

Stainless Steel clad

Weld

Weld Penetration #T17

Penetration #T62

Fig. 5.112 RPV head. Axial sections of J-groove welds. Hardness (HV0.1kgf) measurements on penetrations having been in service for 170,000 h

160000 140000 120000

Time (h)

100000

No PW SCC

80000

PW SCC

60000 40000 20000 0

150

170

190

210

230

250

270

290

Hardness (HV)

Fig. 5.113 RPV head. PWSCC initiation time versus the penetrations base metal Vickers hardness (HV2kgf)

312

5

Nickel Base Alloys

Ovalization measurements

3

120

2,5

100

2

80

1,5

60

1

40

0,5

20

0

Head penetrations ovalization (mils)

Head penetrations ovalization (mm)

There is a fairly good correlation between the position of a penetration on a RPV head and the degree of ovalization; the ovalization is higher at steep set-up angles as shown in Fig. 5.114. Most of the results come from silastic molds taken from the field and sent to the EDF hot laboratory of Chinon for laser profilometry implementation. As the residual stresses resulting from the J-groove weld fabrication increase with the degree of ovalization, it can be postulated that the greater degree of ovalization, the higher the PWSCC probability. This postulate is supported by the results from multiple French head inspections, which have shown that most of the cracks were associated with the outer periphery, as shown on Fig. 5.115.

0 0

10

20

30

40

50

Vessel/penetration angle (°)

Fig. 5.114 RPV head penetration ovalization versus the angle between the penetration and the RPV head (set-up angle). Triangles are for 3 loops plants and squares for 4 loops plants

NUMBER OF CRACKED VH PENETRATIONS VERSUS ANGLE 70 60 50

Number of 40 cracked penetrations 30 20 10 1300 MW

0 0-17°

17-26°

Angle (°)

900 MW 26-36°

Fleet

36-47°

Fig. 5.115 RPV head. Number of cracked penetrations versus set-up angle, for 2 series of EDF PWRs (900 MWe are 3 loops; 1300 MWe are 4 loops)

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

313

Conclusion, remedial actions In 1991, when the RPV head leak occurred, little was known about the impact of the media generated by the primary water in the penetration-head annulus on head wastage. This lack of knowledge drove EDF and the French safety authorities to prohibit the operation of reactor pressure vessels with TW nozzle cracks. Given the costs of inspections, specimen removal, analysis, the cost of repairs and most of all the cost of the down time, there was a cost benefit in simply replacing the RPV heads. In 1993, EDF decided to replace all RPV heads which had penetrations made of Alloy 600 (54 heads out of 58 at that time). The replacement materials chosen were Alloy 690 for the base metal and Alloy 152 for the welds. The replacement schedule was dictated by a safety criterion (minimum residual ligament) and on economic considerations (for example, combined with a SG replacement or with CRDM replacements). The last “A600” head was replaced in 2009. None of the 54 replaced heads had reached more than 170,000 h of operation. The EDF maintenance strategy has been reasonably successful as no further RPV head leaks have occurred in EDF plants and the population of cracked penetrations has been limited.

5.2.9

Destructive Examination of a Boat Sample Harvested From a Leaking Penetration of a B&W Unit

Plant main characteristics: B&W PWR, 850 MWe, 2 loops, USA. Equipment/Component: Reactor Pressure Vessel Head, CRDM #21 (Fig. 5.116). The 69 CRDM nozzles of the relevant head are constructed of A600 and procured in accordance with requirements of SB-167 of ASME B&PV code. The CRDM nozzle material was hot rolled and annealed. The RPV CRDM nozzles were shrunk fit into RPV head penetrations and welded with a J-Groove weld with A182 filler material. The specified diametrical interference range for the shrink fit was 0.5 to 1.5 mils (13 to 38 µm). Operating conditions: primary water, head temperature: 602°F (317 °C). Time of operation: 28 years. Failure discovery: in December 2000, the VT inspection of the RPV head revealed leak traces of at least 5 of the 8 thermo-couple nozzles and of the nozzle #21 (Fig. 5.117). This observation triggered NDE inspections such as PT, ECT and UT. Nozzle 21 NDE results were the followings:

314

5

Nickel Base Alloys

SS flange

A600 weld Control rod

CRDM nozzle (SB-167 ; A600) Thermo couple nozzle Insulation

Boron deposits

RPV head Counterbore region

A600 cladding A600 weld 4.00’’ nominal 2.75’’ bore 2.50’’ OD leadscrew support Inner bore leadscrew support OD leadscrew

Fig. 5.116 RPV head. Typical B&W CRDM design

Fig. 5.117 RPV head CRDM. View of the “popcorn” like boron deposits at the base of nozzle #21

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

315

• Crack originated in A182 weld filler material and later moved into wall of CRDM nozzle; • Crack was radial and axial; • No circumferential crack was evidenced. Similar event frequency: many RPV head penetrations have cracked in France, USA, Japan, Sweden, Belgium, UK… Fortunately, only a small number leaked in operation. Specimen/sample characteristics: a boat sample of the Alloy 600 pipe and Alloy 182 attachment weld from CRDM #21 was received in the Metallurgy Laboratory for evaluation of NDE indications. The two indications of interest consisted of an anomalous UT reflection at the interface between the weld and pipe and a liquid penetrant indication suggesting a radial crack extending from the toe of the fillet weld at the pipe approximately 3/4″ across the weld. It is suspected that this crack produced the leak path discovered by the presence of boric acid on the outside of the head. DE goal: the DE goal was evaluation of NDE indications. Results The sample received and the sectioning in the laboratory are illustrated in Figs. 5.118 and 5.119.

Fig. 5.118 RPV head. CRDM #21. Schematic of sample in as-received conditions (dimensions in inches)

316

5

Nickel Base Alloys

Fig. 5.119 RPV head. CRDM #21. Sample as-received in the laboratory. Viewed in direction of arrow marked “Sample” Fig. 5.118. Scale is 1/16”

Fig. 5.120 RPV head. CRDM #21. Left: liquid penetrant indication extending from fillet weld at pipe (bottom) into EDM notch cut during sample removal. Circumferential component of indication (arrow) appears to be mechanical. 1/16″ scale. Line indicates plane of section for Fig. 5.122. Right: cracks visible on EDM cut on bottom of sample as-received in laboratory. 1/16″ scale

Laboratory visual inspection and color contrast penetrant inspection confirmed the presence of the radial crack and that the crack extended axially completely through the sample (Fig. 5.120). There was a considerable amount of disturbed metal from previous grinding of the weld surface, however, the crack could be seen at the free surface of the weld at moderately high magnification (Fig. 5.121).

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

317

Fig. 5.121 RPV head. CRDM #21. Left: crack that emerges from EDM cut at left and traverses rough ground surface of weld. Right: crack near the point that it disappears into the fillet weld

20 µm

Fig. 5.122 RPV head. CRDM #21. Left: full thickness of specimen showing multiple parallel cracks. Free surface of weld is at lower right. EDM cut at upper left. Right: thin filled crack tail from one of large open cracks not in view. Nital etch

Two sections, one for examination of the crack path and the other for examination of the weld/pipe interface, were created from the sample. The crack (Fig. 5.122 left) consists of multiple parallel cracks. The fine cracks extending from some of the gaping parallel cracks contain deposits that were analyzed by the energy dispersive x-ray attachment to the scanning electron microscope. These deposits tend to be rich in the alloying elements of the weld, especially niobium and to a lesser extent chromium and iron, relative to the base alloy of the weld. The weld is comparable to a freshly deposited weld of the same type (SFA 5.11 Class ENICrFe-3). As shown in the etched micrograph of Fig. 5.122 right, the cracks have some interdendritic tendency but are not wholly interdendritic. The cracks have some of the characteristics typical of hot cracking sometimes seen in this alloy. The long thin tail filled with material that is enriched in certain alloy elements is typical of cracks that form at temperatures near the melting point of the bulk alloy. That is,

318

5

Nickel Base Alloys

Base metal

Weld metal

1 mm

100 µm

Fig. 5.123 RPV head. CRDM #21. Left: cross section comprising view 3–3 Fig. 5.118. Right: interface between pipe (left) and weld. No discontinuities were present. Nital etch

they are somewhat like micro-fissures or liquation cracks that occur in weld metal of this type. The interface between the weld and pipe is shown in Fig. 5.123. The structure is somewhat coarse in this area but there are no cracks or other discontinuities that would explain the anomalous UT signal from this region. In order to more completely characterize the cracks, the section used to collect the data discussed above was broken out of the epoxy mounting material and remounted to provide the view identified 2–2 in Fig. 5.118. As shown in the illustration, the angle of the cut was such that the crack was successively ground away as different planes were examined in 0.010″ to 0.012″ increments. The initial appearance of the defect was considerably different when viewed in this direction (Fig. 5.124 left). At this point where the sample is at its deepest axial penetration, the defect takes the form of fine interdendritic cracking and does not have any characteristics of hot tearing. It does, however, bear a resemblance to the fissures described above. At the next grinding step, the weld defects appear about the same and severe intergranular cracking becomes evident in the pipe base metal (Fig. 5.124 right). As shown in Fig. 5.125 through Fig. 5.127, each of the defects in the weld is linked to an intergranular corrosion defect in the pipe base metal. With the possible exception of the first grind increment mentioned above, the weld indications are more open and might be classified as other than interdendritic corrosion if they were not coupled directly to the intergranular corrosion of the base metal (Fig. 5.126).

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

319

Base metal EDM cut

Figure 5-125

1 mm

1 mm EDM cut

Fig. 5.124 RPV head. CRDM #21. Left: first increment of grinding. Plane shown intersects crack at deepest point in sample. Right: second increment of grinding. Severe IG cracks in base metal. Nital etch

320

5

Nickel Base Alloys

1 mm

EDM cut

EDM cut

100 µm

Fig. 5.125 RPV head. CRDM #21. Left: area inset from Fig. 5.124. Right: same general area as Fig. 5.124 after another grind step. Dark areas are voids caused by corroded grains pulling out during polishing. Nital etch

EDM cut

1 mm EDM cut

Fig. 5.126 RPV head. CRDM #21. Grind plane near mid thickness of sample. Note cracking is still continuous through weld and base metal. Nital etch

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

Weld wetted surface

321

500 µm

Fig. 5.127 RPV head. CRDM #21. Grind plane near surface of sample. Note cracking is still continuous through weld and base metal. Nital etch

322

5

Nickel Base Alloys

Conclusion, remedial actions The preponderance of the evidence points to PWSCC as the primary mechanism of crack propagation in the weld and CRDM #21 base metal. There is no conclusive evidence that there were manufacturing defects in the original weld that participated in initiation of the PWSCC, however, the crack morphology suggests hot cracking or liquation cracking in the Alloy 182 weld metal may have a role in initiation of the defects. Qualitative comparison of the weld to freshly deposited weld metal confirms that the alloy type is as expected. The CRDM #21 has been repaired in accordance with 1992 ASME code Section XI. The flaws have been removed from both weld metal and nozzle base material using manual process (Fig. 5.128). The long-term solution for this unit was to replace the RPV head.

Fig. 5.128 RPV head. CRDM #21. PT inspection during excavation

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

323

5.2.10 Replica of a Leaking Control Rod Drive Mechanism Penetration From an MHI Unit Plant main characteristics: MHI PWR, 1180 MW, 4 loops, Japan. Equipment/Component: RPV head. CRDM nozzles #47 and #67 (see location on Fig. 5.129 and layout on Fig. 5.130). Operating conditions: primary water. Time of operation: 13 years. Failure discovery: the unit was under its 10th periodic inspection since April 20, 2004. When works prior to the head penetrations VT (70 locations in total) were conducted, white adhesive material was identified near the base of the CRDM nozzle #47 (Fig. 5.131 left). 270°

Vent pipe

180°

0°

CRDM nozzle with deposits

90° Thermocouple nozzle with leak trace

Fig. 5.129 RPV head. Penetrations arrange layout

324

5

Nickel Base Alloys

Thermocouple nozzle #67 CRDMs

Thermocouple drawing rod The seal housing is overhauled and the thermocouple is taken off during outage inspections. Water leakage may occur temporarily when the seal housing is assembled and the RCS filled at startup.

CRDM nozzle #47

~183 mm

Thermocouple housing

70 mm

Nozzles (A600)

102 mm

Boric acid

LAS RPV head

Thermocouple nozzle

Leak trace SS clad

RPV head

64 mm Thermal sleeve

A182 J-Groove weld

Fig. 5.130 RPV head. Layout of thermocouple nozzle #67 (left) and of CRDM nozzle #47 (right)

Deposit

Deposit

Leak trace (boric acid) Deposit

Fig. 5.131 RPV head. Left: view of the leak trace (boric acid) on the head, at the bottom of the CRDM nozzle #47. Right: view of the deposits on the thermocouple nozzle #67 and on the head

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

325

The adhesive material was analyzed on May 5 and was confirmed to be boric acid contained in the primary coolant. Inspection of this CRDM nozzle further revealed that the adhesive material was observed only around this nozzle. It was confirmed that the adhesive material is attributed to leakage from this nozzle. Inspections were also conducted on the other 69 piping nozzle stubs, and deposits were also observed on the thermocouple nozzle #67 (Fig. 5.131 right). Similar event frequency: many RPV head penetrations have cracked in France, USA, Japan, Sweden, Belgium, UK… Fortunately, only a small number leaked in operation. Specimen/sample characteristics: no sample was harvested from these nozzles, only one replica was taken. DE goal: the DE goal was leaks root cause analysis. Results Nozzle #47 Figure 5.132 shows the location of the replica. Linear cracks were identified by replica observation on the J-Groove weld attaching the nozzle to the RPV head (Fig. 5.133). The cracks propagate radially along the grain boundaries of the weld. Replica observations after grinding deep to -3 mm (-0.12″) from the surface revealed longer and branched intergranular cracks, still in the weld metal. A182 type weld 270° SS clad Replica

180°

0°

~120 mm A600 type nozzle

~70 mm ~102 mm

Fig. 5.132 RPV head. CRDM nozzle #47. Location of the replica

90°

326

5 ~14 mm (0.55’’)

Nickel Base Alloys

~15 mm (0.59’’)

Fig. 5.133 RPV head. Nozzle #47. Replica observation result. Left: after the first grinding sequence: −0.5 mm deep. Right: after the third grinding sequence: −3 mm deep

The Fig. 5.134 suggests that the leak path starts from the weld surface, at angle 270° which is the area where cracks have been observed by replica. These cracks likely propagated through the weld up to the bottom of the annulus. Once reaching the annulus, the water has easy access to the head upper face, generating boric acid deposits. The surface condition of the weld has been investigated (Fig. 5.135). Three separate conditions have been observed: grinder finishing, grinder + buff finishing and cutter ground and buff finishing. The procedure for grinder and buff finishing is as follows: after the welding, the surface of the weld is finished by grinder, and is further polished to a smooth one by buffing for non-destructive inspection. Regarding crack initiation, it cannot be denied that a blowhole due to the welding process, etc. could likely be the cause of crack initiation. However, it is

Leak exit

A600 nozzle

RPV cover head

Weld

Annulus bottom Weld-nozzle interface

Leak entry

Fig. 5.134 RPV head. Nozzle #47. Suggested leak path

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

327

270° 250°

290°

230° Grinder finishing Grinder and buff finishing

1 mm

Cutter cleaning and buff finishing

1 mm 90°

Fig. 5.135 RPV head. Nozzle #47. Surface finish condition of the weld

highly possible that the absence of surface finishing (buffing) of the weld resulted in tensile residual stresses, which in turn generated SCC. Note that in case of grinder finishing, generation of comparatively large tensile stress of about 770 MPa in the outer-most surface-layer was measured. Based on domestic and foreign experience, the observed cracks have been attributed to PWSCC. The findings indicate that the combination of stress, material and condition have led to PWSCC and eventually to leakage, Nozzle #67 No significant signal indication has been identified either by the helium leak test or by ECT and UT from the inner surface of the pipe. Review of the records of previous inspections has revealed a leakage of the primary coolant from the conoseal cover around the upper part of this stub at the time of commissioning after construction. Moreover, findings mentioned before have suggested that leaked boric acid was not wiped out appropriately when the primary coolant containing boric acid had leaked from the conoseal cover around the upper part of the stub at the time of commissioning after construction, which has allowed the boric acid to remain. Conclusion, remedial action The nozzle #47 leak is due to weld through-wall PWSCC.

328

5

Nickel Base Alloys

The nozzle #67 deposits come from an old conoseal leak and are not PWSCC related. As short-term remedial action, the J-Groove weld of nozzle #47 has been repaired by welding against leakage over the cracks with 690-type nickel-based alloy of high corrosion resistance, to prevent a potential leakage of the primary coolant from its boundary and also to stop the development of PWSCC by shutting off access from the primary coolant. The long-term remedial action involved head replacement with a head “made of” 690-type nickel-based alloy of high corrosion resistance.

5.2.11 Destructive Examination of a Boat Sample Harvested From a Penetration of a W Unit Plant main characteristics: W PWR, 1,120 MWe, 4 loops, USA. Equipment/Component: Reactor Pressure Vessel Head, CRDM nozzle #68. Operating conditions: primary water, head temperature: 550.4°F (288 °C). Time of operation: 20 years, but only 2.219 effective full power years at 600°F (315.6 °C) as this head is a “cold head”. Failure discovery: in accordance with the regulator requirements, ultrasonic inspections were performed on the inside of the relevant unit RPV head CRDM tube penetrations during the 2007 refueling outage. The inspections identified a 0.52″ long
0.326″ (13.2
8.3 mm) deep axial indication in the #68 CRDM tube, near the J-groove weld. The #68 penetration is a periphery tube and the maximum ultrasonic reflector was located 16.5° counter clockwise from the zero reference. A PT examination was performed on the surface of the #68 penetration weld zone and the result is shown in Fig. 5.136 (left). The PT exam identified a 0.150″ (3.8 mm) axial linear indication at the approximate orientation of the maximum ultrasonic reflector. In addition, a 0.050″ (1.3 mm) diameter rounded indication was detected on the J-groove weld. Similar event frequency: many RPV head penetrations have cracked in France, USA, Japan, Sweden, Belgium, UK… Fortunately, only a small number leaked in operation. Specimen/sample characteristics: to evaluate the indications, a ‘boat’ sample was removed from the #68 tube and the J-groove weld by EDM. However, the removed sample did not capture the rounded surface indication or the deepest portion of the axial indication (Fig. 5.136, right). In addition, the excavation uncovered an angled, sub-surface defect that was connected to the axial indication.

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

329

Fig. 5.136 RPV head. CRDM #68. Left: photo showing two PT indications on the surface of the J-groove weld. The axial indication (left arrow) measured 0.150″ (3.8 mm) long and corresponded to the approximate location of the axial ultrasonic reflector. A rounded 0.050″ (1.3 mm) diameter indication was also detected (upper arrow). The lab evaluations indicated the J-groove weld toe was below the axial indication. Right: photo showing the field PT result for the excavation site after the boat sample was removed. The boat sample did not capture the rounded indication (#1) or the deepest portion of the axial indication (#2). In addition, the excavation uncovered an angled, subsurface linear defect (#3) that intersected the axial indication

DE goal: the primary objective was to determine the nature and cause of the indications in the boat sample. Results Laboratory pre-sectioning evaluations VT The as-received boat sample is shown in Fig. 5.137. The sample measures approximately 1.5″ long
0.75″ wide (38
19 mm) and has a maximum thickness of 0.375″ (9.5 mm).

1 cm

1 cm Up right

Down left

Down right

Fig. 5.137 RPV head. CRDM #68. Left: wetted surface of the boat sample. Note the relatively heavy grinding toward the upper half (weld side) of the sample. No crack-like indications are visible. Right: EDM cut surface. No cracking is visible

330

5

Nickel Base Alloys

The visual inspections did not identify cracking or other linear indications that corresponded to the field PT indications. The most significant observation was the presence of heavy surface grinding toward the upper half (i.e., weld side) of the sample. Due to the surface grinding, the weld toe could not be identified by the visual inspection. The EDM surface exhibited smooth, rounded features that were typical of the EDM cutting process. FLUORESCENT PT The upper left portion of the sample contained a linear indication that bled heavily on both the wetted and EDM cut surfaces. The indication measured approximately 0.18″ (4.6 mm) long on the non-cut surface and 0.375″ (9.5 mm) long on the EDM surface. Although the indication was not continuous around the upper edge of the EDM cut, a subsequent PT exam confirmed the two linear indications were connected. Both linear indications were visible in the second exam, even though the fluorescent dye was only applied to the EDM surface. The location and orientation of the linear indications corresponded to the axial indication that was identified by the field NDE inspections. The fluorescent PT examination also detected a single rounded indication on the EDM surface. The rounded indication was located approximately 0.090″ (2.3 mm) from the axial indication. LABORATORY MICROFOCUS RT The examination detected the axial indication that was identified by the fluorescent PT; although, no other indications were detected. STEREOSCOPE EXAMINATIONS The boat sample surfaces were examined using a stereoscope, with particular emphasis on the PT indications. Due to surface grinding marks, the axial indication could not be identified by the stereoscope inspection of the non-cut surface. The axial indication was detected on the EDM surface. SURFACE SEM On the non-cut surface, the axial indication was relatively tight and could only be detected at high magnifications. The indication followed a non-branching irregular path that did not necessarily coincide with the local grinding marks (Fig. 5.138). In one region, the indication coincided with a local patch of ductile features, which appeared to be related to smeared metal from the surface grinding. No crack branching was observed on the non-cut surface. During the SEM inspections of the non-cut surface, several angled fissures were also detected. The fissures tended to follow to the local grinding direction. The axial indication was easily detected by the SEM examination of the EDM surface (Fig. 5.139 left). Figure 5.139 (right) provides a typical view of the crack. There was little crack branching, except near the ends of the indication. This figure also provides a view of the rounded PT indication on EDM surface. As was

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

331

50 µm

50 µm

Fig. 5.138 RPV head. CRDM #68. Left: SEM photo near the upper end of the axial indication on the non-cut surface. There is evidence of smearing from the surface grinding. Right: SEM photo of the axial crack on the non-cut surface. The crack followed an irregular path and was non-branching. In this area, the crack did not follow the local grinding marks

1 mm

5 mm

Fig. 5.139 RPV head. CRDM #68. Left: BSE montage of the EDM cut surface. The arrows point to the crack. Right: SEM photo near the upper end of the axial indication on the EDM surface. The left arrow points to crack branching near the non-cut surface edge. The right arrow points to the globular particles that covered the rounded PT indication

reported during the stereoscope inspection, the indication features were obscured by globular debris from the EDM cutting process. Laboratory sectioning plan and sample identifications The laboratory NDE results indicated the upper left portion of the boat sample in Fig. 5.137 (left) contained the axial indication that was detected by the field NDE inspections. The boat sample also contained a rounded indication on the EDM cut, which corresponded to a portion of the angled, sub-surface indication that was uncovered by the boat sample removal (indication #3 in Fig. 5.136 right). A boat sample sectioning plan was developed to allow for metallurgical characterization of the two indications and to perform the remaining evaluations that were identified in the test plan. The boat sample sectioning details, sample identifications, and planned examinations are summarized in Fig. 5.140.

332

5

Nickel Base Alloys

Fig. 5.140 RPV head. CRDM #68. Left: photo showing the initial boat sample cuts. The horizontal cut between samples A and B is located approximately 0.050″ (1.3 mm) below the tip of the axial indication. Right: sub-sectioning for sample A

Sample C macro-etch results The section C cut face was lightly ground and macro-etched. The etching revealed the boat sample contained portions of the last two weld passes. Based on the profile of the wetted surface of the tube, there was minor surface grinding of the tube near the toe of the weld. Sample B metallography The horizontal cut that separated samples A and B was approximately 0.23″ (5.8 mm) from the upper EDM edge. The cut location was below the axial indication on the wetted surface of the boat sample, but intersected the axial indication on the EDM surface. The horizontal cut face on sample B was prepared in a metallurgical mount. The tube base metal contained branched, intergranular cracking (Fig. 5.141 left) that was typical of PWSCC. The crack branches had sharp tips and contained little oxidation. No crack blunting was observed. There was limited interdendritic cracking into the weld (Fig. 5.141 right). Within the sample B mount, none of the cracking extended to the wetted surface of the boat sample.

40 µm

40 µm

Fig. 5.141 RPV head. CRDM #68. Left: etched view of the branched, intergranular cracking in the sample B tube material. Electrolytic phosphoric-nital dual etch. Right: etched view near the weld metal crack end in sample B. The two cracks have an interdendritic appearance. Within sample B, the cracking did not extend to the wetted surface of the mount. Electrolytic phosphoric-nital dual etch

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

333

40 µm

40 µm

Fig. 5.142 RPV head. CRDM #68. Left: surface indication in the sample B mount. There was no evidence of crack extension from any of the surface indications. Electrolytic phosphoric-nital dual etch. Right: sample B tube material with an electrolytic phosphoric acid etch to reveal the carbide structure. The tube microstructure contained significant intragranular carbides and partially decorated grain boundaries

The surface of the weld exhibited an irregular contour and several linear indications were observed (Fig. 5.142 left). Based on the heavily deformed surface microstructure, the linear indications appeared to be laps that were formed by metal deformation during grinding. In the examined section, the deformed layer measured up to 0.0007″ (18 µm) thick. There was no evidence of service-related crack initiation from the indications. The deformed metal and local crevices are believed to be the source of the fissures that were detected by the SEM examination of the wetted surface. The tube material had a relatively fine duplex grain structure with the smallest grains measuring ASTM Size 7 and the largest grains ASTM Size 5. The microstructure contained large quantities of random intragranular carbides and the grain boundaries were partially decorated with carbides (Fig. 5.142 right). This microstructure will have a relatively high susceptibility to PWSCC. Sample A1, crack surface examinations The crack surface was reflective and appeared intergranular. There were no clear indications of crack age; although, a thumbnail-shaped region on the tube appeared to be more oxidized than the remainder of the sample. The tube portion of the sample exhibited an intergranular morphology in all examined regions (Fig. 5.143). The exposed surface of the weld exhibited several characteristics. At low magnification, the weld cracking appeared to follow the columnar interdendritic features of the solidification pattern (Fig. 5.144 left), which is typical of SCC. However, at higher magnifications, some of the features were smoother than is typical for PWSCC. Several of the smooth regions were evaluated by EDS techniques; however, the areas did not exhibit manganese segregation that can be

334

5

Nickel Base Alloys

Fig. 5.143 RPV head. CRDM #68. Left: typical SEM view of the tube crack surface in the sample A1. The tube material exhibited intergranular features throughout the sample. Right: lower portion of the exposed crack surface in sample A1. The left side of the sample is intact weld metal that was broken open in the lab. The large grained area near the center of the photo was located in the base metal heat affected zone

Fig. 5.144 RPV head. CRDM #68. Left: SEM photo near the center of the exposed crack in the sample A1 weld. At low magnification, the weld cracking appeared to follow the columnar, interdendritic features of the weld solidification pattern. Right: SEM view of the sample A1 crack surface near the upper end of the weld. The arrow points to a planar defect in the weld. There are several cracks within the weld that are connected to the defect. The ductile region toward the upper left corner of the sample was broken open in the lab

associated with hot cracks. Based on the crack surface features, it was concluded that there was evidence of both PWSCC and hot cracking in the weld. The exposed weld surface also contained a planar defect that was parallel to the fusion line (Fig. 5.144 right). Based on defect location and orientation, the defect was caused by lack of fusion between weld passes. Within the weld, there were several cracks that were connected to the defect. Based on the general characteristics of the weld defects, interdendritic weld separations, direction of crack branching, and local ductile tearing, it was concluded that the primary direction of cracking within the weld was toward the wetted surface

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of the boat sample. This suggests the PWSCC did not initiate from the wetted surface of the boat sample. Sample A2A evaluations The section A2A axial cut was located approximately 0.040″ (1 mm) from the rounded PT indication on the EDM surface. The indication was identified as a weld lack of fusion defect between the surface of the tube and the weld. The metallurgical sample was re-polished in preparation for an SEM exam. The polishing step uncovered a porous inclusion near the edge of the lack of fusion crevice (Fig. 5.145 left). Several incipient interdendritic cracks had initiated from the edge of the inclusion and the lack of fusion crevice (Fig. 5.145 right). Most of the cracks appeared to be hot cracks; however, the angular appearance of two indications appeared similar to incipient PWSCC. Qualitative EDS evaluations were performed on the large inclusion, the material in the lack of fusion crevice, several small inclusions that were adjacent to the crevice, and the oxide within several cracks. A general dot map scan of the elements was also performed. The results are summarized below: • The large inclusion and most of the smaller inclusions contained titanium, nitrogen, and oxygen, which suggests they were titanium nitrides or oxides. One very small weld metal inclusion contained calcium and fluorine, which was likely related to the welding flux; • The lack of fusion crevice contained oxidized metallic particles from the EDM wire and base metal cutting debris (i.e., tungsten, oxygen, iron, nickel, chromium and niobium); • The material within the incipient cracks was consistent with Inconel 182 weld metal oxidation products;

Fig. 5.145 RPV head. CRDM #68. Left: SEM photo of the sample A2A metallurgical mount. Note the large inclusion (arrow) that is adjacent to the lack of fusion defect. Right: SEM photo with arrows pointing to several cracks that initiated from the edge of the inclusion. The angled appearance of the lower two cracks appears similar to incipient PWSCC. Also note the incipient penetrations along the tube (right) side of the inclusion

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• No measurable fluorine or other potentially corrosive elements were identified in the incipient cracks or the lack of fusion crevice. The remaining Sample A2A metal was removed from the mount and re-oriented in a new metallurgical mount. The sample was positioned so the axial crack was perpendicular to the mount face, with the upper portion of the EDM cut parallel to the mount face. The primary objective for the mount was to determine if the lack of fusion defect continued toward the axial crack within the mount. The re-oriented mount was evaluated at three locations within 0.013″ (0.33 mm) of the EDM surface. No lack of fusion or other anomalies were identified. The grinding continued for another 0.094″ (2.4 mm) on the re-oriented sample. There was limited crack branching within the weld. The tube cracking exhibited intergranular features. Microhardness Testing Microhardness measurements were performed at several areas of interest in the sample B metallurgical mount. The results can be summarized as follows: • The equivalent weld hardness values ranged from 89.7 Rockwell B (HRB) to 98.6 HRB in areas away from the ground (cold worked) surface. The weld hardness in the cold worked surface layer was between 21.2 Rockwell C to 25.3 HRC; • The equivalent tube hardness measurements were between 82.0 HRB and 88.1 HRB. In general, the higher measurements were located toward the outer diameter of the tube. Other than the relatively high hardness on the cold worked surface layer of the weld, the measurements are considered typical for the fabrication materials (i.e., mill annealed Alloy 600 tubing and Inconel 182 weld metal). Conclusion, remedial action The boat sample contained a 0.032″ (0.8 mm) long portion of the angled, sub-surface defect that was uncovered by the boat sample excavation. The defect was caused by lack of fusion between the next to last weld pass and the tube surface. The metallurgical sections identified several incipient cracks that had initiated from the sides of the lack of fusion crevice. Based on the field PT results, the lack of fusion defect was connected to the axial indication; although, this connection was not observed within the boat sample material. The surface connected portion of the axial indication measured 0.18″ (4.6 mm) long and was located in the fillet leg of the J-groove weld that was adjacent to the wrought tube. Within the weld, the axial indication exhibited multiple defect/crack morphologies that were characterized as lack of fusion between weld passes, welding hot cracks, primary water stress corrosion cracking (PWSCC), and local regions of ductile tearing between crack ligaments. The general direction of crack propagation was toward the wetted surface of the weld, which indicates the PWSCC cracking did not initiate from the wetted surface of the boat sample.

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In the wrought tube material, the axial indication exhibited branched, intergranular features that were typical of PWSCC. The tube/weld microstructures and chemistries were consistent with the specified materials (i.e., mill annealed Inconel 600 tube and Inconel 182 weld). Based on the presence of random intragranular carbides and partially decorated grain boundaries, the tube material had a relatively high susceptibility to PWSCC which is typical for mill annealed tubing produced during the 1970’s. The tube microhardness measurements ranged from equivalent values of 82.0 to 88.1 Rockwell B scale, which indicates there was not a high degree of cold working. The weld surface exhibited heavy grinding that resulted in a 0.0007″ (18 µm) thick cold worked layer and grinding laps. The microhardness measurements for the cold worked layer measured up to 25.3 Rockwell C scale. There was no evidence of crack initiation from the cold worked layer or the grinding laps. Based on the laboratory evaluations, the PWSCC cracking is attributed to the detected welding defects, a susceptible tube material microstructure, the existence of a tight crevice condition created by the welding defects, and the presence of high hoop stresses on the outer diameter of the tube at this location. The following is considered the most probable scenario for the PWSCC cracking: • The original four-layer welding process generated a sub-surface lack of fusion defect that was not detected by the fabrication surface non-destructive examination (NDE). The lack of fusion defect corresponds to the angled, sub-surface defect that was uncovered by the boat sample excavation and was partially captured in the boat sample; • The fabrication welding process also generated a non-detected defect or a non-relevant indication that was connected to the lack of fusion defect and the weld surface. This defect corresponds to the rounded PT surface indication that was not captured by the boat sample. The imperfection may not have been detected by the fabrication surface exams due to the heavy surface grinding, a defect location that was slightly below the weld surface, or a rounded indication size that was acceptable per the code of construction (i.e., 0.06-inch, (>1.6 mm)). Given the widespread degradation present in the RVH at the 2002 outage, the utility decided to replace the RVH. This decommissioned head was made available to the industry for DE. Similar event frequency: several RVH nozzles leaks worldwide (USA, France and Japan). Specimen/sample characteristics: six penetrations were removed from the retired head, however, the DE results of only one (#54) is reported here. Although a variety of penetration removal methods were evaluated, radiological contamination controls practiced at the repository limited the cutting techniques. Of the alternative cutting options considered, an oxy/fuel process was determined to be the most viable alternative (Fig. 5.146). One concern with the application of a high heat-input process was that the J-groove weld and penetration tube should not be exposed to temperatures higher than those experienced during the reactor operation. An upper temperature limit of 600°F (316 °C) was imposed at the J-groove weld during the penetration removal. However, oxidation products from the cutting process did cover the primary water-wetted surfaces. One important step was the removal of oxidation products from the cutting process. Preparation of the CRDM penetration assemblies by the removal of copious oxidation products introduced by the oxy/fuel cutting process and stripping off loose, activated, oxides produced during plant operation were accomplished for four penetrations. A replication stripping technique enabled the controlled and sequential removal of these loose deposits from key regions of the penetration surfaces and captured the deposits for future analysis, if required. Additional

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Fig. 5.146 RVH penetration #54. Left: cutting torch assembly (arrowed). Right: penetration in as-cut conditions

cleaning was accomplished using dry-ice impingement and demineralized water swabbing. Figure 5.147 illustrates the surface conditions during the various cleaning stages. On completion of the cleaning process a sealing coat was applied to the flame-cut surfaces to provide a degree of protection from the sharp edges.

Fig. 5.147 RVH. Top left: as received condition of penetration #59. Top right: partial replica stripping of oxy/fuel oxidation products. Bottom left: penetration #59 following stripping and dry-ice blasting. Bottom right: cleaned primary surface penetration #10

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A final high-resolution replica was taken from important regions of the CRDM penetrations to enable subsequent detailed examination of surface features to be undertaken at a location removed from the high dose field of the cleaned penetration assemblies. DE program and goal: the broad objectives of this DE program were to (i) provide a description of surface and volumetric defects that can be used to benchmark the NDE capability against real flaws, (ii) improve the fundamental understanding of the underlying degradation mechanisms of base and weld metals, and (iii) gain insights into the RVH annulus environment that develops as a result of primary water leakage. Results: A wide-ranging metallurgical examination of penetration assembly # 54 was undertaken requiring detailed planning at each stage to optimize the data obtained from the destructive analysis; key to this being the development of sectioning plans initially based on the NDE and replication finding as shown in Fig. 5.148. Many features displayed by penetration 54 provided unequivocal evidence of significant weld repairs having been undertaken, including the replacement of the penetration tube following either a partial or complete fill of the J-groove during manufacture. Figure 5.149 illustrates significant weld bead width variations around the circumference together with an irregular weld overlay pattern. While the morphology of surface weld beads indicates nonstandard welding, the principal evidence of repairs was from cross sectional profiles through the weld. Figure 5.150 is typical of a

VET3

8

EC Indication Field UT Indication Field EC Indication Vendor UT Indication Vendor Replica Indications EC Field Wet Face Initial Cuts Azimuthal Sectioning

Isolated Tube ID Indications

Possible Wastage VET1

VET2 FUT1

VUT4 Weld Profile

VUT1

6 FET1

4

VET4

FET4

FUT3 VUT6

FET2

FUT3

VUT2

A1A4

A1A5

C1A4

C1A3

C1A2

B1A1

C1A1

B1A2-4

B1A5

A1A1

2

VUT5 VUT2

A1A3

VUT3 FET3

A1A2

Distance From Bottom of Penetration (in)

10

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310 320 330 340 350 360

0 Degrees

Fig. 5.148 RVH penetration #54. Sectioning plan based on combined field (F) and laboratory (V) NDE together with J-weld wetted surface replica indications

5.2 Destructive Examinations Related to Reactor Pressure Vessel …

180°

341

180°

90°

270°

270° 90°

0°

0°

Fig. 5.149 RVH penetration #54. Replica of J-weld wetted surface of and trace of weld passes (obtained from replica)

End of Annulus Gap

Low Alloy Steel J-weld

End of Annulus Gap

Low Alloy Steel

Butter

Butter J-weld

Weld Repair

Weld Repair

Penetration Tube A82 weld overlay

Penetration Tube A82 weld Overlay

Fig. 5.150 RVH penetration #54. Etch macro-section illustrating the various regions associated with the weldment at the 190° (left) and 165° (right) planes

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number of locations around the J-groove, where weld fusion locally extended into the penetration tube, resulting in an abrupt microstructural change within the wrought-tube microstructure. In addition, the annular gap extended beyond the butter layer and original J-weld to the root of the weld repair, indicating the removal and replacement of the original penetration tube. Other than the two abnormalities associated with the weld repair, i.e., the deep weld penetration into the tube and the extended annular gap, no defects were identified at these locations that corresponded to the circumferential NDE indications. However, there appeared to be a coincidence between excessive weld penetration into the tube and the location of circumferential NDE indications at weld root. No evidence of corrosion (wastage) was present within the RVH annulus. Bulk weld and weld repair metal contained a variety of defects including hot cracks, inclusions, cavities and lack of fusion. Void defects throughout the buttering layer were often associated with either inter-pass boundaries or non-metallic inclusion defects, especially adjacent to the low alloy steel interface. Significant circumferential cracking, and to a lesser extent radial cracking, was manifest at the butter-layer wetted surface (see Fig. 5.151). This widespread cracking extended within the butter layer from the low alloy steel interface to the J-weld wetted surface following inter-dendritic, and often parallel, paths. Figure 5.152 illustrates butter-layer cracking that appeared to stop at the weld overlay interface in this particular sectioning plane. However, as the crack has propagated along the butter to low alloy steel interface, small corrosion pits have formed in the low alloy steel, indicating a link to the primary environment.

Radial direction

Fig. 5.151 RVH penetration #54. BSE micrographs of wetted surface. Left: multi-directional cracking and witness of surface grinding. Right: relatively wide circumferentially orientated cracking exhibiting branching, together with straight unbranched radial cracks

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Fig. 5.152 RVH penetration #54. Left: example of butter layer cracking in the as-polished condition. Cracking appears to stop at weld overlay (dotted line) in this plane. Note the cracking within the Alloy 82 weld overlay. Corrosion pits had developed on the low alloy steel side of the interface. Right: crack initiating at the J-weld wetted surface (arrow)

Figure 5.152 also illustrates shallow cracks that initiated in the Alloy 82 weld overlay and propagated into the butter-layer. Another example of cracking, in this case initiating at the primary water wetted J-weld surface, is presented in the same Figure (right micrograph). The characteristics of the various cracks, some clearly unconnected to the wetted surface, suggested both of fabrication related and environmentally induced defects. To aid in the characterization of the observed cracks and particularly to aid in mechanistically discriminating the cracks, discerning criteria were developed from fractographic observations; two examples are presented in Figs. 5.153 and 5.154.

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Fig. 5.153 RVH penetration #54. Fracture of a ‘Buried’ Hot-crack in the J-weld, with rounded interdendritic fracture morphology

1

2

3

4

Fig. 5.154 RVH penetration #54. Fracture morphology of a PWSCC crack adjacent to the J-weld wetted surface

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Conclusion and remedial action Based on the observations made during the destructive examination of penetration number 54, a root cause analysis has concluded: • Observations of excessive weld penetration into the tube is indicative of an extensive weld repair during fabrication, which might be responsible for a ‘false-call’ NDE indication in this penetration. • Extensive cracking of the J-weld butter layer has developed, some of which was associated with inclusions and contamination, while others were associated with environmental degradation. It is believed that inadequate cleaning of the J-grove surface, following air-arc gouging of the weld preparation, contributed to fabrication related crack initiation in the butter layer adjacent to the low alloy steel interface. • Mechanistic assessments using fracture morphology and surface chemistry indicated that cracking in the butter-layer was consistent with hot cracking and primary water stress corrosion cracking (PWSCC) mechanisms. • Alloy 82 weld overlay cracking is a manifestation of PWSCC. PWSCC initiation in Alloy 82 has not been observed frequently in the field. However, dilution of the Alloy 82 by the underlying dilute Alloy 182 butter layer decreased the Alloy 82 chromium content, increasing its susceptibility to PWSCC. The head was replaced with a new one with TT690 penetrations and A52/152 butter and J-groove welds.

5.2.13 Destructive Examination of a Control Element Drive Mechanism Repaired with A52 Plant main characteristics: CE PWR, 1100 MWe, 2 loops, USA. Equipment/Component: Reactor Pressure Vessel Head, CEDM #64. Operating conditions: primary water, 310.3 °C (590.6°F). Time of operation: 4 years for the area of concern. Failure discovery: a rejectable rounded indication was identified in the J-groove weld of CEDM #64 during a penetrant test in 2008 (Fig. 5.155). The weld material where this defect appeared (alloy 52) had been in service since 2004 (following an embedded flaw repair) and had undergone acceptable penetrant examination in 2006 after one cycle of operation. After shallow grinding, the rejectable indication is still there. Similar event frequency: several PT indications on repairs worldwide.

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Nickel Base Alloys

Fig. 5.155 RPV head. Localization of the PT rejectable indication on CEDM #64 (black arrow)

Specimen/sample characteristics: EDM was used to extract a boat sample which weighed 20.76 g and measured approximately 43 mm (1.7``) long
15 mm (0.6'') wide
*10 mm (0.40``) deep. DE goal: the primary purpose of the laboratory examinations was to identify the most likely cause(s) for the delayed presentation of the PT indication. Results The original PT indication identified during the site inspection in 2008 is shown in Fig. 5.156. This indication was rounded and measured approximately 12 mm (1/2'') in diameter. The indication continued to bleed out after cleaning and reapplication of developer. Figure 5.157 shows the location of the PT indication after removing the developer. The approximate location of the boat sample is annotated on this figure. Multiple weld beads and surface grinding are evident in this area. Radiographic inspection performed at the site detected a void measuring *0.193``
*0.082'' (*4.9
*2.1 mm) coincident with the PT indication. Low magnification photographs showing the wetted surface and EDM surface are presented in Fig. 5.158. These photographs show the relative locations of the PT indication and two prominent gouges on the wetted surface along with a void on the EDM surface.

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347

Fig. 5.156 RPV head. CEDM #64, site photograph showing original PT results and *12 mm (1/ 2”) diameter indication

Fig. 5.157 RPV head. CEDM #64, site photograph showing indication region after cleaning. Approximate boat sample location is indicated (dotted line)

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Fig. 5.158 RPV head. CEDM #64, low magnification photographs of the boat sample

200 µm

200 µm

Fig. 5.159 RPV head. CEDM #64, photographs of the PT indication on the wetted surface. Left: before cleaning, right: after cleaning 5 min in alcohol. No evidence of cracking associated with this void

Stereo microscope photographs were taken of the PT indication on the wetted surface (Fig. 5.159). It was apparent that red dye staining was present within the void. Thin fragments of material were identified surrounding the entrance to the void. A white crystalline material was present within the void. This material was further analyzed by SEM/EDS. There was no evidence of cracking associated with this indication or anywhere else on the wetted surface of the boat sample. SEM and EDS examinations were performed on the boat sample prior to sectioning. SE imaging was employed to describe sample topography, while BSE imaging was used to qualitatively determine chemical composition differences present. In a BSE image, gray level contrast varies primarily with the average atomic number of a sample, with lighter atomic number regions appearing dark and higher atomic number regions appearing bright. The EDSattachment on the SEMwas used to qualitatively and semi-quantitatively determine the chemical composition of various regions of interest.

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Fig. 5.160 RPV head. CEDM #64, low magnification SE image of the PT indication on the wetted surface of the boat sample, showing the five areas (A through E) examined at higher magnifications

Five areas (designated A through E) have been selected for high magnification examinations (Fig. 5.160). Area ``A'' contained overlapping grinding marks but no evidence of cracking. Grinding marks were observed at area ``B'' as well. Area ``C'' contained the most convincing evidence of crack-like features. Figure 5.161 shows this area at higher magnifications, after rotating and tilting to better show the fracture surface. The fracture surface in area ``C'' appeared to be

Fig. 5.161 RPV head. CEDM #64, higher magnification micrographs of Area C, with sample titled to better view fracture surface. Evidence of ductile tearing on fracture surface

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Nickel Base Alloys

ductile tearing and may have occurred during grinding. There was no composition difference between the base weld metal and the fracture surface that would indicate hot cracking. Fracture surfaces associated with hot cracks can contain elevated amounts of silicon and manganese relative to the bulk material due to micro-segregation that occurs during solidification. Similar micrographs were taken in areas ``D'' and ``E''. The cracking in these areas appeared to be ductile tearing, similar to area ``C''. There was no evidence of environmentally induced cracks in any of the areas examined around the PT void or elsewhere on the boat sample wetted surface. The EDM surface of the boat was also examined by SEM/EDS. The most prominent feature on this surface was the void. The primary elements detected by EDS included carbon, oxygen, aluminum, tungsten, titanium, chromium, iron, nickel, and copper. No manganese was detected. Since Alloy 182 contains 7.5% manganese, it appeared that Alloy 52 material was present on the EDM surface in this area. Transverse sections were made through the boat sample at the five locations shown in Fig. 5.162 to permit cross section metallographic and SEM/EDS examinations of the known defect regions and determine whether there was any evidence of environmental degradation such as PWSCC. These sections would also determine if the PT indication on the wetted surface was connected to the void on the EDM surface. An extended dwell fluorescent penetrant test was performed on the cut and wetted surfaces of piece C and piece E/F. A one-hour dwell time was used. The purpose of this test was to determine if additional indications might be located adjacent to the large bleed out. Both pieces did not show any evidence of cracking or other linear indications.

Fig. 5.162 RPV head. CEDM #64, photographs of the boat sample after sectioning. Note: cut #5 was made after performing an extended dwell (1 h) penetrant test on piece E/F

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351

Piece D was radiographed with the source normal to the cut surfaces to determine the depth of the void below the wetted surface. The void extended *400 µm (16 mils) below the wetted surface. Pieces A through F were mounted in clear epoxy mounting compound, ground, and polished using standard laboratory techniques. Wet grinding was accomplished through 600 grit sandpaper followed by polishing with 3 lm diamond suspension and 0.05 lm alumina. A 5% electrolytic nital etch (*9 VDCfor *30 s) was used to reveal the material microstructure. SEM/EDS examinations were performed on the specimens in the as-polished condition; carbon coating was used to improve specimen conductivity. All samples were examined by stereo microscopy, optical metallography, and SEM/EDS. Sequential grinding was done through the EDM void on piece A and the wetted surface PT indication on piece D. One face was ground and polished for the other four mounts. Piece A The first polished face on this specimen did not breach the EDM void. Figure 5.163 presents optical micrographs of the void after chemical etching. The elongated features emanating from the void were wide and did not appear to be cracks. There was a small crack at the EDM surface, but this was likely a result of the boat sample extraction. An interesting feature was identified on the wetted surface of specimen A (Fig. 5.164). This feature extended 25 µm (1 mil) below the surface and was not connected to the wetted surface in the examination plane. EDS dot maps were collected from this area. There was no evidence of manganese enrichment near the discontinuity faces as would be expected for hot cracking. The bulk material contained primarily chromium, nickel, and iron as expected; small amounts of aluminum, carbon, oxygen, and silicon were detected inside the discontinuity. These elements likely originated from the mounting and polishing compounds. This area was also examined optically after lightly grinding and

400 µm

100 µm

Fig. 5.163 RPV head. CEDM #64, piece A, high magnification optical micrographs of the EDM surface void after electrolytic etch with 5% nital. The elongations were wide and did not appear to be cracks. There was no evidence of cracking on the EDM or wetted surface

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Nickel Base Alloys

Fig. 5.164 RPV head. CEDM #64, SEMmicrographs showing linear indications near the wetted surface of cross section piece A. These indications extended *25 µm (1 mil) deep below the wetted surface; they were not connected to the wetted surface in this plane (left: BSE, right: SE)

polishing to remove the carbon coating. The discontinuity was located within the surface cold-worked layer and show evidence of folded metal above and below the defect, which indicate this feature is an artifact of prior grinding. There was no evidence to support environmental cracking. Piece B Piece B cross section contained multiple weld passes. There was no evidence of cracking observed in this cross section. The sample was lightly ground and polished to remove the etched layer prior to SEM/EDS analysis. The nozzle material was consistent with Alloy 600; both weld regions were generally consistent with Alloy 52, although chromium dilution was evident in the weld bead near the nozzle. A shallow void was located at the wetted surface as shown in Fig. 5.165. This void extended *300 µm (12 mils) below the wetted surface and was covered by a thin ligament of weld metal.

Fig. 5.165 RPV head. CEDM #64, high magnification SEMmicrographs showing a shallow void covered by a thin ligament of weld metal on the wetted surface of cross section piece B. This void extended *300 µm (12 mils) below the wetted surface (linear feature is a sample preparation artifact). Left: BSE, right: SE

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Fig. 5.166 RPV head. CEDM #64, SEMmicrographs taken near the EDM surface of cross section piece C showing linear indications in the nozzle material and two areas selected for EDS. It appeared that the indications were associated with the EDM process, not in-service cracking. Indications measured *100 µm (4 mils) in length (left: BSE, right: SE)

Piece C Piece C cross section contained multiple weld passes. There was no evidence of cracking observed in this cross section. The sample was lightly ground and polished to remove the etched layer prior to SEM/EDS analysis. Short linear indications measuring *100 µm (4 mils) long were observed on the EDM surface (Fig. 5.166). These indications appeared to be associated with the EDM process, not in-service cracking. Piece D The first face of this cross section did not breach the PT void. A low magnification stereo microscope photograph of face #2 after etching is presented in Fig. 5.167. The boat sample extended approximately 3 mm (0.12``) deep into the nozzle in this plane. Multiple weld passes were evident in this area. The PT indication is shown at higher magnification. The void was barely breached. Progressively higher magnification SEMmicrographs of the void are presented in Fig. 5.168. These micrographs highlight a crack in a thin ligament covering the void. The curved morphology and lack of branching indicated this crack was not a result of in-service environmental cracking. Piece E Piece E wetted surface shows evidence of surface grinding over approximately 50 µm (2 mils) deep. Piece F An interesting feature was noted on the wetted surface of piece F (Fig. 5.169). This indication extended approximately 300 µm (12 mils) below the wetted surface. There was no cracking associated with this feature.

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Nickel Base Alloys

500 µm

~3 mm (0.12") 2 mm

J-weld Nozzle

Fig. 5.167 RPV head, CEDM #64, low magnification photograph showing face #2 of piece D. Multiple weld passes are present. The boat sample included *3 mm (0.12'') of the nozzle wall thickness. Electrolytic 5% nital etch

Fig. 5.168 RPV head, CEDM #64, piece E, SE micrographs taken of PT indication region. Arrow indicates a crack in the thin ligament covering the weld void. Higher magnification SE micrograph shows a crack in the thin ligament. The general curved morphology of this crack suggested it was not due to in-service cracking. The crack appears to be unbranched

5.2 Destructive Examinations Related to Reactor Pressure Vessel … Fig. 5.169 RPV head, CEDM #64, as-polished micrograph of specimen F wetted surface. This area appeared to contain a weld void that was subsequently filled with weld metal

355

100 µm

Conclusion, remedial action In conclusion, the boat sample did not show any indication of in-service environmentally induced cracking. Following the boat sample extraction, the plant could restart with the regulator’s approval. This DE result supports the good field behaviour of Alloy 52 and does not jeopardize the extended inspection intervals of some 30% Cr alloys as compared to 15% Cr Alloys.

5.2.14 Leak of a Reactor Pressure Vessel Head Vent Nozzle at a KHIC-CE Unit ([PRI-10–02, 2010]) Plant’s main characteristics: KHIC-CE PWR, 1050 MWe, 2 hot legs, 4 cold legs, Korea. Equipment/Component: reactor pressure vessel head, vent line, nozzle (Fig. 5.170). Failure discovery: while implementing the visual inspection of the reactor vessel penetration lines on February 25, 2010, an indication of boric acid leakage was identified at the reactor vessel head vent nozzle. Upon investigation, two small axial cracks were identified on the vent nozzle. The amount of boric acid leakage was evaluated and estimated to be 31.8 L (10 gallons) which had leaked inside containment. The radiation monitor and air contamination of the containment building did not detect this leakage, thus, the radiation effect due to the RCS leakage was negligible. Operating conditions: the nozzle is at the vessel head temperature.

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Nickel Base Alloys

Fig. 5.170 Left: cross-section of the reactor pressure vessel head; right: top view of the head

Time of operation: 15 years, 12th refuelling outage. Similar event frequency: at least one similar event occurred at another CE unit but in the US. During a refuelling outage inspection, two axial indications (cracks) have been detected using a rotating pancake coil (ET) on the vessel head vent nozzle of this unit. The cracks were approximately 5 mm (0.2″) long and approximately 0.5– 0.75 mm (20–30 mils) deep (difficult to measure). These cracks were in the same location as where cracks were machined during the previous outage. They appear to have re-initiated and have slowly grown over one cycle. However, eddy current data from the previous outage showed that the indications were removed. Specimen/sample characteristics: no sample was taken; only non-destructive testing was performed on the vent nozzle (Fig. 5.171). DE goal: leak root cause analysis. Results Various non-destructive techniques were implemented: visual examination, eddy current test, dye penetrant test and ultrasonic test to know more about the two axial cracks responsible for the leakage. Fig. 5.171 Sketch of the vent nozzle installation in the reactor pressure vessel head

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Fig. 5.172 View of the boric acid deposits resulting from the vent nozzle leak

Fig. 5.173 Shape and dimensions of the two axial cracks responsible for the reactor pressure vessel head vent nozzle leak

Visual examination showed the presence of boric acid deposits not only on the leaking vent nozzle but also the presence of white “rivers” on the top of the head (Fig. 5.172). The other non-destructive techniques allowed to determinate the location, shape and dimensions of the two axial cracks (Fig. 5.173). The two cracks are through wall, one is 22.6 mm (0.89″) long, the other 25.9 mm (1.02″) long. They initiated and propagated in the vent nozzle Alloy 600 base metal. The nozzle started to leak when one of these cracks reached the bottom of the nozzle-head annulus. The stain and precipitation of boric acid were removed to check for the integrity of the reactor vessel head base metal. This integrity was confirmed. Based on previous experience, the two axial cracks were assumed to be from PWSCC. Conclusion, remedial action The leak was due to two PWSCC through wall axial cracks that initiated and propagated in the nozzle base metal. The Alloy 600 based nozzle was replaced with an Alloy 690 based nozzle and the integrity of the weld was verified (Fig. 5.174). Additionally, the integrity of the weld was scheduled to be confirmed by a later leak test.

358

5

Nickel Base Alloys

Fig. 5.174 Repair of the leaking reactor pressure vessel vent nozzle

5.3 5.3.1

X-750 Field Experience Destructive Examinations of X-750 Split Pins—Results and Remediation

Plant’s main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: Reactor upper internals, RCCAs guide tubes, split pins (Figs. 5.175 and 5.176). The split pins are made of Alloy X-750. This alloy was originally developed as a precipitation-hardened high nickel alloy for high temperature applications. This alloy has been applied to various core component fabrications (springs, pins…) because of its good properties regarding stress relaxation resistance, its high YS and its superior corrosion resistance. The locking bar and the lock cap are made of AFNOR Z2 CN 18.10 (similar to 304 L), the locking bar is welded with AFNOR Z2 CNS 20.10 (similar to 308L). Failure discovery: in the absence of inspection, operators can be warned of split pins failures by loose parts generation (Fig. 5.177). However, rather early in time, split pins inspection programs have been launched by PWR operators around the world. Operating conditions: primary water, 155 bars, 325 °C (617°F). Time of operation: from 8,000 to 47,100 h for the first and second generations, 25 calendar years for the third generation examined here. Similar event frequency: the first split pins cracking event was reported in Japan as early as 1978. Cracked split pins are observed in France for the first time in January 1982 and in the US in March of the same year. Since then, all early PWRs (from the 70’s and the 80’s) have replaced their original split pins. Moreover, some plants have replaced split pins more than once.

5.3 X-750 Field Experience

359

RCCA guide tube (continuous guiding section)

Core upper plate

Split pin, see detail Figure 5-176

Fig. 5.175 Reactor upper internals. Location of split pins (white arrow)

360

5

Nickel Base Alloys

Split pin

View from under the RCCA guide tube lower flange

Fig. 5.176 Reactor upper internals. Location of split pins (detail of Fig. 5.175)

(First) Threads cracking

Welded locking bar Lock cap

Lock cap

Potential loose parts Nut

Shank/ flange radius cracking

Leaves cracking

Potential loose part

Fig. 5.177 Reactor upper internals. Typical locations of split pins cracks

Potential loose part

5.3 X-750 Field Experience

361

Specimen/sample characteristics: over the years, several generations of split pins have been installed in EDF reactors: first generation (started cracking in 1982), second generation (started cracking in 1987), third generation (cracking of the split pins supplied by one particular vendor after 30,000 h of operation), fourth generation, fifth generation: NG89 (Fig. 5.178). This DEs summary relates to the failures of the first and second split pins generations (Table 5.7).

Second generation type split pin

NG89 generation type split pin

RCCA guide tube lower flange

Upper core plate

Fig. 5.178 Reactor upper internals. Split pins. Comparison between second (left) and NG89 generations (right)

Circular

Parabolic

(continued)

Rolled, short pitch. Diameter: 16 mm, pitch: 1.5 mm. 3 less threads

Shot peening of shank/flange radius and leaves

After final heat treatment

1095 °C, 1 h, WQ+704 °C, 20 h, AC. Maximum YS=900 MPa

1095 °C, 1 h, WQ+704 °C, 20 h, AC. Maximum YS=900 MPa

06/89 to 08/96

NG89

5

14.00 mm

12.95 mm

Shank diameter Shank/ flange radius shape

Flange Split Threads

Surface treatment

Machining

Material Annealing thermal treatment Ageing thermal treatment

Fourth generation

02/1983 to 03/ 08/84 to 04/92 08/88 to 01/92 1985 Inconel® X-750 (AFNOR NC 15 Fe 7 TNbA) 1095 °C, 1 h, WQ+704 °C, A: 1150 °C, 2 h, AC D1: 1095 °C, 1 h, 1095 °C, 1 h, AC+ AC 704 °C, 20 h, AC 20 h, AC. Maximum YS= B: 885 °C, 24 h, AC 900 MPa D0: 982 °C, 0.5 h, AC A: 15% CW+840 °C, 1095 °C, 1 h, WQ+704 °C, D1: 704 °C, 20 h, 1095 °C, 1 h, AC+ 14 h, AC+720 °C, 16 h, AC 704 °C, 20 h, AC 20 h, AC. Maximum YS= AC 900 MPa B: 700 °C, 20 h, AC D0: 732 °C, 8 h, AC+ 620 °C, 6 h, AC Either before (rolled threads) or after (machined threads) the final After final heat treatment hardening TT, depending on the vendor None None Polishing of shank/ Cold rolling of shank/flange flange radius and radius and leaves leaves Machined Machined Electrode Discharge Machining (a few early second generation machined) Rolled or machined, depending on the vendor. Diameter: 15.9 mm, Rolled, short pitch. Diameter: pitch: 2.3 mm 16 mm, pitch: 1.5 mm

Third generation

Origin

Installation

Second generation

First generation

Parameter

Table 5.7 Reactor upper internals. Split pins generations characteristics (AC=Air Cooling, WQ: water quenched)

362 Nickel Base Alloys

0.98 YS15 for “resh” deposits and 300). The maximum depth is 30% of the wall thickness. The crack propagation is either intergranular or transgranular, depending on the zone investigated. These cracks are PWSCC of non-sensitized, but cold-worked stainless steel.

9.8.4

Laboratory Analysis of a Leaking Letdown Cooler (Hyres et al. 2017)

Plant main characteristics: B&W PWR, 900 MWe, 2 hot legs and 4 cold legs, USA. Equipment/Component: the 3A letdown cooler is a compact counter flow heat exchanger having a Helicoil tube bundle design consisting of 30 seamless Type 316L stainless steel tubes, each having a 19 mm (0.750 in) OD and 1.8 mm (0.072 in) wall thickness, and measuring approximately 18 m (60 feet) long. The tubes were procured in the solution annealed condition, i.e. heated at 1038 °C (1900°F) followed by rapid quenching to below 427 °C (800°F) in less than 3 min. When rolled into the bundle, each tube contains approximately nine 9 coils. Once coiled,

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the entire tube bundle is stress relieved at 1093 °C (2000°F) for 32 min, followed by rapid cooling to below 427 °C (800°F). Each tube is tack-welded to a support bar on the inlet and outlet ends, and then formed at a 90° angle toward the inlet and outlet tubesheets. The tubes are roll expanded (2–5% wall reduction) nominally 3.8 cm (1.5 in) into the 4.8 cm (1.88 in) thick tubesheets and then seal welded. The bundle is encased within a 13 mm (0.5 in) thick carbon steel shell containing inlet and outlet ports for the primary and secondary fluids. Primary inlet flow (RCS) is from the centre of the bundle outward. Secondary side cooling water (Component Cooling) flows in the opposite direction, from the outer periphery of the cooler, spiralling inward toward the centre. The cooling water exits the central cavity through the outlet nozzle located on the same side as the inlet nozzle. Operating conditions: RCS letdown fluid enters the tubes nominally at 14.9 MPa (2155 psig) and 291 °C (555°F). Treated Component Cooling water flows on the shell side. The operating conditions on the shell side of the letdown cooler are 71 ° C (160°F) measured at the cooler outlet and 0.48–0.62 MPa (70–90 psia) (pressure estimated in the cooler), which corresponds to a saturation temperature of 149– 160 °C (300–320°F). The RCS temperature is 291 °C (555°F) at the cooler inlet and decreases as the fluid cools as it passes through the tubes. Localized boiling of the Component Cooling water (producing some superheated steam) occurs on the tube surface at the RCS inlet end of the letdown cooler where both the RCS temperature and the OD of the tube wall equal or exceed the saturation temperature at the shell side operating pressure. In this respect, letdown cooler design operating conditions in the B&W NSSS differ from other PWR and even BWR designs that have stepwise cooling and pressure reduction of the letdown water via a regenerative heat exchanger in order to prevent localized boiling conditions from occurring. From 1994, when the 3A letdown cooler went into service, until April 2003, the secondary side Component Cooling water chemistry was potassium chromate (100– 500 ppm as CrO4), sodium phosphate (100–300 µg/L as PO4), and pH *10. In May 2003, chromate chemistry was replaced with molybdate (500–1000 µg/L MoO4)-azole (tolyltriazole) chemistry at pH 9.0–11. Makeup water to the Component Cooling system is high purity demineralized water. After the letdown cooler leak developed, boric acid from RCS in-leakage was introduced into the Component Cooling water (secondary side) system until the leaking cooler was removed from service. The Component Cooling system operates at a lower pressure than the raw water system, which acts as its heat sink. Time of operation: 12 years. Failure discovery: due to the recent poor reliability of the letdown coolers at Oconee and since no letdown cooler from any B&W plant had been destructively examined since 1987, it was decided to destructively examine the archived Oconee 3A letdown cooler which had a known leak in order to determine the cause of the tube failure. Leakage was discovered in the 3A letdown cooler in July 2003. This

1100

9

Stress Corrosion Cracking of Stainless …

letdown cooler was in service from 1994 until the EOC 22 Refuelling Outage in spring 2006, when it was removed and replaced with another cooler. Similar event frequency: forty-two failures of letdown coolers have occurred in B&W plants since 1977. Of these, 27 (or 64%) of the failures have occurred at the Oconee plants. OD-initiated high cycle fatigue at tube-to-tube stitch welds was identified as the cause of early failures by the destructive examination of letdown coolers from Crystal River-3 and Three Mile Island-1. A number of recommendations were developed and implemented at B&W plants to minimize or prevent additional tube failures by high cycle fatigue. For a while these recommendations appeared to be effective. Oconee reported no letdown cooler failures between 1997 and 2003. However, failures reoccurred from 2003 to 2014. Similar letdown coolers are in service at Davis-Besse and ANO-1. ANO-1 has experienced no failures to date; Davis-Besse reported a cooler failure in 2009. The cause of failure was not determined, but assumed to be due to high cycle fatigue. Specimen/sample characteristics: Fig. 9.277 is a receipt photograph taken of the cooler showing the primary side inlet and outlet manifolds. DE goal and program: leak root cause analysis. Results The tubes were dewatered prior to pressure testing, and then each tube was individually pressure tested with 206 kPa (30 psi) helium for *15 min to identify leaking tubes. One tube, identified as Tube #17 in the laboratory, failed the pressure test. The shell side was also pressurized with 206 kPa (30 psi) of helium. Soap

Fig. 9.277 Receipt photograph showing the primary flow seal side of the letdown cooler. The primary inlet (near center) and outlet (toward bottom) manifolds are visible

9.8 Heat Exchangers, Heaters—Destructive Examinations Results and Remediation

1101

bubbles were used to check the integrity of each tube, the tubesheet seal welds, and the weld joining the tubesheet to the shell wall. This test also confirmed the leak in Tube #17. No other leaks were identified. The letdown cooler shell was cut just above the primary side end plate and then removed to access the tube bundle. Figure 9.278 shows the tube bundle and its central cavity. White-to-brown deposits were found on the tubes in the tight radius region on the inlet ends. The deposits were most heavily concentrated on the tube intrados, which corresponds to the underside (i.e., 6:00 position) of the tubes in-service. Few or no deposits were present on the tube extrados. The leak in Tube #17 was located in the deposit-covered region of the tubes as indicated in Fig. 9.278 right. Evidence of heat tinting was also found near the tight radius area of the tube bundle corresponding to the Tube #17 leak location (Fig. 9.279). Visual examination of the OD surface of the 5.1 cm (2 in) section of Tube #17 revealed three circumferential cracks in the tube intrados (see Fig. 9.280). Visual examination under higher magnification revealed the cracking to be jagged with a minor branch at one tip of the through-wall crack (see Fig. 9.281 left). IGA-like features were also found on the OD surface at the opposite end of the crack. This finding indicated corrosion was associated with the cracking, which likely initiated on the tube surface exposed to the Component Cooling water (see Fig. 9.281 right).

Fig. 9.278 Left: the letdown cooler after shell removal. The cut location to isolate the tubes is indicated. Middle: the central cavity near the inlet side of the tube bundle. The tube #17 leak location is indicated. Right: higher magnification view of the tube #17 leak location. Cut locations for the destructive examinations are indicated

Fig. 9.279 Left: view of the primary flow seal after removing the tubes. Right: higher magnification view of the tight radius region showing the most pronounced heat tinting

1102

9

Stress Corrosion Cracking of Stainless …

Fig. 9.280 Left: initial cuts to isolate the through-wall crack region. Right: resulting piece as viewed from the tube #17 intrados. Three cracks were visible in this area

Fig. 9.281 Left: higher magnification view of the tube #17 cracks. Right: IGA-like features were observed at one of the crack tips

Fig. 9.282 Left: photograph taken after cutting the piece open clamshell-style to reveal the ID surface. The through-wall crack location is indicated. Middle: higher magnification view of the through-wall leak location. Right: photograph showing the additional sections made through the leak location

The tube section was cut open clamshell-style to permit visual examination of the ID surface (see Fig. 9.282 left). One crack was found (see Fig. 9.282 middle), which was the through-wall leak identified during pressure testing. Cuts were then made through the cracked region in order to produce a through-wall open crack specimen and two metallographic mounts, one through the through-wall crack tip and one through a secondary crack (see Fig. 9.282 right).

9.8 Heat Exchangers, Heaters—Destructive Examinations Results and Remediation

1103

Fig. 9.283 Left: photograph of the opened through-wall crack. Cracking is intergranular in nature. Right: SEM image of the opened crack taken near the tube ID surface

Fig. 9.284 SEM image of the opened crack. Left: mid-wall region. Right: near the tube OD surface

Low magnification optical microscopy and low magnification SEM both revealed that the through-wall cracking was intergranular from OD to ID (see Figs. 9.283 and 9.284). Pitted features on many grain facets indicated corrosive attack occurred at some point after the crack formed. Secondary cracking was also noted in several locations, a characteristic typical of stress corrosion cracking in austenitic stainless steels. EDS analysis of the heavily deposited region on the opened fracture surface showed the deposits were composed of major amounts of O, Cr, Fe, and Ni, with minor amounts of Mo, and trace amounts of Si, Ti, Cu, Zn, and Sn. No evidence of deleterious soluble species such as chloride was found in the areas examined. It should be noted that the escaping fluid through the crack would likely remove deposited soluble species from the crack surfaces. Deposits collected from the OD surface of Tube #17 in the through-wall crack region were affixed to a specimen stub using double-sided carbon tape. EDS analyses of regions of interest found that the deposits consisted of major amounts of

1104

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Stress Corrosion Cracking of Stainless …

Fig. 9.285 Left: micrograph of the cross section prepared through the tube #17 through-wall crack tip. OD surface is along top edge. Electrolytic 10% oxalic etch. Right: same area using Differential Interference Contrast illumination

O and Ca, with minor amounts of Mg, Si, P, Fe, Cu, Zn, and Ba, along and trace amounts of Al, Cr, Ni, and Cu. The presence of Mg, Ca, and Si indicated in-leakage of raw water into the Component Cooling water system. The presence of phosphorus in the deposits was consistent with deposition occurring during the time period that CrO4–PO4 chemistry was employed. Barium was also identified during the 1987 letdown cooler examination. A definitive source for the barium and its potential impact on the tube cracking could not be conclusively determined. The through-wall crack tip region exhibited a few branches, but was generally straight and unbranched for much of its length (see Fig. 9.285). Secondary cracking was noted on the OD surface as well. Intergranular cracking and branching are evident near the OD, but the latter half of the crack was clearly straight and transgranular. There was also evidence of cold work on the OD surface, as evidenced by the presence of disturbed grains in this area. The cross section of a secondary crack in Tube #17, observed after ASTM A 262 etching, indicates that the material microstructure is non-sensitized. Vickers microhardness (100 g load) traverses were taken on the polished cross section prepared from Tube #17. An OD-to-ID traverse indicated elevated hardness near the OD surface (285 HV) due to surface cold work. The bulk hardness for tube #17 was approximately 150–160 HV, compared to 140–150 HV for the other the other tubes tested. Elevated hardness generally increases a material’s susceptibility to SCC. The XRD results for the heavy tube deposits indicated they were largely composed of calcium phosphate, Ca3(PO4)2, with lesser amounts of tri-calcium silicate, Ca3SiO5, and silica, SiO2. The source of the phosphate is the sodium phosphate added for pH buffering of the Component Cooling water during the time period that potassium chromate was used as a corrosion inhibitor in the system. In-leakage of raw water into the Component Cooling water is the only plausible source of Ca, Mg, and Si. A review of historical Component Cooling water system chemistry data did reveal specific raw water in-leakage events via Component Cooler tube leaks

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1105

that occurred after the 3A letdown cooler was removed from service in 2006; however, no specific leak events were found in the reported chemistry data for the time period that the letdown cooler was in service. Tube-to-tubesheet joint leakage of the Component Coolers (the joints are not seal welded) is therefore the likely chronic source of Ca, Mg, and Si by low level raw water in-leakage. Conclusions, Remedial Actions A stress-relieved Type 316L stainless steel tube in the 3A letdown cooler developed a through-wall leak most likely due to OD-initiated caustic stress corrosion cracking based on the laboratory analyses. The through-wall cracking was intergranular in nature and developed within a heavily deposited region of the tube that experienced the highest operating temperatures and localized boiling of the Component Cooling water at the OD surface. Highly caustic conditions were created in the region of localized boiling when caustic forming impurities (Ca, Mg) entered the Component Cooling water via raw water in-leakage. Calcium combined with the phosphate, being used for pH buffering at the time, to form calcium phosphate deposits where boiling occurred. Other raw water impurities formed deposits such as tri-calcium silicate and silica in the boiling region. The occurrence of caustic SCC of austenitic stainless-steel tubing under these conditions is consistent with the literature, which indicates that caustic conditions approaching 20% and higher are favourable for SCC and IGA. Elevated hardness levels present at the tube OD due to surface cold work increased the tube’s susceptibility to SCC. Remedial measures developed from this work and implemented at the plant were: (1) to maintain a minimum concentration of borate in the Component Cooling water in order to buffer the pH and prevent caustic conditions from occurring in the region of localized boiling and (2) to lower the control limit for chloride in order to more quickly prompt action to isolate and repair leaks, since an increasing chloride concentration in the Component Cooling water would be indicative of significant raw water in-leakage into the system. It was also recommended that: (1) the tubesheets of the Component Coolers be coated in order to mitigate raw water in-leakage through tube-to-tubesheet joints and (2) the tubing material for future replacement letdown coolers be changed from Type 316L to an alloy that contains at least 30% nickel by weight to prevent caustic SCC.

References François Cattant, Materials Ageing in Light Water Reactors – Handbook of Destructive Assays, Lavoisier Editions, February 2014. Gordon, B.M. Materials performances, page 29, April 1980. Compilation of results obtained between 200°C (392°F) and 300°C (572°F), 1980.

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Stress Corrosion Cracking of Stainless …

Hongqing Xu, Steve Fyfitch, Ryan Hosler, and James Hyres, Laboratory investigation of a leaking type 316 socket weld in a boron injection tank sampling line, 15th International Conference on Environmental Degradation, Edited by: Jeremy T. Busby, Gabriel Ilevbare and Peter Andresen, TMS (The Minerals, Metals & Materials Society), 2011. James W. Hyres, Paul Deeds, Rick Tiffany, Paul Deniston, Richard E. Smith, George Licina, Peter Riccardella, and David Alley, Laboratory analysis of a leaking CRDM housing from Palisades, 16th International Conference on Environmental Degradation of Materials in Nuclear Power Systems – Water Reactors, Ashville, North Carolina, USA, August 11–15, 2013. James Hyres, Ben Williams, Richard Smith, Sontra Yim and David Alley, Laboratory analysis of cracked CRDM housing from Palisades, 17th International conference on Environmental Degradation of Materials in Nuclear Power Systems ‒ Water reactors, Ottawa, Ontario, Canada, August 9–13, 2015. James Hyres, Rocky Thompson and Jim Batton, Laboratory Analysis of a Leaking Letdown Cooler from Oconee Unit 3, 18th International Conference on Environmental Degradation of Materials in Nuclear Power Systems – Water Reactors, Portland, Oregon, USA, August 13–17, 2017. Michael Sullivan and James Hyres, Laboratory analysis of reactor coolant pump seals, 15th International Conference on Environmental Degradation, Edited by: Jeremy T. Busby, Gabriel Ilevbare and Peter Andresesn, TMS (The Minerals, Metals & Materials Society), 2011. Michael R. Ickes, Stress Corrosion Cracking of an Austenitic Stainless-Steel Pipe Weld, 19th International Conference on Environmental Degradation of Materials in Nuclear Power Systems – Water Reactors, Boston, Massachusetts, USA, August 18–22, 2019. Ryan Hosler, Beverly Cyrus, Steve Fyfitch and Trent Henline, Davis Besse Small Bore Class 1 Piping Socket Weld Destructive Examination, EPRI International Light Water Reactor Materials Reliability Conference and Exhibition, August 1–4, 2016.

Chapter 10

Rupture and Stress Corrosion Cracking of Martensitic Stainless Steel

10.1

Background

Martensitic stainless steels are used when high corrosion resistance and high mechanical properties are both required. However, martensitic stainless steels, when aged or when not properly thermally treated can fail under stress corrosion cracking as shown in the following few examples.

10.2

Destructive Examination Results and Remediation

10.2.1 Destructive Examination of an Aged Pressurizer Valve Stem Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: RCS, pressurizer, stem of the spray valve RCP 201 VP. The stem is made of Z6 CNU 17.04 (17.4 PH). This material can age at high temperature. Operating conditions: temperature ranging from 293 °C (559°F) to 329 °C (624°F). Time of operation: 9,500 h for the stem and 46,138 h for the valve body. Failure discovery: because of a major leak of the packing of the RCP 201 VP valve (1,000 l/h, 4.4 gpm) and in order to keep the reactor operating, the valve was closed with the stem set in back seat position. The closing torque was 14 m.kg. At the following outage, this stem was replaced and sent to the hot laboratory at Chinon for condition assessment.

© Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_10

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1108

Similar event frequency: several components made of 17.4 PH® martensitic steels (or similar) have failed in nuclear reactors, either from mechanical fracture or from SCC. DE program and goal: assessment of the valve stem condition. Checking for the absence of deterioration following the sequence of operation in back seat position. The DE program consisted in mechanical testing: impact test and hardness measurements. Results Impact test The specimens have been machined from the valve stem as shown on Fig. 10.1: • 4 specimens (R2A1 to R2A4) have been taken in the area not experiencing a high temperature in operation (stem top); • 4 specimens (R2A5 to R2A8) come from the stem area operating at high temperature (stem bottom) in order to see whether some ageing occurred in service. The specimens are of KCV type. The specified test temperature was 0 °C (32°F) and 3 specimens of each stem end were tested at this temperature. However, given the low fracture energy found, the 2 last specimens (one from each stem end) were tested at room temperature. The results, along with the RCC-M code specification are reported in the Table 10.1.

Hardness measurements (HV30) Impact test specimen R2A1 Impact test specimen R2A3

Impact test specimen R2A2 Impact test specimen R2A4

Impact test specimen R2A5

Impact test specimen R2A6

Impact test specimen R2A7

Impact test specimen R2A8 Hardness measurements (HV30)

Fig. 10.1 Pressurizer spray valve stem. Localization of the mechanical testing specimens

10.2

Destructive Examination Results and Remediation

1109

Table 10.1 Pressurizer spray valve stem. Impact tests results Temperature (°C/°F)

Code

Energy (daJ)

KCV (daJ/ cm2)

Mean KCV (daJ/cm2)

Minimum KCV at 0 °C (32°F) 7.5 – according to the code (RCC-M) Top end of the stem (low service temperature) 0/32 R2A1 5.7 7.1 6.9 0/32 R2A2 5.5 6.9 0/32 R2A3 5.3 6.6 Bottom end of the stem (high service temperature) 0/32 R2A6 3.3 4.1 4.1 0/32 R2A7 3.4 4.3 0/32 R2A8 3.0 3.8 Extra tests performed at room temperature 22/71.6 R2A4 6.9 8.6 20/68 R2A5 4.1 5.1

Standard deviation (daJ/cm2)

Brittle area (%)

Lateral expansion (mm)

–

–

0.64

0.25

30 40 50

0.69 0.38 0.49

0.25

80 90 90

0.33 0.38 0.32

45 70

0.62 0.51

Hardness Vickers hardness measurements have been carried out in order to supplement the impact tests results information and find out whether the material was aged because of phase a’ precipitation. The location of the measurements was: • In the upper end of the specimen R2A1 (area not operating at high temperature); • In the lower end of the specimen R2A8 (area operating at high temperature). The results are reported in the Table 10.2. No noticeable hardness difference is observed between the 2 zones, which mean no ageing by a’ phase precipitation occurred. Table 10.2 Pressurizer spray valve stem. Results of the hardness measurements

Specimen R2A1 (low service temperature)

Specimen R2A8 (high service temperature)

Area

d (mean)

HV30kgf

Mean hardness

Standard deviation

1 2 3 4 5 1 2 3 4 5

0.392 0.388 0.39 0.39 0.39 0.385 0.39 0.385 0.39 0.39

362 370 366 366 366 375 366 375 366 366

366

2.8

370

4.9

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10 Rupture and Stress Corrosion Cracking …

Conclusion, Remedial Action Although the hardness measurements show no difference between the top and the bottom of the stem, the lower end impact rupture energy is lower than the upper end energy. Moreover, the impact rupture energy of the stem lower end is less than the code RCC-M specification. Additional examinations have been launched to investigate this apparent discrepancy between impact test and hardness measurements results.

10.2.2 Destructive Examination of a Failed Reactor Cooling System Valve Stem Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: RCS hot leg, temperature measurement line, downstream isolating valve RCP 102 VP. This valve is open when the reactor operates and closed during outages. The valve stem is 28.6 mm (1.126’’) in diameter and made of Z6 CNU 17.04 (17–4 PH) martensitic SS (Fig. 10.2). Operating conditions: environment: primary water. Temperature: bottom end of the stem = 286 to 323 °C (545 to 613°F); top end = less than 100 °C (212°F). Time of operation: 118,700 h total but only around 84,000 h at high temperature (43,800 h at 323 °C (613°F), 3,200 h at 286 °C (545°F) and 37,000 h at around 300 °C (572°F)). Failure discovery: during the 1992 unit outage, the valve was closed. The RCS pressure was 25 bars and the temperature 85 °C (185°F). The following day, despite the valve was opened, the gate remained in place. Hence, the valve was dismantled and the lower end of the stem was found broken into 3 pieces. Similar event frequency: valve stem failures because of the material ageing are rare events. Specimen/sample characteristics: the 3 pieces of the valve stem were sent to the hot laboratory at Chinon for DE. DE program and goal: failure root cause analysis. The DE program included: VT, micrography, SEM, chemical analysis, hardness measurements and impact tests.

10.2

Destructive Examination Results and Remediation

1111

Valve stem

Broken area

Fig. 10.2 Drawing of the gate valve RCP 102 VP isolating the RCS hot leg temperature line. The location of the field cracking is indicated

Results VT Figure 10.3 shows an overview of the bottom end of the stem. The stem broke into 3 pieces. The fracture surface is rather plane and with little oxide. The surface of the

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10 Rupture and Stress Corrosion Cracking …

Fig. 10.3 Isolation valve of the RCS hot leg temperature line. View of the bottom end of the stem. Top: pictures showing the 3 pieces back in place. Photograph a: piece #1, view towards B direction; the black arrows point at mechanical/impacts damage. Photograph b: piece #3, view towards A direction. Photograph c: piece #2, view towards A direction. Photograph d: piece #2, view towards B direction

piece #1 presents some mechanical damage (impacts), likely resulting from the valve stem operation. No particular initiation zone is visible. Micrography A cross section of the piece #2 after etching is presented in Fig. 10.4. The examination of this section provides the following comments: • • • •

The main cracks surface is slightly oxidized; Some secondary cracks are visible, also slightly oxidized; All cracks are intergranular; The martensitic structure is as expected for this type of steel.

10.2

Destructive Examination Results and Remediation

1113

2 mm

Vue towards B direction

Vue towards A direction α β

200 µm

100 µm

100 µm

γ

δ

ε

50 µm

Fig. 10.4 Isolation valve of the RCS hot leg temperature line. a: CC cross section (see location on Fig. 10.3) of piece #2. b: zone 1 detail. c: zone 2 detail. d: zone 3 detail. e: zone 4 detail. Villèla etching

SEM Piece #3 was used for the SEM examination (Fig. 10.5). The rim of the specimen exhibits some mechanical damage (image b). The intergranular and slightly oxidized crack propagation is typical of brittle fracture (image c). However, some local limited ductile areas (image d), along with some small cleavage zones (image e), are visible all around the fracture surface.

1114

10 Rupture and Stress Corrosion Cracking …

Fig. 10.5 Isolation valve of the RCS hot leg temperature line. a: overview of the piece #3 (see location on Fig. 10.3). b: SEM view of some mechanical damage of the rim of the specimen. c: SEM image of the typical intergranular cracking. d: SEM picture of local ductile areas (pointed at by red arrows). e: SEM view of local cleavage areas

10.2

Destructive Examination Results and Remediation

1115

Chemical Analysis All element contents meet the 17–4 PH specification. The phosphorus content is 0.020 Wt%. Hardness Given 17–4 PH martensitic SS is prone to embrittlement, as a consequence of phase a’ precipitation at holding temperatures less than 400 °C (752°F), hardness measurements have been carried out. Vickers hardness under 30 kgf (66 pounds force) has been measured at the top end (specimen AB, see Fig. 10.6) and at the bottom end (CC cross section specimen, see Fig. 10.3) of the stem. The results show a significant difference between both ends (DHV = 79, from 377 HV30 at the top to 456 HV30 at the bottom), which is the evidence of the bottom end ageing. Moreover, the high hardness of the top of the stem indicates that this stem has been tempered either 4 h at 520 °C (968°F) or 2 h at 530 °C (986°F). However, at the time this unit was built, the actual code specification did not exist. The RCC-M 5110 code specification (edition 1988) requires a tempering treatment of 4 h between 595 (1,103) and 620 °C (1,148°F).

20

15

10

5

-80

0

280

0

280

100

50

Cracks -80

Fig. 10.6 Isolation valve of the RCS hot leg temperature line. Left: localization of the chemical analysis (DE specimen), hardness (AB specimen) and impact tests specimens into the valve stem; the B to F lines represent cross sections. Right: impact tests results. Top: fracture energy in daJ; bottom: brittleness in %

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10 Rupture and Stress Corrosion Cracking …

Discussion The stem brittle fracture results from service thermal ageing. Moreover, the intergranular nature of the fracture along with the likely low temperature tempering call for a dual ageing mechanism. The first mechanism is the precipitation of a’ phase in the tempered martensite during operation and the second mechanism is temper embrittlement. Segregation of phosphorus at grain boundaries is possible when the P content is around 200 ppm (like this stem) and when the temper treatment has been performed at low temperature. To check for the dual mechanism possibility, impact tests have been decided. For the 17–4 PH steel, EDF R&D has established an equation linking the shift of the Transition Temperature (TT, at 50% brittleness) to the hardness increase from the a’ phase precipitation: DTT ¼ 2:5DHV30 DTT = 2.5 DHV30 In the case of this broken stem, the shift of the initial Transition Temperature from the a’ phase precipitation would be DTTi = *200 °C. A shift of the TTi greater than 200 °C would indicate that the material not only aged from the a’ phase precipitation due to the long hold at high temperature but also underwent temper embrittlement from fabrication. Impact tests The following tests have been performed: • KCV tests on 6 specimens machined into the top end of the stem (Fig. 10.6), in the low temperature area to determine the initial transition temperature (DTTi) of the material; • KCV tests on 4 specimens machined into the bottom end of the stem (Fig. 10.6), in the high temperature area to determine the final transition temperature (DTTf) of the aged material. The tests should be performed at a temperature close to TTi + 200 °C (theoretical shift from the a’ phase precipitation only after the temperature hold). The tests results are presented in Fig. 10.6. In the first set of tests, the initial TT has been determined (temperature for which the rupture face is 50% brittle): 4 °C. It is noteworthy to mention that local intergranular rupture has been observed on the fracture surface (Fig. 10.7). In the second set of tests, the F1 specimen broken at a temperature close to TTi + 200 °C (= 210 °C) is 90% brittle (intergranular rupture, Fig. 10.8). Consequently, the temperature for the test of the second specimen (F2) was increased by 50 °C to 260 °C. Even at 260 °C, the rupture was still more than 50% brittle (Fig. 10.9). The final TT is therefore superior to 260 °C.

10.2

Destructive Examination Results and Remediation

1117

Fig. 10.7 Isolation valve of the RCS hot leg temperature line. Stem M2 KCV specimen. SEM images of the fracture surface of the specimen broken à −60 °C. Left: view of cleavage and ductile tearing. Right: intergranular features

Fig. 10.8 Isolation valve of the RCS hot leg temperature line. Stem F1 KCV specimen. SEM images of the fracture surface of the specimen broken à 210 °C. Presence of intergranular fracture and of some ductile tearing

Fig. 10.9 Isolation valve of the RCS hot leg temperature line. Stem F2 KCV specimen. SEM images of the fracture surface of the specimen broken à 260 °C. Presence of intergranular fracture and of some ductile tearing

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10 Rupture and Stress Corrosion Cracking …

Conclusion, Remedial Action The stem bottom end fracture resulted from a high load applied to a brittle 17–4 PH. Two mechanisms contributed to the material embrittlement: • a’ phase precipitation; • Temper embrittlement. The observation of a final ΔTT higher than the one expected from the original a’ precipitation can stem from two origins: • First, an extra temper embrittlement in operation, although rather observed at a higher temperature and • Second, rather more likely, a typical embrittlement synergistic effect as the bulk material hardening enhances the grain boundaries brittle behaviour.“ The 17–4 PH martensitic SS is still used for valve stems, however, its final heat treatment has been optimized and is now of 4 h at a temperature ranging from 595 (1,103) to 620 °C (1,148°F). With this thermal treatment, 17–4 PH ageing at PWR operating temperatures is dramatically decreased.

10.2.3 Destructive Examination of the 2SV-40 Pilot Valve Stem Plant main characteristics: Westinghouse, PWR,1,129 MWe, 4 loops, USA. Equipment/Component: stem of the pilot valve 2SV-40. The stem is made of type 410 SS. Operating conditions: the portion of the stem where the fracture occurred was not expected to bear a significant load. Due to the inverted orientation of the valve, condensation from any steam leaks would tend to accumulate around the pilot plug. Time of operation: 20 years. The valve had previously been rebuilt in 1991, although no parts were replaced at that time. Failure discovery: the pilot plug valve stem was found fractured on valve 2SV-40 during a scheduled maintenance. A steam leak was noted along the pilot plug seat (Fig. 10.10, right), and red iron oxide had accumulated at the base of the stem, beneath the spring (Fig. 10.10, left). Similar event frequency: valve stem failure is not uncommon in the nuclear industry. Specimen/sample characteristics: at the fracture location, the stem is 22.48 mm (0.885’’) in diameter. DE goal: failure root cause analysis.

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Destructive Examination Results and Remediation

1119

Fig. 10.10 Stem of the pilot valve 2SV-40. Left: fractured portion of valve stem. End of stem inside valve, where spring was located, is covered with powdery red deposits. Right: fractured valve stem as found in valve body. Small leak at pilot plug seat was evident

Results Fracture occurred just above the pilot plug seat. There was essentially no deformation associated with the fracture (Fig. 10.11, left). The fracture plane was normal to the stem axis. A small area of steam cutting was visible on the pilot plug (Fig. 10.11, right). The fracture surface was damaged from rubbing and was heavily oxidized, indicating that the fracture had been present for some time. Repeated cleanings in mild inhibited acid removed only a portion of the fracture deposits; the fracture was coarse and appeared granular (Fig. 10.12, left). No significant overstress area was evident. SEM exam showed the exposed portion of the fracture near the center to be entirely intergranular (Fig. 10.12, right). A random cross-section through the fracture showed the presence of an additional crack parallel to the fracture (Fig. 10.13). The crack path was intergranular, and the cracks were branched and filled with oxide. Along the OD surface, shallow

Fig. 10.11 Stem of the pilot valve 2SV-40. Left: detail of valve stem fracture. Fracture plane was immediately adjacent to radius at pilot plug. Gage = 1/16″. Right: detail of eroded site indicating a leak along the edge of the pilot plug seat

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10 Rupture and Stress Corrosion Cracking …

Fig. 10.12 Stem of the pilot valve 2SV-40. Left: coarse-textured fracture surface. Repeated cleanings removed only a portion of the heavy oxidation. Scale = 1/16″. Right: SEM photo of center of fracture showing an entirely intergranular morphology

Fig. 10.13 Stem of the pilot valve 2SV-40. Left: cross-section through fracture showing pitting corrosion along the OD surface. A second parallel crack is also present. Right: detail of intergranular crack path. Cracks are branched and filled with oxide

pitting and general corrosion were present at the edge of the primary crack (Fig. 10.13, left). The fracture itself was damaged from impact between the fractured ends. At the fracture, the valve stem had a hardness of Rockwell C44. Near the clean threaded end of the stem, the hardness was 42 HRC. It therefore appears that the valve stem was in a hard condition as installed. Qualitative EDS indicated the valve stem alloy to be a good match for Type 410 stainless steel (X12Cr13). Conclusion Fracture of the 2SV-40 pilot valve stem was attributed to SCC. Martensitic stainless steels are susceptible to SCC in moist environments when hardened to levels above

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Destructive Examination Results and Remediation

1121

30 HRC; at 42 HRC, this material was highly susceptible to SCC. This valve stem dated to the 1980s; a maximum hardness of 25 HRC is now recommended for 400-series stainless steels in valve stem applications. The primary crack and parallel crack were heavily oxidized and likely had a relatively slow growth rate. Cracking initiated at a site of general corrosion on the exterior of the stem, likely due to long-term exposure to condensation. The 400-series stainless steels with less than 13% chromium content, are not as corrosion resistant as the steels with higher chromium content of 400-series or 300-series stainless steels and are subject to superficial general corrosion. The surface corrosion near the pilot plug probably facilitated the initiation of SCC at that location. The steam leak at the pilot plug seat may have produced ambient moisture and contributed to this general corrosion.

10.2.4 Destructive Examination of a Rockwell Valve Stem Plant main characteristics: Framatome/Areva, PWR,1,300 MWe, 4 loops, France. Equipment/Component: main steam valves, stems referenced 1VVP111VV and 1VVP113VV. These stems are made of Z6 CNU 17.04, heat #HD029 for the stem 1VVP111VV and #N3188 for the stem 1VVP113VV. The fabrication records provide the following information: • Mill annealed at 1040 °C (1904°F) for 3h30 min, followed by air cooling; • Tempered at 595 °C (1103°F) for 4 h, followed by air cooling. These treatments match the RCCM 2007 specification, thus reverse temper embrittlement should not occur on this martensitic steel. Operating conditions: in operation, the valve is open, the fluid is steam at 70 bars (1015 PSI) and 290 °C (554°F). Time of operation: about 190,000 h (from plant start-up). Failure discovery: when operating the 1VVP111VV valve two tensile loads needed to be applied to the stem to unlock the gates (first load at 57.780 daN, second load at 74.900 daN). A visual examination following the dismantling of this valve revealed the stem was cracked. Similar event frequency: cracking of stems made of martensitic steel is not frequent but not uncommon. Specimen/sample characteristics: stems of 1VVP111VV and 1VVP113VV main steam pipes closure valves.

10 Rupture and Stress Corrosion Cracking …

1122

DE goal: valve stem 1VVP111VV failure root cause analysis. The sound valve stem 1VVP113VV has been provided for comparison (same operating history but not cracked). Results Visual Examination The visual examination of the 1VVP111VV stem reveals the presence of a crack located at the bottom of the stem (Fig. 10.14). This crack propagates through the tenon radius and through almost its whole thickness (Fig. 10.15). This examination also shows: • A colour difference between the stem top and bottom, due to different oxidation conditions: 290 °C (554°F) at the bottom and much cooler at the top; • Some hammering from operation, visible on the bearing zone of the tenon, this hammering is not uniform over the surface (Fig. 10.16 left); • At the stem top, shallow pits are visible at the packing location (Fig. 10.17).

Stem top

Fig. 10.14 Main steam valve stem 1VVP111VV, view upon reception

View 1

Specimen #1

Crack

Fig. 10.15 Main steam valve stem 1VVP111VV, view upon reception. Left: stem bottom. Right: detailed view of the crack

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Destructive Examination Results and Remediation

1123

B

Specimen #2

Downstream

Upstream

Fig. 10.16 Left: stem 1VVP111VV, tenon (foot), view from above. Right: stem 1VVP113VV (sound), tenon, view from above

The visual examination of the 1VVP113VV stem shows similar features: • Hammering of the bearing surface of the tenon (Fig. 10.16 right); • A colour gradient along the stem (Fig. 10.17 right). However, the stem 1VVP111VV looks darker, which means more severe operating conditions for the 1VVP111VV stem. Dimensions Measurements The tenon radius has been measured using 3D analysis (Fig. 10.18). The radius ranges from 1,465 to 1,912 µm (58 to 75 mils), which is consistent with the specification: 1,500 µm (59 mils). A local material upsetting is observed, as a consequence of operation. Similar material upsetting is observed on the 1VVP113VV stem.

10 Rupture and Stress Corrosion Cracking …

1124

Pits

Pits

Fig. 10.17 4 left pictures, stem 1VVP111VV. 4 right pictures: stem 1VVP113VV

10.2

Destructive Examination Results and Remediation

1125

Material upsetting

Fig. 10.18 Stem 1VVP111VV, tenon radius measurement

Hardness Measurements Hardness line scans have been performed on both stems (Fig. 10.19). The hardness is higher at the bottom. The hardness difference between the bottom and the top is 66 HV for the stem 1VVP111VV and 73 HV for the stem 1VVP113VV (Table 10.3). This significant difference results from a hardening of the bottom section of the stems after long holds at more than 250 °C.

HV30

HV30 line scans on stems 1VVP111VV (blue) and 1VVP113VV (red)

Stem bottom

Stem top

Distance from the stem bottom in mm

Fig. 10.19 Hardness measurements on 1VVP111VV and 1VVP113VV stems

10 Rupture and Stress Corrosion Cracking …

1126

Table 10.3 Summary of hardness measurements along the stems Hardness HV30

Stem 1VVP111VV (cracked)

Stem 1VVP113VV (sound)

Maximum at the bottom Maximum at the top Maximum ΔHV between bottom and top

436.5 370.5 66

423.5 350 73.5

SEM Examination The fracture surface examination reveals (Fig. 10.20): • No anomaly in the initiation zone (Fig. 10.21 left); • A brittle transgranular aspect with elongated cleaved bands, both in initiation and propagation zones (Fig. 10.21); • The laboratory fracture has also a brittle aspect. This shows how brittle this material is; without thermal ageing this material would evidence ductile fracture. This material has obviously been embrittled in operation.

Laboratory fracture

Hammered zone of the tenon bearing surface

Fig. 10.20 Stem 1VVP111VV. SEM view of the fracture surface after laboratory final rupture

10.2

Destructive Examination Results and Remediation

1127

Fig. 10.21 Stem 1VVP111VV. Detailed SEM views. Left: zone 2, initiation. Right: zone 4, propagation

Micrography A cross section of the stem 1VVP111VP crack shows: • An almost through wall crack in the plane of Fig. 10.22; • A martensitic stainless-steel structure; • The absence of bulk material anomaly. Some spots of d ferrite, elongated in the stem’s axis direction, are shown on Fig. 10.23. The 1VVP111VV stem (left picture) has less d ferrite than the stem 1VVP113VV (right picture).

Fig. 10.22 Stem 1VVP111VV, specimen #1 (see localisation on Fig. 10.15). Left: macrography of the crack. Right: micrography of the crack tip. Electrolytic nitric acid 50% etch

1128

10 Rupture and Stress Corrosion Cracking …

Fig. 10.23 Characterisation of the bulk d ferrite. Left: stem 1VVP111VV. Right: stem 1VVP113VV. Electrolytic KOH etch

Charpy V Impact tests The Table 10.4 shows: • For the stem 1VVP111VV: – A low fracture energy at the bottom (*5 J); – An energy gradient between the bottom and the top (*80 J), as the result of the bottom embrittlement in operation; • For the stem 1VVP113VV: – A low fracture energy at the bottom (*10 J); – An energy gradient between the bottom and the top (*30 J), as the result of the bottom embrittlement in operation.

Table 10.4 Charpy V impact test results (20 °C, 68°F) Fracture energy (Joules)

Stem 1VVP111VV

Stem 1VVP113VV

Stem top (3 specimens)

78 J ± 2 J 67 J ± 2 J 99 J ± 2 J 5J±4J 5J±4J 6J±4J

34 J ± 2 J 53 J ± 2 J 48 J ± 2 J 8J±4J 13 J ± 4 J 12 J ± 4 J

Stem bottom (3 specimens)

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Destructive Examination Results and Remediation

1129

Conclusion The failed stem exhibits a significant impact test difference between the bottom and the top (66 HV30), this translates in an increase of the mechanical properties at the bottom. The fracture is of brittle origin. The bearing surface of the tenon exhibits some hammering. This embrittlement results from thermal ageing of the material after a 190,000 h hold at 290 °C (554°F). The combination of high loads and a brittle material triggered crack initiation and propagation almost through all the material thickness. Cracking likely occurred when the valve was opened. Based on the examination of the two stems, a generic embrittlement issue cannot be ruled out.

10.2.5 Destructive Examination of a Shaft Sleeve from 1B Main Feedwater Pump Turbine Plant main characteristics: Westinghouse, PWR,1,129 MWe, 4 loops, USA. Equipment/Component: 1B main feedwater pump turbine, shaft sleeve. The CFPT is a Bingham Type CD pump. Both the inboard and outboard sleeves were specified to be AISI 440A SS steel (X60CrMo17), hardened to 450–525 BHN (approximately Rockwell C48-53). The sleeve keys are AISI 416 SS (X12CrS13) with no hardness specified. Operating conditions: secondary water. Time of operation: 18 years. Failure discovery: a steam leak occurred on the 1B Main Feedwater Pump Turbine (CFPT), resulting in a turbine runback. The outboard pump shaft seal sleeve was subsequently found to have fractured and to have worn severely due to contact with its bushing. Similar event frequency: in 1983, Bingham-Willamette began to substitute wrought Type 420 stainless steel (X20Cr13 – X30Cr13) for spun-cast Type 440A stainless steel wear rings and sleeves. The wrought material was hardened to the same level as the originally-specified spun-cast material. Several industry events occurred in the late 1980’s involving cracked shaft sleeves on Bingham auxiliary feedwater pumps, different models than the one relevant to this DE. In each case, the sleeve cracked axially at the keyway in an intergranular mode attributed to stress-corrosion cracking / hydrogen embrittlement. Each sleeve material was Type 420/440A wrought martensitic stainless steel hardened to approximately Rockwell C50. As a result of these failures, the vendor recommended that the material of those sleeves be changed to Type 410 stainless steel (X12Cr13) hardened to no

1130

10 Rupture and Stress Corrosion Cracking …

more than Rockwell C32 (300 BHN), and that the bushing material be changed to Ni-Resist Type 1 or 2. It was also recommended that the keyway radius be increased to 0.038″ (0.965 mm) and the interference fit be reduced. In May 1997, the inboard sleeve on a Bingham Type CD pump at another US plant fractured axially at the keyway. The failure was attributed to the sleeve being “extremely embrittled” and possibly improperly heat treated. Specimen/sample characteristics: the 2 sleeves were sent to the laboratory for DE (the inboard shaft seal sleeve was intact but was replaced as well). An unused sleeve from stock was also provided for examination. DE goal: failure root cause analysis. Results Examination of Failed Outboard Seeve The outboard bushing with the sleeve seized inside it is shown in Fig. 10.24, left. The end face of the sleeve was scribed 1,712,446. Short radial cracks were visible on the bushing end ring, likely a result of the overheating at failure. Metal on both the sleeve and bushing had been plowed, and the sleeve had gapped open inside the bushing about ½″ (13 mm) (Fig. 10.24, right, Fig. 10.25 and Fig. 10.26, left). The axial fracture incorporated one side of the internal keyway (Fig. 10.26, right). The sleeve material proved too hard to cut with a metal saw blade, so the assembly was torch cut axially in order to remove the sleeve. The external groove pattern on the sleeve had been entirely wiped away, save for two bands corresponding to channels in the bushing (Fig. 10.27). Fine cracks were visible throughout the smeared metal on the bushing interior, all likely heat-related. The sleeve fracture was nearly axial for about half its length,

Fig. 10.24 Main feedwater pump turbine, shaft sleeve. Left: outboard bushing as received, with sleeve welded inside it. Right: end view of bushing showing keyway end of sleeve. Keyway is filled with debris; see Fig. 10.25, right

10.2

Destructive Examination Results and Remediation

1131

Fig. 10.25 Main feedwater pump turbine, shaft sleeve. Left: end view of bushing showing gap at bottom end of sleeve, opposite keyway. Right: detail of end of keyway in failed sleeve, still inside bushing, filled with plowed metal

Fig. 10.26 Main feedwater pump turbine, shaft sleeve. Left: oblique view of failed sleeve inside bushing. Fracture at edge of keyway has gapped apart. Right: detail of the left image showing fracture of sleeve at keyway

Fig. 10.27 Main feedwater pump turbine, shaft sleeve. Left: exterior of failed sleeve after removal from bushing showing fracture, wiped OD surface. Right: interior of bushing mating to sleeve portion in left figure. All contact surfaces are wiped

1132

10 Rupture and Stress Corrosion Cracking …

Fig. 10.28 Main feedwater pump turbine, shaft sleeve. Fracture surface of sleeve (top) showing crack progression from keyway to bottom of sleeve. Evenly-spaced crack fronts visible near bottom, approximating width of OD grooves (4A). Fracture changes from fine to coarse texture near center (4B). Crack origin appears to be along radius in keyway (4C)

after which it curved slightly. The fracture had a brittle appearance with no necking or deformation evident. One half of the sleeve fracture was cleaned for examination. Cracking clearly progressed from the keyway area down the length of the sleeve (Fig. 10.28). The keyway area did not appear significantly darker or older than the rest of the fracture. Midway along the length of the fracture, the texture became noticeably coarser, corresponding to the point where the crack path began to curve (Fig. 10.28, 4B); it is likely that the crack rate accelerated at this point. Near the bottom of the sleeve, crack front markings were clearly visible (Fig. 10.28, 4A), with their spacing about the same as the external grooves. The final fracture region at the bottom of the sleeve was quite small. Judging from the texture of the fracture, the origin area appeared to be along the edge of the keyway, rather than at the top or base (Fig. 10.28, 4C). When viewed in profile, the suspected crack origin area lay directly in the keyway radius, while the rest of the fracture plane did not (Fig. 10.29).

10.2

Destructive Examination Results and Remediation

1133

Fig. 10.29 Main feedwater pump turbine, shaft sleeve. Top left: mating sleeve fractures at keyway after removal of metal debris; gauge = 1/16″. Top right: detail of left Figure showing probable origin area along keyway radius. Bottom left: oblique view showing profile of entire keyway. Metallography sections marked. Bottom right: suspected crack origin area. Edge of keyway along bottom, damaged OD surface along top

SEM exam of the origin region showed an intergranular cracking mode, with heavy oxidation on the grain facets (Fig. 10.30). All other regions of the fracture examined also showed intergranular cracking (Fig. 10.31). An impact fracture created in the lab showed the material to behave in a relatively ductile manner (Fig. 10.32). Transverse cross-sections were taken through the origin site, where the fracture was in the keyway radius, and farther down the keyway to capture the keyway radius intact (see Fig. 10.29 bottom left). An intergranular crack path with minor oxide-filled secondary cracking was seen along the crack path in both sections (Fig. 10.33).

1134

10 Rupture and Stress Corrosion Cracking …

Fig. 10.30 Main feedwater pump turbine, shaft sleeve. Top: SEM photo of small ridge at suspected origin area along edge of keyway (see Fig. 10.29 bottom right). Bottom left: detail of left side of ridge in the above photo showing an intergranular morphology. Bottom right: detail of upper right of above photo showing a similar intergranular path

The keyway radius was approximately 0.005″ (127 µm) (Fig. 10.34 left). The wrought tempered martensite microstructure showed minor carbide deposition on the prior-austenite grain boundaries, although not to a degree as would be considered detrimental (Fig. 10.34 right). The failed sleeve had been tempered by heat generated along the OD from contact with the bushing, creating a heat-affected band across at least half the sleeve thickness. Along the ID, where the material was not heat-affected, the sleeve hardness was Rockwell C52. Qualitative EDS showed the material to be a chromium stainless steel (no Ti/Mo/ Ni detected). No detailed chemical analysis was performed.

10.2

Destructive Examination Results and Remediation

1135

Fig. 10.31 Main feedwater pump turbine, shaft sleeve. Top left: structure at base of keyway (bottom right) showing an intergranular morphology. Top right: center of fracture (see Fig. 10.28) where crack appeared to accelerate. Bottom left: SEM photo of coarser, ridged area at left in the top right photo showing intergranular crack path. Bottom right: SEM photo of relatively smooth area at right in the top right photo showing intergranular crack path

Fig. 10.32 Main feedwater pump turbine, shaft sleeve. Transgranular, relatively ductile morphology in lab created impact fracture

1136

10 Rupture and Stress Corrosion Cracking …

Fig. 10.33 Main feedwater pump turbine, shaft sleeve. Left: cross-section through origin region of failed sleeve (A1 in Fig. 10.29 bottom left). Right: different area of fracture in section A1 showing minor intergranular secondary cracking

Fig. 10.34 Main feedwater pump turbine, shaft sleeve. Left: cross-section A2 in Fig. 10.29 (bottom left) showing keyway radius of *0.005″ (127 µm). Fracture plane at top. Right: typical microstructure of failed sleeve showing some carbide on prior-austenite grain boundaries

Examination of Intact Inboard Sleeve The dimensions of the used inboard sleeve were 6 ¼″ (159 mm) OD, 5 1/8″ (130 mm) ID at the keyway end, and 9 5/8″ (244 mm) tall. The sleeve was stained and possibly lightly fretted on the ID surface. The keyway was 1.61″ (40.9 mm) long on the ID and 0.59″ (15 mm) long on the OD. The keyway was not noticeably deformed, although minor rubbing wear had occurred on the OD grooves along one side (Fig. 10.35). An outline of the position of the L-shaped key was visible on the face of the keyway (Fig. 10.36 left). The inboard key was in good condition, while the outboard key had been overheated and severely worn (Fig. 10.36 right). A transverse section was taken through the keyway of the inboard sleeve, at the same approximate elevation as the fracture origin on the failed sleeve. No cracking was observed. The radius of the keyway was about 0.004″ (100 µm) (Fig. 10.37 left). The microstructure of the sleeve was essentially the same as that of the failed sleeve (Fig. 10.37 right).

10.2

Destructive Examination Results and Remediation

1137

Fig. 10.35 Main feedwater pump turbine, shaft sleeve. Left: keyway of inboard sleeve, viewed from ID. Right: keyway of inboard sleeve, viewed from OD. Grooves are lightly rubbed on left side of keyway

Fig. 10.36 Main feedwater pump turbine, shaft sleeve. Left: detail of inboard sleeve keyway showing outline of key position. Right: L-shaped keys, as received. Outboard key was heated and severely worn during sleeve failure

Fig. 10.37 Main feedwater pump turbine, shaft sleeve. Left: cross-section through keyway of inboard sleeve. Radius is *0.004″ (100 µm). Right: Typical microstructure of intact inboard sleeve. Some carbide is present on prior-austenite grain boundaries

1138

10 Rupture and Stress Corrosion Cracking …

Both the inboard sleeve and the unused sleeve from stock had a hardness of Rockwell C52, the same hardness as the failed outboard sleeve. Conclusion Failure of the outboard shaft sleeve was attributed to intergranular stress-corrosion cracking. It is well documented that wrought martensitic stainless steels with high hardness levels are susceptible to intergranular stress-corrosion cracking/hydrogen embrittlement. It is considered risky to use wrought 400-series stainless steels at high hardness levels in aqueous environments under tensile stress. Cast materials are far less susceptible to stress-corrosion cracking, even at high hardness levels. The shaft sleeve fit on the Type CD pump is not quite an interference fit. As such, there should be little contribution of tensile hoop stresses from the installation. However, residual tensile hoop stresses could remain as a result of heat treatment. The fact that the outboard sleeve appeared to have gapped open after failure implied that some residual tensile hoop stress was present. The inboard shaft sleeve had the same hardness, same material, and same keyway radius as the outboard sleeve, yet did not crack; it may have had a lower level of residual tensile hoop stress. This residual hoop stress is a manufacturing variable and will differ from sleeve to sleeve. The original region of the fracture was not significantly more oxidized than the rest of the axial fracture. This observation implies that the crack progressed relatively quickly from initiation to final fracture. The sleeve had last been inspected in May 1995 with no cracking observed. In a material highly susceptible to stress-corrosion cracking, the condition within the environment which actually initiates cracking after 8 + years of trouble-free service probably cannot be identified.

10.2.6 Destructive Examination of Valve Nuts Plant main characteristics: Westinghouse, PWR,1,129 MWe, 4 loops, USA. Equipment/Component: 1½″ (38 mm) by 2″ (51 mm) Dresser safety relief valve (valve 1NM-92). Operating conditions: containment atmosphere. Time of operation: 24 years. Failure discovery: the valve 1NM-92 was removed from service during EOC17. The valve had likely been in service for the life of the plant. As the valve was being refurbished to be placed into stock as a spare, surface cracking was noted on two of the four bonnet nuts. Specimen/sample characteristics: the nuts were ½″-13, SA-194 Grade 6 (410 martensitic SS, X12Cr13).

10.2

Destructive Examination Results and Remediation

1139

DE goal: failure root cause analysis. Results One nut showed an obvious radial indication on the washer face (Fig. 10.38). The indication continued onto the wrench flat, where it ran in an oblique direction across approximately one-half of the nut thickness (Fig. 10.39 left). The radial indication was also visible continuing across several internal threads. A circumferential indication was also present on the washer face of the same nut. A second nut was found to have several irregular circumferential indications, also on the washer face (Fig. 10.39 right). A cross-section through the large circumferential indication in Fig. 10.39 right revealed a single, straight, slightly branching crack with an oxide-filled tip (Fig. 10.40).

Fig. 10.38 Safety relief valve. Left: nuts as received; radial indication noted. Right: detail of nut showing both radial and circumferential indications on washer face

Fig. 10.39 Safety relief valve nuts. Left: side of nut from Fig. 10.38 right, showing continuation of radial indication onto wrench flat. Right: Circumferential indications on washer face of a second nut

1140

10 Rupture and Stress Corrosion Cracking …

Fig. 10.40 Safety relief valve nuts. Left: cross-section through nut with large circumferential crack, visible by eye in Fig. 10.39 right. Right: Crack tip from left photo showing a slightly branched crack path

Fig. 10.41 Safety relief valve nuts. Top: cross-section through nut in Fig. 10.38 right showing many parallel radial cracks. Cracks are located at small pits on wrench flat surface. Bottom left: detail of crack at top photo showing a branched crack emanating from a small pit. Bottom right: Detail of crack tip from left photo. Crack is branching and oxide-filled

Sections through the nut in Fig. 10.38 right showed the radial indication ended at the point visible on the exterior surface in Fig. 10.39 left. In addition, several additional indications were found, each parallel to the washer face and perpendicular to the radial indication (Fig. 10.41 top). These cracks were associated with small surface pits on the wrench flat, and were also branching and oxide-filled (Fig. 10.41 bottom). The steel was fine-grained tempered martensite. The oxide within the cracks had a light appearance in cross-section and so was examined further using scanning electron microscopy (Fig. 10.42).

10.2

Destructive Examination Results and Remediation

1141

Fig. 10.42 Safety relief valve nuts. SEM photo of surface pit on wrench flat (Fig. 10.41, bottom left) with intergranular crack extending from pit

Fig. 10.43 Safety relief valve nuts. SEM image and x-ray map of oxide in crack. Elements: Cr (red), Fe (yellow), Cr + Fe (green). Oxide in crack is enriched in chromium

The oxide within the cracks was found to be essentially all chromium oxide with very little iron oxide present (Fig. 10.43). Rockwell hardness testing showed all four nuts to have a hardness of 29–31 HRC. Conclusion The large indications on the nuts were all superficially typical of surface discontinuities that can develop during the forging and quenching processes. The circumferential indications were almost certainly present in some form since manufacture, as no stress state induced during service would be likely to initiate and propagate cracking in that direction. These indications and the largest radial indication may have been inactive quench cracks from manufacture, since they were

1142

10 Rupture and Stress Corrosion Cracking …

oxide-filled at the tip, followed an intergranular path, and were fairly wide open. 400-series stainless steel is known to be susceptible to stress-corrosion cracking under moist conditions. These nuts were not exceptionally hard at *30 HRC and so were not highly susceptible to SCC; however, the small cracks at tiny pits on the wrench flats were consistent with SCC. These cracks were tight, branching, and oxide-filled. The small surface pits may have allowed for the development of a locally acidic environment. These cracks appeared to be active but were small, and so were probably growing slowly. No cracking was noted in the nuts which did not contain surface discontinuities.

Reference Cattant, François. 2014. Materials ageing in light water reactors—Handbook of destructive assays, Lavoisier Editions.

Chapter 11

Atmospheric Corrosion of Stainless Steel

11.1

Background

Surprisingly; highly corrosion resistant alloys such as 303, 304, or 309L have experienced cracking in the open atmosphere of the containment building. So far, the root cause of this cracking is not fully understood.

11.2

Destructive Examinations Results and Remediation

11.2.1 Outlet Nozzles of the Reactor Pressure Vessel. Destructive Examination of 3 Specimens Harvested from 2 Dissimilar Metal Welds Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: RPV, outlet nozzles, DMW between the RPV nozzle and the safe end. The RPV nozzle is made of ASTM SA 508 Class 3 ferritic steel. A SS butter is applied on the nozzle before being welded to the SS safe end (shop weld). The first butter layer is E 309 L (similar to French 24–12) and the other layers are E 308 L (similar to French 20–10). The safe end is welded to the nozzle also with E 308 L. The nozzle equipped with its safe end is then machined, a minimum thickness of 12 mm (0.5’’) is removed at the OD. Operating conditions: containment building environment, 323 °C (613°F) at the DMW OD (presence of insulation). Unit time of operation: 91,086 h. Failure discovery: during the 1991 outage, a PT of the RPV nozzles DMWs revealed linear indications on the three hot nozzles. Replica taken on the DMW © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_11

1143

1144

11 Atmospheric Corrosion of Stainless Steel

#S10 H2 was not conclusive as to the mechanism responsible for these indications. As a consequence, decision was made to harvest hour glass specimens from the two other nozzles. Similar event frequency: PT indications have been found on several units of the French fleet, on RPV, SG and pressurizer nozzles. Specimen/sample characteristics: 3-hglass specimens have been harvested. The first one comes from the DMW #S10 H1, between radiography marks 11 and 12 (Fig. 11.1). This specimen contains a 7 mm long field PT indication, at the butter/ferritic steel interface. The second one comes from the DMW #S10 H3, between radiography marks #24 and #25. This specimen is free of any field PT indication. The third one comes also from the DMW #S10 H3, at radiography mark #13. This specimen contains an 18 mm long field PT indication, at the butter/ferritic steel interface (Fig. 11.1). DE program and goal: the goal of the DE was the identification of the mechanism responsible for the PT indications. The DE program included: • Determination of the propagation path of the indications into the nozzles thickness in relation to the material structure; • Identification of the chemical elements present in the defects; • Determination of the chemical composition of the oxides observed on the nozzles OD.

A

C

B

A

C

B

Buttering

Buttering Ferritic steel

7 mm

Ferritic steel

B B

4 mm

Fig. 11.1 RPV outlet nozzles. DMWs. Sketches of hour-glass specimens with SEM defects (BSE mode) drawn in red. Left: specimen from the DMW #S10 H1, between radiography marks #11 and #12. Right: specimen from the DMW #S10 H3, at radiography mark #13

11.2

Destructive Examinations Results and Remediation

1145

Results DMW #S10 H1 The as-received hour glass specimen exhibits several defects, either cavities or raised, in the ferritic steel (Fig. 11.2). EDS analysis reveals the presence of O, Fe and Si elements, along with traces of Cl and S. After dry flat polishing, intergranular attack in the buttering and oxide spots at the ferritic steel/buttering interface are observed (Fig. 11.3). The cracks of this network running parallel to the ferritic steel/buttering interface are filled with oxide. When the cracks reach the ferritic steel, they form an oxide spot developing in the martensitic band. In the buttering, long oxide spots correspond to oxidized martensite. The PT indications 1–3 correspond to fine intergranular attack, more or less oxidized, running parallel to the ferritic steel/buttering interface, up to a distance of 0.2 mm (0.008’’) from this interface (Fig. 11.4). This attack is localized in the first butter layer, in an austenitic band running between the ferritic steel (nozzle) and the austenitic-ferritic SS (weld). A cross section of the PT indications shows they are

Ferritic steel

SS Buttering

Fig. 11.2 RPV outlet nozzle. DMW #S10 H1 specimen. SEM image of the OD in the as-received conditions (BSE mode)

Oxidized martensite

100 µm

SS Buttering

50 µm

SS Buttering

Ferritic steel

Ferritic steel

Fig. 11.3 RPV outlet nozzle. DMW #S10 H1 specimen. Left: SEM image of the PT indication #1 (see Fig. 11.1, BSE mode). Right: SEM image of the PT indication #5 (see Fig. 11.1, SE mode)

1146 Buttering

11 Atmospheric Corrosion of Stainless Steel

50 µm

Buttering

50 µm Oxide spots

Martensite band

Oxide spot

Ferritic steel

Ferritic steel

Fig. 11.4 RPV outlet nozzle. DMW #S10 H1 specimen. Left: flat polishing of the PT indication #1 (AB specimen, see Fig. 11.1, nital 5% etch). Right: cross section of the PT indication #3 (BC specimen, see Fig. 11.1, nital 5% etch)

0.7 mm deep (0.03’’). One of the cracks when crossing a martensitic band forms an oxide spot (Fig. 11.4). DMW #S10 H3 The SEM observation of the hour glass specimen taken in the area free of PT indications reveals the presence of many oxidized pits. EDS analysis of one of these pits detects the elements Fe, Si and O, along with traces of Al, Ca, S, Cr, and Mn. Al, Si, and Ca may be remnant from the PT products. A slight polishing erases all traces of pits. The SEM observation of the hour glass specimen containing PT indications also shows the presence of pitting in the ferritic steel. EDS in these pits provides results no different from the previous analyses: Cl and S pollution is detected. The defects are located in the first butter layer, they run parallel to the ferritic steel/butter interface and some branching propagates up to 1.8 mm (0.07’’) from this interface. Most of the ferritic steel defects disappear after polishing except a big oxide spot located at 30 µm (1.2 mils) from the ferritic steel/buttering interface, along with a series of small inclusions close to this spot (Fig. 11.5).

Buttering

Ferritic steel

200 µm

Nozzle axis

Oxide spot

Fig. 11.5 RPV outlet nozzle. DMW #S10 H3, specimen at radiography mark #13. SEM observation after dry flat polishing (BSE mode)

11.2

Destructive Examinations Results and Remediation

1147

Microprobe analysis Oxide spot in the ferritic steel (Fig. 11.6): the analysis of the oxide spot visible on Fig. 11.5 reveals this spot is composed of iron oxide, Fe depleted and Si enriched as compared to the surrounding ferritic steel composition. It contains little or no Al or Ca. It comes from the ferritic steel oxidation. The small inclusions have a different composition: they contain a lot of Al and Ca too; they correspond to typical foundry inclusions. Oxide spot at the ferritic steel/buttering interface connected to buttering intergranular attack (Fig. 11.6): the composition of the periphery differs from the center composition. There is less iron (54.6 vs. 60.3 Wt%), more chromium (11.6 vs. 5.3 Wt%) and more nickel (2.8 vs. 2.1 Wt%) in the center. These results are intermediate between the ferritic steel and the buttering compositions. This is consistent with the fact that these spots form in the martensitic zone which is a high dilution zone. Oxide spot in the buttering: the analysis of an oxide spot in the first butter layer shows the presence of Fe, Si, Cr, Ni, Ca, Al along with traces of K, Na, Mn, and S; this oxide also results from martensite oxidation. From the interface to a distance of 100 µm (4 mils) the chemical composition gradient is high, and from 100 µm (4 mils) to 2.4 mm (0.1’’) the chemical composition is pretty stable with 16.5 Wt% Cr and 8.7 Wt% Ni. The RCC-M §3,5612 (edition 1985) code requires for the middle and the end of the first buttering bead, Cr and Ni minimum content of 17 and 9%; the contents measured on the #S10 H3 nozzle are less than the required values. Then, from 2.4 to 3 mm (0.1–0.12’’), the Cr content increases to 19.6 Wt%, the iron content decreases and the Ni content is stable. Intergranular attack in the first butter layer: the oxide filling a wide-open intergranular crack contains low concentrations of Fe, Cr, and Ni.

Ferritic steel

Ferritic steel

Buttering

Intergranular attack

Fig. 11.6 RPV outlet nozzle. DMW #S10 H3, specimen at radiography mark #13. SEM images of the oxide spots analyzed by microprobe (BSE mode). Left: spot and inclusions located in the ferritic steel (Fig. 11.5). Right: spot located at the ferritic steel/buttering interface

1148

11 Atmospheric Corrosion of Stainless Steel

Conclusion, remedial actions The ferritic steel pitting and the first butter layer intergranular attack both result from corrosion. The high dilution of the ferritic steel in the AISI 309L stainless steel of the first butter layer is responsible for the damage observed on the RPV nozzles. Traces of Cl and S have been observed on the DMWs specimens; the origin of this pollution is unknown. The OD corrosion of the DMWs is monitored by VT (using a field microscope), PT and sometimes replicas or specimen’s removal. In general, the PT indications are eliminated by a light polishing.

11.2.2 Inlet Nozzles of the Reactor Pressure Vessel. Destructive Examination of 5 Specimens Harvested from 2 Dissimilar Metal Welds Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: RPV, inlet nozzles, DMW between the RPV nozzle and the safe end. The RPV nozzle is made of ASTM SA 508 Class 3 ferritic steel. A SS butter is applied on the nozzle before being welded to the SS safe end (shop weld). The first butter layer is E 309 L (similar to French 24–12) and the other layers are E 308 L (similar to French 20–10). The safe end is welded to the nozzle also with E 308 L. The nozzle equipped with its safe end is then machined: a minimum thickness of 12 mm (0.5’’) is removed at the OD. Operating conditions: containment building environment, 286 °C (547°F) at the DMW OD (presence of insulation). Unit time of operation: 84,131 h. Failure discovery: during the 1990 first 10-year outage, a PT of the RPV nozzles DMWs revealed linear indications on all nozzles. After replica examination, all indications were removed by a 3 mm (0.12’’) deep grinding. During the following outage in 1991, small PT indications were observed in the 1990 PT white zones on all but the #S10 H2 DMWs. To know more about these new PT indications, some hour-glass specimens were harvested. Similar event frequency: PT indications have been found in several units of the French fleet, in RPV, SG and pressurizer nozzles.

11.2

Destructive Examinations Results and Remediation

1149

Buttering Buttering

Ferritic steel

Ferritic steel

Fig. 11.7 RPV inlet nozzle. DMW #S10 G1. Sketches of hour-glass specimens with SEM defects (BSE mode) drawn in red. Left: specimen located between radiography marks #21 and #22. Right: specimen located between radiography marks #23 and #24

Specimen/sample characteristics: seven hour glass specimens have been harvested, five from inlet nozzles and two from outlet nozzles. This summary covers only the DE of the inlet nozzles specimens. The first specimen comes from the DMW #S10 G1, between radiography marks 1 and 26. This specimen was PT white in the field. The second specimen comes from the same DMW, between radiography marks #21 and #22 (Fig. 11.7). This area has 2 linear PT indications 9 mm (0.35’’) and 3.5 mm (0.14’’) long. The third specimen also comes from the same DMW, between radiography marks #23 and #24 (Fig. 11.7). This area has 3 linear PT indications 6 mm (0.24’’), 2.5 mm (0.1’’), and 2 mm (0.08’’) long. The fourth specimen comes from the DMW #S10 G3, at radiography mark 1 (Fig. 11.8). This area has 3 linear PT indications, all 2 mm (0.08’’) long. The last specimen comes from the same DMW, between radiography marks 20 and 21 (Fig. 11.8). 3 linear PT indications (3 mm (0.12’’), 2 mm (0.08’’) and 2 mm (0.08’’) long) have been observed at the edge of a zone which has been ground in 1990. DE program and goal: the goal of the DE was the characterization of the PT indications. The DE program included: VT, SEM and micrography.

1150

11 Atmospheric Corrosion of Stainless Steel

Buttering Buttering

Ferritic steel

Ferritic steel

Fig. 11.8 RPV inlet nozzle. DMW #S10 G3. Sketches of hour-glass specimens with SEM defects (BSE mode) drawn in red. Left: specimen located at radiography marks #1. Right: specimen located between radiography marks #20 and #21

Results DMW #S10 G1, specimen 1–26 Although PT white on the field, the SEM observation revealed the presence of some fine and oxidized intergranular attack. The cracking runs parallel to the ferritic steel/ buttering interface, from the interface up to a distance of 0.5 mm (0.02’’) from it (Fig. 11.9). Oxide spots form when the cracks reach the ferritic steel. One defect is wide open and has propagated at 12 µm (0.5 mil) from the ferritic steel/buttering interface (Fig. 11.9).

Buttering

40 µm

20 µm Buttering

Oxide Ferritic steel

Ferritic steel

Fig. 11.9 RPV inlet nozzle. DMW #S10 G1, specimen 1–26. Left: SEM image of intergranular attack and oxide spots (BSE mode). Right: micrograph of a wide-open crack running parallel to the ferritic steel/buttering interface (nital 5% etch)

11.2

Destructive Examinations Results and Remediation

1151

DMW #S10 G1, specimen 21–22 The SEM observation reveals the presence of branched and oxidized intergranular attack. This attack is located in the first butter layer and generally stays 2 mm (0.08’’) away from the ferritic steel/buttering interface (Fig. 11.10). Buttering

Second butter layer 200 µm

First butter layer

100 µm

Ferritic steel

Fig. 11.10 RPV inlet nozzle. DMW #S10 G1, specimen 21–22. Left: SEM image of intergranular attack in the first butter layer, close to the interface with the second layer (BSE mode). Right: SEM image of intergranular attack close to the ferritic steel/buttering interface (BSE mode)

DMW #S10 G1, specimen 23–24 Some defects are closely following the ferritic steel/buttering interface (defects #1 to #5, Fig. 11.11). Others are highly branched and extend all over the first butter layer width (defect #9, Fig. 11.11).

Buttering

Ferritic steel

2nd butter layer 1st butter layer Ferritic steel

Fig. 11.11 RPV inlet nozzle. DMW #S10 G1, specimen 23–24. SEM images of some of the defects present in the first butter layer, after a light dry polishing. Note the unusual aspect of the group of defects #6 + #7 + #8 (BSE mode)

1152

11 Atmospheric Corrosion of Stainless Steel

Buttering

Ferritic steel

200 µm

20 µm

Fig. 11.12 RPV inlet nozzle. DMW #S10 G1, specimen 23–24. SEM image of the defect #8 after a light dry polishing (BSE mode)

Ductile tearing

Fig. 11.13 RPV inlet nozzle. DMW #S10 G1, specimen 23–24. SEM image of the defect #6 broken open. Crack faces have a molten aspect. The hot cracking is 1.2 mm (0.047’’) deep (left red arrow)

The group of defects #6 + #7 + #8 has an unusual aspect. The defect #8 extends on both buttering and ferritic steel (Figs. 11.11 and 11.12). When open, the defect #6 exhibits an interdendritic cracking mode with a molten aspect characteristic of hot cracking (Fig. 11.13). This defect is much less oxidized than the intergranular cracking such as defect #9. A microprobe analysis of the defect #8 reveals the presence of oxygen and iron associated with manganese, calcium, sulfur and phosphorus. The presence of such oxides along with the presence of S and P is consistent with hot cracking located in the ferritic steel. DMW #S10 G3 The two hour-glass specimens taken from the nozzle S10 G3 exhibit intergranular cracking in the first butter layer. The cracks are highly branched and give birth to oxide spots when reaching the ferritic steel/buttering interface (Fig. 11.14).

11.2

Destructive Examinations Results and Remediation

1153

100 µm

Buttering

Oxide spots

Ferritic steel

Oxide spots

Fig. 11.14 RPV inlet nozzle. DMW #S10 G3, specimen 20–21. SEM image of defects present in the first butter layer, after a light dry polishing (BSE mode)

The maximum depth of the defects of the hour-glass specimen #20–21, measured by UT, is 1 mm (0.04’’). A cross section in the middle of this specimen shows that the maximum depth of the intergranular cracking reaches 0.96 mm (0.038’’). Conclusion, remedial action The PT indications correspond to intergranular cracking located in the first butter layer. The high dilution of the ferritic steel in the AISI 309L stainless steel of the first butter layer is responsible for the damage observed on the RPV nozzles. On the hour-glass specimen 23–24 of the DMW #S10 G1, an arc strike has been observed astride on the ferritic steel/buttering interface. The OD corrosion of the DMWs is monitored by VT (using a field microscope), PT and sometimes replicas or specimen’s removal. In general, the PT indications are eliminated by a light polishing.

11.2.3 Steam Generator Outlet Nozzle. Destructive Examination of 2 Specimens Harvested from the Dissimilar Metal Weld Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: DMW #45/15 of the SG #1 outlet nozzle. The nozzle is made of AFNOR 16 MN 5 M steel (*1 Wt% Mn and * 0.4 Wt% Ni). A SS butter is applied on the nozzle before being welded. The first butter layer is E 309 L (similar to French 24–12) and the other layers are E 308 L (similar to French 20–10). Operating conditions: containment building environment, 286 °C (547°F) at the DMW OD (presence of insulation).

1154

11 Atmospheric Corrosion of Stainless Steel

Unit time of operation: 70,389 h. Failure discovery: during the 1991 outage, a PT of the SG nozzles DMWs revealed linear indications on the SG #1 outlet nozzle, between radiography marks 0 and 29. Replica characterized these indications as intergranular corrosion of the first butter layer. To know more about the corrosion mechanism, 2 hours-glass specimens were taken, one in a PT white zone, the other in the replica zone. Similar event frequency: PT indications have been found on several units of the French fleet, on RPV, SG and pressurizer nozzles. Specimen/sample characteristics: 2 h-glass specimens have been harvested, one between radiography marks 0 and 29 (Fig. 11.15), one between radiography marks 28 and 29 (PT white specimen). DE program and goal: the goal of the DE was the characterization of the PT indications. The DE program included: VT, micrography, SEM and microprobe analysis. Results Specimen 28–29 The micrography and the SEM observation confirmed the absence of defect on this specimen. Specimen 0–29 Intergranular attack is observed from the ferritic steel/buttering interface up to a distance of 3 mm (0.12’’) from this interface (Fig. 11.15). The intergranular attack forms oxide spots when reaching the ferritic steel/buttering interface (Fig. 11.16).

Fig. 11.15 SG outlet nozzle. DMW #45/15. Sketch of the hour-glass specimen located between radiography marks #0 and #29, with SEM defects (BSE mode) drawn in red

A

B

C 5 mm

D 5 mm

E 3 mm

Buttering

3 mm

Ferritic steel

C

11.2

Destructive Examinations Results and Remediation

1155

Buttering

Buttering

Ferritic steel

Ferritic steel

Fig. 11.16 SG outlet nozzle. DMW #45/15. SEM images of the intergranular attack and of oxide spots (BSE mode)

2nd Butter layer

500 µm

50 µm

1st Butter layer

Ferritic steel

Fig. 11.17 SG outlet nozzle. DMW #45/15. Flat polishing of specimen BC. The intergranular attack is limited to the first butter layer (oxalic acid etch)

After flat polishing and etching, the intergranular attack is limited to the first butter layer which is 3 mm (0.12’’) wide (Fig. 11.17). The first butter layer has an austenitic structure with martensite zones coming from the dilution of the ferritic steel. On this BC specimen, a wide-open crack runs parallel to a martensite zone, in the middle of the first butter layer. A cross section (CC section, see Fig. 11.15) shows that the corrosion propagates through the entire specimen thickness (1.8 mm/0.07″, Fig. 11.18). When crossing a martensite zone, the corrosion widens. All the wide-open defects are full of oxide. The DE specimen (see Fig. 11.15) has been broken apart. Observation of the faces shows intergranular corrosion of basaltic grains oriented in the solidification direction. This corrosion has propagated through the entire specimen thickness.

1156

11 Atmospheric Corrosion of Stainless Steel

2nd Butter layer

500 µm

200 µm

1st Butter layer Ferritic steel Wetted surface

Field cut

Fig. 11.18 SG outlet nozzle. DMW #45/15. CC cross section (see Fig. 11.15). The corrosion is visible through the entire specimen thickness (oxalic acid etch)

Fig. 11.19 SG outlet nozzle. DMW #45/15. SEM image of the DE specimen (see Fig. 11.15) broken apart. Intergranular corrosion is observed on the entire specimen thickness. The field replica etching induced some pitting

Some pitting is observed, as the result of the anterior field replica etching (Fig. 11.19). Microprobe analysis has been carried out on oxide spots connected to intergranular corrosion, on the CC cross section (see Figs. 11.15 and 11.20). Compared to the periphery, the spots center is depleted in Fe and enriched in Cr, Ni and Mn. For example, Cr varies from 6.2 to 7.3 Wt% at the periphery whereas it ranges from 11.6 to 13.7 Wt% at the center. In the oxide, the alloying elements

11.2

Destructive Examinations Results and Remediation

1157

10 µm 200 µm 1st Butter layer Cavity Oxide spots

Ferritic steel

1st Butter layer

Ferritic steel

Fig. 11.20 SG outlet nozzle. DMW #45/15. View of a SEM image of the CC cross section (see Fig. 11.15). Right: detail #1 of the left image (BSE mode)

content is higher than in the ferritic steel and lower than in the buttering. This is consistent with the fact that oxide spots develop in the martensitic areas which are highly diluted zones. Conclusion, remedial action The PT indications correspond to intergranular cracking located in the first butter layer. The high dilution of the ferritic steel in the AISI 309L stainless steel of the first butter layer is responsible for the damage observed on the RPV nozzles. The morphology of the defects observed on this SG nozzle DMW is no different from the morphology of the defects observed on RPV nozzles DMWs. The OD corrosion of the DMWs is monitored by VT (using a field microscope), PT and sometimes replicas or specimen’s removal. In general, the PT indications are eliminated by a light polishing.

11.2.4 Pressurizer Relief Valve Nozzle. Destructive Examination of a Specimen Harvested from the Dissimilar Metal Weld Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: Pressurizer relief valve nozzle, DMW #35/25/4 (6’’) between the relief nozzle and the safe end. The pressurizer nozzle is made of ASTM SA 508 Class 3 ferritic steel (similar to AFNOR 16 MND 5). A SS butter is applied on the heated nozzle before being welded to the SS safe end (shop weld). The first butter layer is E 309 L (similar to French 24–12) and the other

1158

11 Atmospheric Corrosion of Stainless Steel

layers are E 308 L (similar to French 20–10). The safe end is welded to the nozzle without pre-heating and also with E 308 L filler metal. Operating conditions: containment building environment, 345 °C (653°F) at the DMW OD (presence of insulation). Unit time of operation: 56,491 h. Failure discovery: during the 1991 outage, a PT of the pressurizer nozzles DMWs revealed linear indications on the DMW #35/25/4, at the interface between the ferritic steel and the buttering. A replica, taken at radiography mark #1, characterized these indications as intergranular corrosion located in weld metal overlapping the ferritic steel. To know more about the corrosion mechanism, one hour-glass specimen was harvested. This specimen contained a 10 mm (0.4’’) long PT indication located in front of the radiography mark #2. Similar event frequency: PT indications have been found on several units of the French fleet, in RPV, SG and pressurizer nozzles. Specimen/sample characteristics: one hour-glass specimen has been taken at the radiography mark #2 (Fig. 11.21). DE program and goal: the goal of the DE was the characterization of the PT indications. The DE program included: VT, micrography, SEM, EDS and microprobe analysis.

Fig. 11.21 Pressurizer relief nozzle. DMW #35/25/4. Sketch of the hour-glass specimen located at radiography mark #2, with SEM defects (BSE mode) drawn in red

B

A

4 mm

C

2.5 mm

D

9.5 mm

1st Butter layer

1.6 mm

Ferritic steel

11.2

Destructive Examinations Results and Remediation

1159

Results SEM and EDS SEM examination and EDS analyses of the hour-glass specimen in the as-received conditions show many oxide spots on the ferritic steel. After dry polishing, a new SEM observation reveals 3 narrow and branched defects in the first butter layer which run parallel to the interface with the ferritic steel (Fig. 11.21). Metallography The observation of the BC specimen (see Fig. 11.21) shows intergranular attack in the first butter layer, more or less filled up with oxide. This corrosion runs at 1.2 mm (0.047’’) from the interface with the ferritic steel and is 0.4 mm (0.016’’) deep in plane B. The intergranular corrosion is limited to the first butter layer (Fig. 11.22). Some grains boundaries are decorated with martensite, this martensite being oxidized when corresponding to a crack path.

200 µm nd

2

50 µm

Butter layer

1st Butter layer

Fig. 11.22 Pressurizer relief nozzle. DMW #35/25/4. Left: view of the specimen BC (see Fig. 11.21) after flat polishing and oxalic acid etch. Right: detail “A” of the left micrograph

1160

11 Atmospheric Corrosion of Stainless Steel

Microprobe analysis The first butter layer has an austenitic structure (except in highly diluted zones where martensite prevails). Starting from the ferritic steel, Fe and Mo decrease a little whereas Cr and Ni gently increase. These gentle gradients along with the Cr and Ni contents measured at 0.2 mm (0.008’’) from the ferritic steel interface (respectively 16.4 and 8.8 Wt%) show that the austenite of the first butter layer is diluted by the ferritic steel. In the zone close to the ferritic steel, the Cr and Ni contents are slightly inferior to the code requirement: for the middle and the end of the first weld bead, the Cr and Ni contents should exceed 17 and 9 Wt% (RCCD-m, §3,512, Edition 1985). Martensite is much more diluted than austenite, with Cr and Ni contents respectively of 9.4 and 4.9 Wt%. The interface between the first and the second butter layers exhibits a significant gradient of the chemical composition; Cr and Ni sharply increase to 21 and 11.3 Wt% (normal contents for E 308L). Cl and S have been detected several times in the oxide filling the intergranular cracks. Conclusion, remedial action The PT indications correspond to intergranular cracking located in the first butter layer. This corrosion is very shallow (a few tenth of mm) and is observed in austenitic areas which sometimes exhibit intergranular martensite. The morphology of the defects observed on this pressurizer nozzle DMW is no different from the morphology of the defects observed on RPV and SG nozzles DMWs. The OD corrosion of the DMWs is monitored by VT (using a field microscope), PT and sometimes replicas or specimen’s removal. In general, the PT indications are eliminated by a light polishing.

11.2.5 Destructive Examination of Leaking NS Pipes Plant main characteristics: Westinghouse PWR, 1,220 MWe, 4 loops, USA. Equipment/Component: NS piping. Two leaking welds were found on the Schedule 10–8″ (254–203 mm) diameter stainless steel NS piping, one on each train. These pipes are made of 304. The carbon content of the 2A1 pipe is 0.7 Wt%. Operating conditions: NS welds could see 10–15 psig (0.7–1 bar) internal pressure during normal plant operation. Both pipes were vertical risers, uninsulated and exposed to ambient air in the annulus. The welds would normally have been in contact on the ID by borated water from the FWST, which could have a relatively high oxygen content compared to primary system water. A FWST water sample taken on 7/28/05 showed the following content: • Dissolved oxygen 5 ppm (i.e. saturated); • Chloride 9.2 ppb;

11.2

Destructive Examinations Results and Remediation

1161

• Fluoride 2.6 ppb; • Sulfate 8.1 ppb; • Boron 2789 ppm. In July 2005, the external NS pipe temperature was measured via laser temperature gun: 88–91°F (31–33 °C). Time of operation: about 21 years. Failure discovery: in March 2004, two leaking welds were found on the NS piping. The leaks were discovered due to the presence of dried boron on the pipe exterior. Both leak sites were at the top end of a vertical 45° elbow. The 2A1 pipe showed one leak on the front side above the weld, and two proximate leaks on the back side, above and below the weld (Fig. 11.23). The 2B2 pipe also had two leak sites * 80° apart, both located in the pipe above the weld (Fig. 11.24).

Fig. 11.23 NS leaking pipes. Two views of leak sites as-found on 2A1 pipe. Exterior shows paint, marker, insulation (?), rust, and some drip-type staining. Larger boron site is the “front” side

Fig. 11.24 NS leaking pipes. Two views of leak sites as-found on 2B2 pipe, located just below floor grating. Exterior shows surface rust at welds. Larger boron site is the “front” side

1162

11 Atmospheric Corrosion of Stainless Steel

Specimen/sample characteristics: Three pipe sections containing welds were provided: • Leaking weld from 2A1 with one leak area marked, at 45° elbow; • Leaking weld from 2B2 with one leak area marked, at 45° elbow; • Weld identified only as “B Train” with no leak area marked—assumed to be the other weld on the 45° elbow from 2B2, preserved when the elbow was replaced. The marked leak areas were sectioned out of the 2A1 and 2B2 pipes. DE goal and program: leaks root cause analysis. The program included: VT, PT, micrography, SEM and chemical analysis. Results Macro-examination To locate the leaks, PT was performed on the OD surface of the 2A1 and 2B2 welds. Linear crack-like indications were found in the base metal adjacent to the weld at all five leaking sites. Figures 11.25 and 11.26 illustrate one location: 2A1 front, two irregular cracks, total circumferential length 7/8″ (22 mm).

Fig. 11.25 NS leaking pipes. Left: OD fluorescent dye penetrant results for 2A1 front leak. Weld is beneath ruler. Gage = 1/16″. Right: cross-section through 2A1 front leak

Fig. 11.26 NS leaking pipes. Left: detail of a through-wall leak from 2A1 front. Right: same area as in left macrograph using differential interference contrast (DIC) to show unusual grain structure

11.2

Destructive Examinations Results and Remediation

1163

Fractography A portion of each of cracks on the 2A1 pipe was broken open to reveal the internal crack surface. The surfaces were granular with a brown to rusty-brown staining extending from the OD inward. The ID edge of each opened crack was bright and clean. SEM was used to examine these opened crack surfaces in detail. All of the opened cracked areas showed an intergranular crack path. Some ductile tearing was visible along the ID surface where the crack had been pulled open in the lab. The OD portions of the opened cracks contained more deposits (Fig. 11.27). The intergranular cracked surfaces near the ID were cleaner. Sulfur and chlorides were detected in deposits on the opened 2A1 front leak site. Sulfur and chlorides were not noted on the opened lower 2A1 back leak site but were detected on the opened upper 2A1 back leak site. The ID pipe surface adjacent to the 2A1 lower indication showed the presence of random shallow intergranular corrosion. The surface was not uniformly attacked, as might be expected if the attack had been produced during manufacture by a pickling process. This area of the pipe surface had been previously ground for weld preparation. No chlorides were detected on the ID surface, although a minor sulfur peak was produced.

Fig. 11.27 NS leaking pipes. Left: OD edge of opened crack, 2A1 front. Deposits are crusted on the intergranular surface. Right: crack tip near ID edge, 2A1 front

1164

11 Atmospheric Corrosion of Stainless Steel

Metallography An axial cross-section was taken through each indication revealed by fluorescent PT. A through-wall crack was found in the base metal at each site, typically ¼–3/8″ (6–10 mm) from the weld (Fig. 11.25 right). The crack locations corresponded to a band of sensitized material where carbides had formed on the grain boundaries as the base metal cooled after welding. Several of the crack sites were located where the pipe wall was slightly thinner, either from external grinding (Fig. 11.28 left) or possibly some deformation of the pipe (Fig. 11.28 right). The straight pipe runs on both 2A1 and 2B2 had unusual microstructures, with large grains at the surface and very small grains within (Fig. 11.26 right). This structure was unrelated to welding and must have resulted from an incomplete anneal when the pipe was manufactured. However, the microstructure of both pipe elbows was essentially normal; the only crack in an elbow was at the lower 2A1 back site. The crack paths were branching and intergranular, and the cracks appeared discontinuous in places as the crack path wandered in and out of the plane of section (Fig. 11.29 left). Cracking was limited to the sensitized band of material. Fine, discrete carbides were visible on the grain boundaries throughout the sensitized area (right), and intergranular attack (IGA) occurred along these same grain boundaries.

Fig. 11.28 NS leaking pipes. Left: cross-section through 2B2 front leak. Right: cross-section through lower 2A1 back leak. Profile of ID surface appears concave

Fig. 11.29 NS leaking pipes. Left: detail of OD surface penetration, 2A1 front. Right: detail of microstructure showing discrete carbides on grain boundaries, an indication of a sensitized condition. Oxalic acid etch

11.2

Destructive Examinations Results and Remediation

1165

Conclusion, remedial action The cracking observed in the NS stainless steel piping was strictly intergranular and was observed only in base metal which had been sensitized during welding. The cracking mechanism therefore appears to be intergranular stress-corrosion cracking (IGSCC). The cracking appeared to have progressed from the OD surface inward. Oxygen content is likely the critical factor for IGSCC occurrence in a PWR system. The temperature at which this IGSCC occurred is unusually low, however there are other examples of room temperature SS cracking in the Industry. Moisture must be present in order for SCC to occur. Ambient moisture in the form of condensation from nearby piping in the annulus was observed. No moisture was dripping directly on the NS pipes at the leaking elbows; however, the surface deposits observed could have absorbed moisture and kept the pipe surface beneath the deposit slightly moist. The tendency for austenitic stainless steels to sensitize can be reduced by the use of low-carbon grades (L-grades).

11.2.6 Destructive Examination of Containment Spray System Pipes Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: containment spray system pipes. Pipes made of Z2CN18-10 (304L). The pipes are 355.7 mm OD and 4.77 mm thick. Operating conditions: containment building atmosphere. Boric acid with 3000 ppm boron. Temperature = 40 °C (104°F). Pressure = 6 bars (87 PSI). In normal operating conditions, the pipes are full of stagnant boric acid. Twice a month, periodic tests are run at 600 m3/h flow in order to check the good condition of the spray pumps 2EAS001PO and 2EAS002PO. Time of operation: 28 years, from 1982 to 2010. Failure discovery: boric acid crystals were discovered on the two containment spray suction lines 2EAS009TY and 2EAS010TY, at the floor penetration location towards the RWST. The leaks are located at the location of venting zones of the welded baseplates to the pipes, in the SB4031 support (Fig. 11.30). Behind the baseplate, the environment is called “neutral aerated” and oxidizing because of oxygen presence. Also, the containment SS pipes have strongly hurt the frame, inducing significant marks on the welded protective baseplates. Some water hammer in operation may be responsible for that. Specimen/sample characteristics: the specimens received in the hot laboratory are composed of two half shelves, named baseplates, welded on the pipes OD (Fig. 11.31).

1166

11 Atmospheric Corrosion of Stainless Steel

RWST 2 PTR 001 BA

Cable way

Valves PTR 162 VB PTR 163 VB Pipe EAS 009/010 TY Support SG4064

Support SB4031 Not compliant

Tightness opening

Slab

Slab

Rear baseplate

Pipe RIS 210 TY Front baseplate

Support SG4032

Fig. 11.30 Sketch of the containment spray suction lines

Top

Welded rear baseplate

Welded rear baseplate

Dent Shallow dent

Discontinuous weld

Bottom

Discontinuous weld

Fig. 11.31 Left: OD of the 2EAS009TY pipe, view of the rear baseplate. Right: OD of the 2EAS010TY pipe, view of the rear baseplate

11.2

Destructive Examinations Results and Remediation

SIS line

1167

Spray suction lines 2EAS009TY and 2EAS010TY

Fig. 11.32 View of the leaks of the containment spray suction lines 2EAS009TY and 2EAS010TY

The baseplate weld is discontinuous. It is in this area of discontinuous weld that boric acid leaks have been observed (Fig. 11.32). DE goal and program: leak rot cause analysis. Results VT On the 2EAS099TY pipe segment, two leaks have been observed. The ID reveals the presence of pits alignments in the vicinity of the weld. Rust-like zones start from these alignments (Fig. 11.33). At higher magnification, these zones reveal circumferential micro-cracks with corrosion products around them (Fig. 11.34). On the OD after the baseplate removal, a thick and dense oxides deposit is visible close to the weld and associated with pits (Figure 11.35). The baseplate and the pipe walls both suffer from radial cracking (Fig. 11.36). The pipe OD, out of the baseplate area, is free of cracking. Similar observations can be made on the 2EAS010TY pipe segment with similar ID defects but only on the rear baseplate (Fig. 11.37). The higher magnification observation of the rear baseplate ID defects reveals the presence of white boric acid deposits (Fig. 11.38). Micro-cracks are associated with these deposits. After removal of the two baseplates, the OD behind them shows a thick and tenacious oxides deposit in the vicinity of the weld. On the pipe OD, at the rear baseplate location, cracks are visible (Fig. 11.39), whereas at the front baseplate location, pits are visible but no through wall crack.

1168

11 Atmospheric Corrosion of Stainless Steel

Weld and HAZ Pits alignments

Specimen (EDS)

Specimen Specimen

Front base plate

Dented area

Rear baseplate

Fig. 11.33 ID of the 2EAS009TY pipe, view of the front (left) and rear (right) baseplates locations. Red dotted line = cuts. Red star = OD leak location

Crack ~ 14 mm long

Specimen

Crack Micrography, axial section

Micrography section

Specimen

EDS specimen Specimen

Fig. 11.34 2EAS009TY, view of specimens 1, 2 and 3

11.2

Destructive Examinations Results and Remediation

1169

Towards the weld Towards the weld Deposits and oxides Deposits and oxides

Fig. 11.35 2EAS099TY. Left: OD deposits, pipe side. Right: ID deposits, baseplate side

Baseplate

Gap Cracks

Pipe

Fig. 11.36 2EAS009TY. View of the pipe/baseplate interface on a cross section

Weld and HAZ

Specimen

Pits alignments

Dented area

Fig. 11.37 ID of the 2EAS010TY pipe segment. Left: front baseplate (leak tight). Right: rear baseplate (leaking). The red star points at the OD leak location

1170

11 Atmospheric Corrosion of Stainless Steel

Towards weld

Z1 zone

Cracks

Fig. 11.38 ID of 2EAS010TY pipe segment. Left: micro-cracks with ferritic corrosion products around them. Right: high magnification view of specimen 4 in the cross-section area (Z1 zone)

Crack

Crack

Crack

Fig. 11.39 2EAS010TY. OD view in the Z1 zone with multiple cracks

11.2

Destructive Examinations Results and Remediation

1171

Metallography 2EAS009TY SEGMENT A first section was performed perpendicularly to the linear defect  (see location on Fig. 11.33 left). This section captures both the pipe and the baseplate at the weld location, the gap between these two materials has been assessed to 0.15 mm (6 mils). Micrography shows multiple pipe cracks (Fig. 11.40). The cracks are OD initiated, inside the pipe/baseplate gap, from corrosion pits, and propagate through wall (Figs. 11.41 and 11.42). Some cracks also initiate at the baseplate ID.

Weld Baseplate

Pipe

ID

Fig. 11.40 2EAS009TY. Cross section

Fig. 11.41 2EAS009TY. Pipe OD cracking

1172

11 Atmospheric Corrosion of Stainless Steel

Fig. 11.42 2EAS009TY. Z1 initiation zone (gap)

Fig. 11.43 2EAS009TY. Left: other crack initiation at the pipe OD. Right: zone 2 observation

Propagation is transgranular and branched, typical from chloride-induced SCC (Figs. 11.43 and 11.44). An axial section (specimen ②, Fig. 11.33 right) has been performed through a through-wall crack. Multiple transgranular and branched cracks are observed (Figs. 11.45 and 11.46).

11.2

Destructive Examinations Results and Remediation

Fig. 11.44 2EAS009TY. Zone 3 observation

Fig. 11.45 2EAS009TY. OD initiation, oxidized and branched cracks

Fig. 11.46 2EAS009TY. Branched and transgranular crack, 10% oxalic acid etching

1173

1174

11 Atmospheric Corrosion of Stainless Steel

2EAS010TY SEGMENT Similar results have been observed on the 2EAS010TY segment. EDS analyses EDS analyses have been carried out on the specimen ③ of the 2EAS009TY pipe; both OD and ID deposits have been analysed. A significant chloride pollution has been evidenced on the OD whereas no such pollution has been observed at the ID. Microprobe analyses Chlorides have been observed in the OD deposits and into the cracks. Hardness measurements HV0.5 have been carried out at the OD, into the bulk and at the ID in three different zones: free span, and cracked zone on the pipe 2EAS009TY and into the cracked zone of pipe 2EAS010TY, the results are reported in the Table 11.1. The typical hardness for 304L SS is in the 160–180 HV0.5 range. The surface hardness is significantly superior to the bulk hardness, likely as the result of surface cold-work. Table 11.1 Hardness measurement results

Mean HV0.5

2EAS009TY—Free span

2EAS009TY—Cracked zone

2EAS010TY—Cracked zone

OD Bulk ID 189 158 193

OD Bulk ID 181 155 194

OD Bulk ID 173 147 216

11.2

Destructive Examinations Results and Remediation

1175

Conclusion The results call for cracking under SCC in an oxidizing environment (oxygen presence) polluted with chlorides. This deleterious environment started to initiate OD pits at the pipes surface, behind the baseplates which are confined areas. Then SCC initiated at the bottom of some of these pits in a very acidic environment, until through wall at some locations, thus generating leaks. Along with the previous example, here is a second case of SCC initiated at low temperature (less than 50 °C–122°F), although SCC initiation models predict initiation times would be extremely long at such low temperature. Only a very harsh environment, as the one that can exist at the bottom of pits, can explain such deviations to the usual models.

11.2.7 Destructive Examination of a Valve Nut Plant main characteristics: B&W PWR, 850 MWe, 2 loops, USA. Equipment/Component: RCS, valve LP-20, nuts. The nuts are likely made of 303 SS (C: < 0.15 Wt%, Cr: 17–19 Wt%, Ni: 8–10 Wt%, Mn: < 2 Wt% and Si < 1 Wt %). Operating conditions: the LP-20 valve serves as the reactor building emergency sump isolation valve; it is located in an enclosure in a pump room at ambient temperature. Time of operation: about 29 years. Failure discovery: during a maintenance disassembly of valve 3LP-20, several of the nuts on body-to-bonnet studs were found to contain cracks. One nut had fractured completely. Specimen/sample characteristics: one broken nut was sent to the laboratory for DE. DE goal and program: the goal of this DE was failure root cause analysis. The program included: VT, micrography, SEM and EDS analysis. Results The nominal 1″ (25.4 mm) nut was 0.84″ (21.3 mm) tall and 0.94″ (23.9 mm) on the ID. The nut had no markings but appeared to have been machined from hex-shaped bar; the flats had a matte finish while the faces were bright. A section encompassing * 90° had fractured out of the nut (Fig. 11.47). The nut had sprung apart where fractured, as the remaining flats were no longer parallel. Additional axial cracks were visible on the internal threads (Fig. 11.47); these cracks did not penetrate to the OD surface but were visible on the end faces. The fracture surfaces were darkly oxidized and showed some rust-colored deposits as well.

1176

11 Atmospheric Corrosion of Stainless Steel

Fig. 11.47 Left: fractured stainless-steel nut from valve LP-20, as received. Other cracks are visible on end face. Right: interior of fractured nut showing additional axial cracks visible on threads. Fracture surfaces are darkly discolored and have some rusty deposits

Fig. 11.48 Valve LP-20. SEM photo of fracture surface showing intergranular morphology, typical of most visible areas

SEM examination of one of the fracture surfaces showed it to be intergranular (Fig. 11.48). A cross-section through one of the axial cracks confirmed the crack path to be intergranular and branched (Fig. 11.49). The austenitic microstructure showed carbide decoration on the grain boundaries throughout the entire nut, indicating the material to be in a sensitized condition (Fig. 11.50). The material contained a large quantity of manganese sulfide inclusions and so was probably a Type 303 free-machining stainless steel. EDS of the fracture surfaces showed elevated sulfur in many locations, both on the fracture and on the threads. Some areas were enriched in manganese. Both of these concentrations may be due to selective corrosion of the manganese sulfide inclusions.

11.2

Destructive Examinations Results and Remediation

1177

Fig. 11.49 Valve LP-20. Left: cross-section through crack showing it to extend from inner threads (bottom) toward OD flat. Crack is intergranular and heavily branched. Right: detail of crack tip showing branched intergranular cracks. Oxalic acid etch

Fig. 11.50 Valve LP-20. Detail of microstructure showing discrete carbides on the grain boundaries. This structure was seen throughout the nut

1178

11 Atmospheric Corrosion of Stainless Steel

Sensitization of stainless steel occurs due to the precipitation of chromium carbides along the grain boundaries, which results in a depletion of chromium in the adjoining matrix. This chromium depletion renders the material susceptible to intergranular corrosion. Sensitization occurs at temperatures of 900–1500 °F (482– 816 °C); as this valve operated at ambient conditions, the sensitization of the nut(s) must have occurred at some point during their fabrication. In the presence of a sustained tensile stress, attack occurs in the form of intergranular SCC, as was observed here. The nut contained significant residual tensile stress, as evidenced by its tendency to spring apart after fracture. The torque applied to the nut also produces a tensile stress; however, the nuts were not necessarily over torqued. Any other stainless-steel nuts on this valve which were also machined from this susceptible material will likely also be cracked. Conclusion The valve nut cracked from SCC. The combination of high tensile stresses, material sensitization and high sulfur content governed the nut cracking.

Reference Cattant, François. 2014. Materials ageing in light water reactors—Handbook of destructive assays, Lavoisier Editions.

Chapter 12

Hydrogen Embrittlement

12.1

Background

Hydrogen embrittlement can lead to failure. Hydrogen embrittlement induced rupture is one of the multiple mechanisms of corrosion (see Sect. 12.3). Although many various components have failed following material hydrogen embrittlement, the most spectacular cases encountered in EDF PWRs were in big components tie rods. Some examples of failed tie rods are presented here in a chronological order as they occurred. A general conclusion/remedial actions paragraph will conclude this chapter.

12.2

Destructive Examinations of Tie Rods and Remediation

12.2.1 Destructive Examination of 2 Failed RHR Supporting Tie Rods Plant main characteristics: Framatome PWR, 1300 MWe, 4 loops, France. Equipment/Component: RHR support tie rods. Operating conditions: atmospheric environment. Unit time of operation: 10,862 h. Failure discovery: following an RHR tie rod rupture on one of the 4 loop units, it was decided to inspect these tie rods on all similar units (20). The 2 broken tie rods of this DE were found during an outage walk-down. © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_12

1179

1180

12 Hydrogen Embrittlement

Similar event frequency: around 100 big component tie rods ruptures in the French PWR fleet. Specimen/sample characteristics: tie rod dimensions: length = 1800 mm (71’’), diameter = 56 mm (2.2’’); material = 35 NCD 16 (C: 0.32/0.39; Ni: 3.6/4.2, Cr: 1.6/2; Mo: 0.25/0.45 Wt%). DE program and goal: failure root cause analysis. Results Both tie rods are broken in the threaded area, probably at the first loaded thread (Fig. 12.1, left picture). There is no apparent necking. On both fracture surfaces, corrosion initiated in a soft area, with an elliptical shape (lunule, Fig. 12.1, right picture). Rupture propagated radially from this area, with a rougher surface than in the initiation zone. The small size of the soft surface as compared to the rough surface shows how high was the axial load (initial pre-stress = 133,000 daN) of these tie rods.

Initiation site

1 cm

Initiation 5 mm

Fig. 12.1 RHR supporting tie rod. View of the fracture surface. The initiation zone (lunule) is clearly visible (bottom left of right picture)

12.2

Destructive Examinations of Tie Rods and Remediation

1181

Pit

Fig. 12.2 RHR supporting tie rod. SEM view of the fracture initiation zone. A pit is visible at the periphery

Fig. 12.3 RHR supporting tie rod. SEM view of the fracture initiation zone (left) and of the final rupture (right)

Figure 12.2 shows that corrosion initiated at a pit. Figure 12.3 shows that corrosion is intergranular whereas final rupture is ductile. In the initiation zone, Fig. 12.4 shows the presence of cavities at grain boundaries; this particular feature is typical of hydrogen embrittlement. Microanalysis reveals an intergranular surface pollution with Si, Mo, Ca, Zn, and S, all elements that can be found in some of the grease used for tie rods installation. A section of the initiation zone, in the middle of the pit observed on Fig. 12.2, shows that this pit is 170 µm (6.7 mils) deep (Fig. 12.5). Oxide thickness ranges from 20 (0.8 mil) to 50 µm (2 mils) depending on the location. The tie rods structure is martensitic (Fig. 12.6).

1182

12 Hydrogen Embrittlement

Fig. 12.4 RHR supporting tie rod. SEM views of some typical features of hydrogen embrittlement

Rupture face

100 µm

Thread side

170 µm

Fig. 12.5 RHR supporting tie rod. Micrograph taken at the edge of the initiation zone. Nital etch

Fig. 12.6 RHR supporting tie rod. Bulk material martensitic structure. Nital etch. HV10 = * 450

10 µm

12.2

Destructive Examinations of Tie Rods and Remediation

1183

Hardness, irrespective of the location (surface or bulk), is very homogeneous: 453–459 HV10, with an average of 458 HV10. According to AFNOR A03 173 standard, these figures correspond to UTS of 1400 and 1610 MPa respectively, for 1180–1380 MPa specified (NFA 35 557 standard). In conclusion, the root cause of these tie rod failures is SCC induced by hydrogen embrittlement initiated on a pit. The likely source of hydrogen is corrosion; a source of water could be condensation.

12.2.2 Destructive Examination of Failed Reactor Pit Aseismic Blocks Tie Rods Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: reactor pit aseismic blocks tie rods. The cylindrical concrete structure supporting the RPV could move in an earthquake. To prevent any displacement, this structure is held in place by blocks which are tied to the containment building base slab (Fig. 12.7). In the slab, the upper length of the tie rod runs in a metallic threaded sleeve. 3 loop units have 18 or 19 of such blocks, each being equipped with 8 tie rods. Some of the tie rods attaching these aseismic blocks to the base slab have been found broken. Operating conditions: atmospheric environment. Time of operation: from 64,552 to 104,493 h, depending on which of the 4 units is considered.

Fig. 12.7 Reactor pit aseismic blocks tie rods. View of block #14

1184

12 Hydrogen Embrittlement

Failure discovery: EDF civil engineering maintenance policy calls for checking tie rods upper nut torque. If the torque is too low, the nuts are re-tightened. During this maintenance work, some tie rods have been found broken either before re-tensioning or after. Similar event frequency: a least 11 tie rods from 4 different units of the EDF PWR fleet have been found broken. Specimen/sample characteristics: most of the tie rods are 36 mm (1.42’’) in diameter. Their pre-stress is 70,000 daN. The tie rods are entirely covered with grease. The tie rods are made of LAS (AFNOR 65 SMC 4, C: 0.63; Si: 1.1, Mn: 1.1; Cr: 0.6 Wt%). DE program and goal: failure root cause analysis. Results The grease chemical analysis reveals low sulfur and chloride contents. The tie rod surface is oxidized but without major general corrosion. Except one, all ruptures are localized below the threaded sleeve (a few mm to several hundred mm, Fig. 12.8). Fracture surfaces are plane and oxidized; no necking is observed (Fig. 12.8). Fracture has propagated radially from one or more initiation sites. Initiation sites have an elliptical shape (lunule), are millimeters in dimensions and appear darker than their surroundings because they are more oxidized (Fig. 12.9). Sometimes, corrosion initiates from a pit on the tie rod surface. SEM examination of the fracture surface provides the following: • The very beginning of the initiation zone does not show any recognizable feature (left picture of Fig. 12.10); • Some tie rods exhibit pits. As the result of severe ferrite phase attack, lamellar perlite prints are visible (right picture of Fig. 12.10); • The lunule tip exhibits transgranular propagation; • The final rupture is 100% transgranular (Fig. 12.11); • The rupture faces are highly oxidized which implies tie rods did not fail recently. Despite attempts to remove the surface oxide, some areas are still covered with a thick oxide layer (Fig. 12.12). Secondary wide open and oxidized cracks run parallel to the main rupture surface (Fig. 12.12). These cracks propagation is transgranular and they correspond to the final rupture cleavages (Fig. 12.12). The structure is perlitic (Fig. 12.13). On some tie rods, secondary cracks have initiated just below the rupture surface (Fig. 12.14). These cracks are shallow (0.5 mm, 0.02’’ deep) and full of oxide. Microanalysis in the initiation zone reveals the presence of Cl, Ca, and S. Elements Ca and S are likely residues of the grease used. Even after severe cleaning, Cl and S are still present. Mean bulk material hardness ranges from 357 to 377 HV2, depending on the tie rod.

12.2

Destructive Examinations of Tie Rods and Remediation

1185 Initiation site

Threaded sleeve

Initiation site

5 mm

1 mm

1.9 mm

Fig. 12.9 Reactor pit aseismic blocks tie rods. View of 2 ruptures initiation sites (lunules)

0.7 mm

1.1 mm

2 mm

0.5 mm

Fig. 12.8 Reactor pit aseismic blocks tie rods. View of the fracture surface of 2 broken tie rods

1186

12 Hydrogen Embrittlement

Fig. 12.10 Reactor pit aseismic blocks tie rods. SEM view of an initiation site. Right picture: view of lamellar perlite print after selective attack of the ferrite

Fig. 12.11 Reactor pit aseismic blocks tie rods. SEM view of brittle final rupture

200 µm

100 µm

Fig. 12.12 Reactor pit aseismic blocks tie rods. Fracture cross section. Left: area still covered with thick oxide and with secondary cracks running parallel to the surface. Right: secondary cracks transgranular propagation. Nital etch

12.2

Destructive Examinations of Tie Rods and Remediation

1187

Fig. 12.13 Reactor pit aseismic blocks tie rods. SEM view of the ferrite-perlite structure

100 µm

Main fracture surface

300 µm

Fig. 12.14 Reactor pit aseismic blocks tie rods. Surface secondary cracks initiation

Some mechanical testing was performed with the following results: • Tensile tests at room temperature: YS = 1,100 MPa; UTS = 1,210 MPa; uniform elongation = 6%, total elongation = 12%, necking = 32%. Contrary to the field ruptures, significant necking is observed. The rupture face is ductile with some transgranular cleavage zones. • Impact tests at room temperature: energy = 0.63 daJ/cm2; 100% brittle aspect (cleavage); lateral expansion = 0.05 mm (2 mils). This material is fragile. • Tensile tests on specimen with 0.3 mm (notch radius = 0.25 mm) and 1 mm (notch radius = 0.15 mm) deep notches (respectively: 0.012, 0.01, 0.04, and 0.006’’). For both specimens, the rupture is fragile (cleavage) without any necking.

1188

12 Hydrogen Embrittlement

• Toughness tests at room temperature: K1C = 33 MPa√m; this low figure confirms how susceptible to a notch this material is. Given the material properties and the pre-stress, it was calculated that the critical semi elliptic flaw was less than 2 mm deep (0.08’’). In conclusion, the failure mechanism was the following: • • • •

Localized corrosion (pit) at the tie rod surface with hydrogen generation; Hydrogen embrittlement; SCC initiation in the brittle zone; Mechanical brittle rupture by cleavage once the SCC flaw reaches the critical size.

12.2.3 Destructive Examination of Steam Generator Support Leg Tie Rods: Example #1 Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: steam generators, tie rods attaching the support legs to the concrete slab (Fig. 12.15). Operating conditions: containment building atmospheric environment. Unit time of operation: 160,000 h. Failure discovery: during a forced outage walk-down, the lower end of a SG support leg tie rod was found on the floor. The entire tie rod was sent to the laboratory for destructive examination. Similar event frequency: a small number of systems or components tie rods have been found broken in the French fleet. Specimen/sample characteristics: the tie rods are 76 mm (3’’) in diameter and 2.28 m (89.8’’) long. Their pre-stress is 180,000 daN. The tie rods are made of LAS (AFNOR 35 NCD 16, C: 0.32/0.39; Ni: 3.6/4.1; Cr: 1.6/2.0; Mo: 0.25/0.45; Mn: 0.2/0.6; Si: 0.10/0.40 Wt%). DE program and goal: tie rod failure root cause analysis. Results The tie rod surfaces in contact with the containment building atmosphere are covered with rust type oxide (Figs. 12.16 and 12.17). The tie rod length in the slab also exhibits traces of oxidation (Fig. 12.17). The washer surface in contact with the support plate is also oxidized (Fig. 12.18). The corrosion is more severe in a circle corresponding to the slab hole

12.2

Destructive Examinations of Tie Rods and Remediation

1189

Support plate

Concrete slab

Support plate Washer Support leg Support plate

Fig. 12.15 PWR. Left: SG and RCP support legs. Right: tie rods attaching the support legs to the concrete slab

diameter which means that a deleterious environment has developed in this annulus (Fig. 12.19). The rupture surface is plane and oxidized (Fig. 12.20). Two corrosion initiation sites (“L1” and “L2”, located almost 90° from each other are visible. The mechanical fracture initiated and expanded radially from initiation site “L1”. Both initiation sites are associated with pits. Cross sections show how plane is the rupture and that corrosion initiated from pits. In the initiation zone, shallow (2 mm/0.08’’ deep) strongly oxidized cracks are visible (Figs. 12.21 and 12.22). In this corrosion initiation zone, crack propagation is intergranular (Fig. 12.22). The structure is tempered martensite. Despite severe cleaning, the initiation zone remains covered with thick oxide (Fig. 12.23). However, secondary cracks can be observed. At the transition zone

1190

12 Hydrogen Embrittlement

5 mm

3 mm

Fig. 12.16 SG support leg attachment tie rod. View of the upper end

10 cm

2 cm

5 mm

Fig. 12.17 SG support leg attachment tie rod. View of the lower broken end

between corrosion and mechanical fracture, 3 types of surfaces are observed: (I) intergranular (majority), (II) transgranular (with cleavage, minority) and (III) small ductile ligaments on some grain faces (Fig. 12.23). These features are typical of SCC induced by hydrogen embrittlement. The final mechanical rupture is all ductile with cupules. The mean tie rod hardness is 417 HV30, which is consistent with the expected result for this type of steel (maximum: 640 HV).

12.2

Destructive Examinations of Tie Rods and Remediation

1191

2 cm

Fig. 12.18 SG support leg attachment tie rod. View of the upper face of the lower washer

3 mm

Fig. 12.19 SG support leg attachment tie rod. Washer detail pointed at by a black arrow on the previous figure

In conclusion, the tie rod failed by hydrogen induced SCC, the failure mechanism was the following: • • • •

Localized corrosion (pit) at the bottom of a thread with hydrogen generation; Hydrogen embrittlement; SCC initiation in the brittle zone and propagation; Final ductile rupture once the SCC flaw reaches the critical size.

1192

12 Hydrogen Embrittlement

1 cm

Fig. 12.20 SG support leg attachment tie rod. Rupture surface. Two initiation sites are visible (L1 and L2) located almost 90° from each other

2 mm

Fig. 12.21 SG support leg attachment tie rod. Rupture upper surface cross section “A” (see location on Fig. 12.20)

12.2

Destructive Examinations of Tie Rods and Remediation

1193

100 µm

Fig. 12.22 SG support leg attachment tie rod. High magnification of details #1 and #2 of Fig. 12.21

Fig. 12.23 SG support leg attachment tie rod. SEM views of the initiation zone (left) and of the transition zone between corrosion and mechanical fracture (right)

12.2.4 Destructive Examination of Steam Generator Support Leg Tie Rods: Example #2 Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: steam generators, tie rods attaching the steam generators legs locking devices to the concrete slab. The tie rods are inserted in sleeves. Operating conditions: containment building atmospheric environment, 40 °C (104°F) and 30% humidity in operation. Unit time of operation: over 290,000 h. These tie rods have been installed before commissioning (July 31st, 1979). Failure discovery: following several tie rods failures around year 2000, decision was made to replace them with zinc coated tie rods. The tie rods of this unit have not been replaced and instead wax injection was attempted in the sleeves in 2011.

1194

12 Hydrogen Embrittlement

However, because of a leak, this injection was reported first to 2013, then to 2014. In February 2013, 13 tie rods have been harvested for investigation and replaced with coated tie rods. 34 other tie rods could not be replaced with new tie rods. Similar event frequency: a small number of systems or components tie rods have been found broken in the French fleet. Specimen/sample characteristics: 3 tie rods have been received in the laboratory; each being cut in 3 pieces about 70 cm (27.6’’) long. The tie rod AGV1 A1 exhibits many corrosion pits in the free span and in the threads: pieces 1, 2, and 3. The tie rod AGV2 H1 exhibits corrosion pits in the freespan and in the threads along with a linear indication by magnetic particle testing: pieces 7, 8, and 9. The tie rod AGV2 H2 shows the highest hardness: pieces 4, 5, and 6. The tie rods are 52 mm (2.05’’) in diameter and 2.2 m (86.6’’) long. The tie rods are made of LAS (AFNOR 35 NCD 16, C: 0.32/0.39; Ni: 3.6/4.1; Cr: 1.6/2.0; Mo: 0.25/0.45; Mn: 0.2/0.6; Si: 0.10/0.40 Wt%), with a tempered martensitic structure. The tie rods have been brushed to remove superficial oxidation. DE program and goal: the goal of this destructive examination is to make a condition assessment of the 34 tie rods left in place. Results Structure and chemical composition. The tie rods structure corresponds, as expected, to tempered martensite (Fig. 12.24). The chemical composition of the 3 tie rods meets the specification of the 35 NCD 16 steel. Tensile tests The tensile tests results are in accordance with the French standard NF A35-557– 1975 for the 35 NCD 16 steel (Table 12.1). Fig. 12.24 Typical tie rods bulk structure (nital 2% etching)

12.2

Destructive Examinations of Tie Rods and Remediation

1195

Table 12.1 Mechanical properties of the 3 tie rods, room temperature (25 °C–77 °F). Tie rod

YS (MPa)

UTS (MPa)

Elongation (%)

Reduction area (%)

AGV1 A1 AGV2 H2 AGV2 H1 Standard

1130 1160 1051 Min.: 930

1235 1275 1164 1080 - 1370

14 15 15 Min.: 11

57 58 62

Hardness measurements Hardness line scans have been performed on a diameter of the tie rods. HV10 mean values are 391, 398, and 364 respectively for tie rods AGV1 A1, AGV2 H2 (Fig. 12.25) and AGV2 H1. The tie rods hardness meets the specifications. The hardness in the centre of the tie rods is slightly inferior to the hardness close to the surface. This is due to the tempering process where the surface cooling is faster than the bulk cooling. VT and PT A VT has been performed on the tie rods in the as-received condition. The Fig. 12.26 shows, as an example, the tie rod AGV1 A1. The following surface defects have been observed: • On the free span, multiple corrosion pits which can be either isolated (Fig. 12.27 left) or clustered (Fig. 12.27 middle). The tie rod AGV1 A1 has the most pits whereas tie rod AGV2 H2 has very few pits. About 150 mm (6’’) long spiral alignments of pits have been observed on tie rods AVG1 A1 and AGV2 H1 (Fig. 12.27 right), without any explanation so far.

Hardness 10 kgf

• Regarding threads, only tie rod AGV1 A exhibits corrosion (Fig. 12.28). In 3 zones, the threads have been corroded over almost their entire height. Corrosion products are found at the bottom of the threads, however, as compared to the free span, pits are less abundant and shallower.

Distance over the diameter Fig. 12.25 HV10 line scans (averaged on 3 nearby diameters) on the tie rod AGV2 H2

1196

12 Hydrogen Embrittlement

Fig. 12.26 View of tie rod AGV1 A1. Top: piece 1, 0°. Middle: piece 2, 0°. Bottom: piece 3, 0°

Fig. 12.27 Tie rod AGV1 A1, specimen 31. Left: isolated pits. Middle: pits cluster. Right: spiral of pits

Fig. 12.28 Tie rod AGV1 A1, view of threads corrosion

12.2

Destructive Examinations of Tie Rods and Remediation

1197

The 3 tie rods PT did not reveal any linear indication that could be related to SCC crack; only corrosion pits have been observed. 3D topography 3D topography measurements allowed to determine pits depth. Mean pits depth is 266 µm (10.5 mils) and maximum pits depth is 536 µm (21.1 mils). Micrography Pits cluster, specimen 31-D In the corrosion pits area, elongated defects, with a maximum depth of 900 µm (35.4 mils) and 80 µm (3.1 mils) wide are observed (Fig. 12.29 left). These elongated defects seem to have initiated at pits bottom and propagated perpendicular to the surface. These defects are filled with oxides. Successive polishing steps show that these defects are plan and perpendicular to the tie rod axis (Fig. 12.30). The minimum length of these defects is 1.2 mm (47 mils) in a plan perpendicular to the tie rod axis.

Fig. 12.29 Tie rod AGV1 A1. Left: view of the specimen 31-D section. Middle: specimen 31-R defect. Right: specimen 11-M thread bottom

Defect 2

Depth

Depth

Depth Depth

Depth

Depth

Fig. 12.30 Tie rod AGV1 A1, specimen 31-D. Aspect of the defect 2 after successive polishing steps, from left to right: 0 µm, −140 µm (5.5 mils), −260 µm (10.2 mils), −380 µm (15 mils), −490 µm (19.3 mils) and −620 µm (24.4 mils).

1198

12 Hydrogen Embrittlement

Isolated pit, specimen 31-R Shallow defects are visible at the bottom of this pit (Fig. 12.29 middle). The origin of these defects remains unknown: either a pit extension or small pits initiated at the bottom of the larger one. Deteriorated threads, specimen 11-M The Fig. 12.29 right shows a thread much wider at the top than initially whereas there is little corrosion at the bottom. No crack has been detected. As expected, given the threads are rolled, the threads surface is strongly cold worked (Fig. 12.31). The magnetic particles test linear indication discovered on the tie rod AGV2 H1 corresponds to a scratch full of oxides (Fig. 12.32). SEM SEM examination was performed on specimen 31-D in order to track active cracks. The examination shows (Fig. 12.33): • All defects are quite linear and perpendicular to the surface, they are branched beyond 0.6 mm (24 mils) deep; • The defects are full of oxides 80 to 100 µm (3 to 4 mils) wide; • Oxidation increases at the crack tip through a network of fine penetrations a few dozens to a few hundred microns deep (Fig. 12.34 left), which is consistent with a slow propagation; • No active SCC crack has been observed; • Crack tip EDS analyses reveal the presence of Fe, Cr, Ni and Mo elements in the matrix and the same oxidized elements in the oxidized zones; • No pollution is found in the cracks, S and Mo having overlapping energy peaks; • An EDS mapping shows Cr stratification at crack tip (Fig. 12.35).

Fig. 12.31 View of the surface cold work at the bottom of the threads (Nital 2% chemical etching)

12.2

Destructive Examinations of Tie Rods and Remediation

1199

Magnetic particles test indication

Fig. 12.32 Tie rod AGV2 H1, cross section of the magnetic particles test linear indication: scratch full of oxides

Gold deposit

Silver paint

Fig. 12.33 Tie rod AGV1 A1, SE observation of specimen 31-D (pits cluster)

1200

12 Hydrogen Embrittlement

Fig. 12.34 Tie rod AGV1 A1, specimen 31-D, SE observation of a crack tip

Fig. 12.35 Tie rod AGV1 A1, specimen 31-D, EDS mapping of a crack tip

Conclusion The destructive examination of 3 SG tie rods shows: • The material meets the specification; • The mechanical properties are rather high despite meeting the specification, which makes them more susceptible to SCC; • Pits are everywhere, with the tie rod AGV1 A1 being the most affected. Pits max. depth is about 500 µm (20 mils); • The shank of tie rod AGV1 A1 exhibits old entirely oxidized SCC cracks that had initiated at the bottom of pits. The absence of fresh crack shows that crack propagation had almost or completely stop: • The deepest defect is 906 µm (35.7 mils) deep and 100 µm (4 mils) wide; • The magnetic particles test linear indication corresponds to an oxidized scratch.

12.2

Destructive Examinations of Tie Rods and Remediation

1201

All these results are in accordance with the previous field experience. The rounded tip of the defects is consistent with a sleeping old crack. However, should the conditions change (environment and stresses), then any re-activation of these crack should be considered. We cannot rule out that several “finger gloves” defects initiated at the bottom of the same pit could one day merge in a single much larger defect. Last, the threads bottom does not appear as being significantly prone to SCC initiation as no SCC crack has been evidenced in any of the 3 tie rods examined; rolled threads could explain this.

12.2.5 Destructive Examination of Reactor Cooling Pump Support Leg Tie Rods Plant main characteristics: Framatome PWR, 900&1300 MWe, 3&4 loops, France. Equipment/Component: reactor cooling pumps, tie rods attaching the support legs to the concrete slab (Fig. 12.15). Operating conditions: containment building atmospheric environment. Unit time of operation: from 90,220 to 192,000 h, depending on which of the 4 units is considered. Failure discovery: following the rupture of a SG tie rod (see previous destructive examination), a vast inspection program of similar tie rods was launched. NDE (Magnetic Particle Testing) indications have been found on some RCP support leg tie rods. Several of these tie rods have been harvested for destructive examination. Similar event frequency: several RCP tie rods have exhibited NDE indications. Specimen/sample characteristics: the tie rods are 76 mm (3’’) in diameter and 2.28 m (89.8’’) long. Their pre-stress is 180,000 daN. The tie rods are made of ASME SA540 B24 (AFNOR 40 NCD 7.03, C: 0.35/0.46; Ni: 1.60/2.05; Cr: 0.65/ 1.00; Mo: 0.28/0.42; Mn: 0.65/0.95 Wt%) or AFNOR 35 NDC 16. DE program and goal: NDE indication characterization. Results The upper length of the tie rod of Fig. 12.36 exhibits dark oxide. This tie rod has a 110 mm (4.33’’) long circumferential MPT indication. A cross section of the MPT indication shows the presence of an intergranular crack initiated from a pit (Fig. 12.37). This hydrogen induced SCC crack is 120 µm (4.7 mils) deep.

1202

12 Hydrogen Embrittlement

Fig. 12.36 RCP support leg attachment tie rod. View of the upper end at the 110 mm (4.33’’) long circumferential MPT indication location

20 µm

200 µm

Fig. 12.37 RCP support leg attachment tie rod. Cross section of the circumferential MPT indication. Intergranular crack initiated from a pit. Nital etch

A cross section located 180° apart from the previous cut, reveals the presence of 2 other cracks, also initiated from a pit at the bottom of a thread (Fig. 12.38). The pit is 200 µm (7.9 mils) deep and the cracks are 340 µm (11.4 mils) deep. The tie rod bulk hardness is 323 HV30, which meets the RCC-M2312 ed. 2000 specification for 40 NCD 7.03 Class A steel (275–350 HV). The tensile properties also meet the same code specification: • YS: 886 for 830 MPa minimum; • UTS: 1,033 for 930 MPa minimum; • Elongation: 17% for 13% minimum. In conclusion, the MPT indication of this tie rod is SCC induced by hydrogen embrittlement, hydrogen being generated by local corrosion or pitting at the bottom of threads.

12.2

Destructive Examinations of Tie Rods and Remediation

1203

100 µm

1 mm

Fig. 12.38 RCP support leg attachment tie rod. Cross section at 180° of the MPT indication. Cracking initiated from a pit. Nital etch

12.2.6 Conclusion, Remedial Actions Literature data show that tie rods, because of their high YS, may suffer from SCC following hydrogen embrittlement (general corrosion and pitting are potential sources of hydrogen generation). Table 12.2 summarizes the tie rods destructive examinations performed at EDF. Shank ruptures are not impossible but correspond to specific conditions. Tie rods ruptures usually occur in the threads, where the installation and operation stresses peak. No difference can be made between machined and rolled threads. Two types of SCC cracks have been observed: • Intergranular fine cracks (Figs. 12.39, 12.40, 12.41 and 12.42); • “Finger gloves” defects, 50 (2)–100 µm (4 mils) wide which look like old corroded SCC cracks and no active propagation (Fig. 12.43). As proven by tensile tests, the tie rod material (typically: martensitic steel) is very susceptible to notch presence. This explains why cracks are typically found at the bottom of threads and the limited necking of broken tie rods. Some tie rods have been replaced with zinc coated tie rods. To prevent further corrosion, some tie rods’ ends have been protected with wax as shown on Fig. 12.44.

1204

12 Hydrogen Embrittlement

Table 12.2 Summary of tie rods destructive examinations conducted at EDF Defect type

Number of examined tie rods

Location of the defects according to the threads type Machined Rolled Fabrication Shank threads threads unknown

Tie rods with corrosion 36 18 3 (general corrosion or pitting) Tie rods with SCC 24 8 2 Failed tie rods (rupture) 17 2 2 Total 41 22 4 * 3 reactor pit aseismic blocks tie rods broken after re-torqueing; 1 tie deep defect at the rupture location

11

4*

10 4* 9 4* 11 4* rod with a 1 mm (0.04’’)

Fig. 12.39 Intergranular secondary SCC cracks observed on a main steam line tie rod (1991)

Fig. 12.40 Intergranular SCC crack, 2.2 mm (87 mils) long, initiated at the bottom of the threads of a main steam line tie rod (1992)

12.2

Destructive Examinations of Tie Rods and Remediation

1205

Fig. 12.41 Intergranular SCC cracks, 100 (4)–300 µm (12 mils) deep, initiated at the bottom of the threads of a main steam line tie rod (2001)

Fig. 12.42 Intergranular secondary SCC cracks observed on a balance of plant component tie rod (2003)

1206

12 Hydrogen Embrittlement

Fig. 12.43 Left: corrosion pit at the bottom of the threads of a main steam line tie rod (1992). Right: SCC crack, 1.2 mm (47 mils) deep and 120 µm (4.47 mils) wide, observed at the bottom of the threads of a steam generator tie rod (2009).

Fig. 12.44 Tie rods end corrosion protection. ①: Steel tube. ②: Polysiloxane joint. ③: Greased cap. ④ Corrosion protection wax

12.3

Other Destructive Examinations

12.3

1207

Other Destructive Examinations

12.3.1 Failure Analysis of a Double-Headed Stud for EAS Spray Pump Connection in CPR1000+ Nuclear Power Plant Plant main characteristics: CPR1000 PWR, 1080MWe, 3 loops, China. Equipment/Component: Double-headed studs for EAS spray pump connection, DIN 939 M36
110. The material is RCC-M M5110 X6CrNiCu17-04 age hardening martensitic stainless steel. Operating conditions: Normal temperature, atmospheric environment. Time of operation: engineering stage, not in operation. Failure discovery: The studs fractured under static load after installation, and visual examination showed brittle fracture. Specimen/sample characteristics: After the installation of the connecting stud for EAS spray pump, one of the studs broke. SNPI was commissioned to perform physical and chemical examinations on 4 studs, including failed ones. Results Macrophotograph of the studs is shown in Fig. 12.45. The fracture occurred at the thread and the fracture surface was clean and flush, and there is no obvious plastic deformation. The fracture surface is crystalline and granular, with radial pattern flow from the center to the surroundings. There is a small area of cutting lip on the outside edge. The proportion of the central and radial pattern accounts for more than 90% of the total area of the fracture, which has proved that the fracture is brittle.

Fig. 12.45 Macrophotograph of studs. Left: from left to right, #1 to #7. Right: #1 fracture surface

1208

12 Hydrogen Embrittlement

Table 12.3 Chemical composition examination results Number

Chemical composition wt% 

Cr

Ni

Cu

V

H

0.006

16.46

3.95

3.49

0.30

0.00046

0.007

17.10

3.95

3.54

0.32

0.00012

0.020

15.50– 17.50

3.00– 5.00

3.00– 5.00

0.15 – 0.45

/

C

Si

Mn

P

S

1#

0.045

0.50

0.61

0.023

2#

0.042

0.34

0.61

0.020

RCC-M M5110 X6CrNiCu17-04

0.07

1.00

1.00

0.025

The chemical composition examination results are shown in Table 12.3. The results show that the chemical composition of the fractured stud meets the standard requirements, but the hydrogen content of the fractured stud #1 is significantly higher than the stud #2. The tensile test results are shown in Table 12.4. The results show that the tensile strength and yield strength of sample #3 meet the standard requirements for the corresponding steel type at room temperature, but the elongation and reduction area lower than the standard requirements. The tensile strength and yield strength of the sample #4 meet the standard requirements at 350 °C (662 °F). The impact test results are shown in Table 12.5. The results show that the impact results of studs #1 and #3 are lower than the standard requirements. Stud #4 impact result meets the standard requirements. The hardness test results are shown in Table 12.6. The results show that the Brinell hardness values of all the studs meet the standard requirements, but the Brinell hardness values of studs #1 and #3 are significantly higher than the lower limit specified by the standard. Figure 12.46 shows the metallographic structure of the cross section and Table 12.7 shows the energy spectrum analysis result in the segregation region. The results reveal that the microstructure of stud 1# is tempered martensite. A significant component segregation zone was found within 1/2 radius on the cross section. Except for that the carbon content in the segregation region is significantly

Table 12.4 Tensile examination results at room temperature and 350 °C (662°F) Number

Yield strength YS/MPa

Tensile strength UTS/MPa

Elongation A/%

Reduction of area Z/ %

Note

#3 RCC-M M5110 X6CrNiCu17-04 #4 RCC-M M5110 X6CrNiCu17-04

970  790

1200  960

9.5  14

20.0  45

Room Temperature

881  630

1083 –

16.5 –

65.0 –

350 °C (662°F)

12.3

Other Destructive Examinations

Table 12.5 Impact test results at 0 °C (32°F).

Table 12.6 Hardness test results

1209

Number

Impact Energy Akv/ J A B C

Average value /J

#1 #3 #4 RCC-M M5110 X6CrNiCu17-04

8.5 9.5 13.5 14.0 82.0 92.0  40 J

8.7 13.8 87.0

8.0 – –

Number

Brinell hardness values /HBW

#1

376.0

376.0

394.6

388.2

Average value 383.7

#2 #3 #4 RCC-M M5110 X6CrNiCu17-04

343.5 373.0 327.0  302

338.6 361.7 327.0 HB

341.0 367.3 336.2

343.5 364.5 331.6

341.7 366.6 330.5

Segregation

Matrix

Fig. 12.46 Microstructure of sample 1#. Top right: microstructure in segregated area. Bottom left: microstructure in normal area. Bottom right: electron spectroscopy analysis area

1210

12 Hydrogen Embrittlement

Table 12.7 Metallographic structure and energy spectrum analysis result of stud #1

Element location

Content wt% C V Cr

Ni

Cu

Fe

Segregation Matrix

6.49 4.72

3.26 3.54

2.74 3.17

70.83 71.87

0.35 0.37

16.32 16.34

higher than that of the matrix, the content of other main elements is basically equivalent to that of the matrix. The SEM morphology of the fracture surface of stud 1# is shown in Fig. 12.47. The fracture surface is relatively flat and without obvious plastic deformation, which reveals that the fracture is brittle. The fracture initiation is located at the center of the stud and cracks extend radially from the center to the edge. The initiation area is a typical rock sugar-like intergranular characteristic, with claws pattern on the crystal surface. The propagation area is mainly intergranular fracture and is accompanied by quasi-cleavage. The final fracture area has small area and displays the dimple fracture. There is no secondary crack in the fracture surface. The fracture is a typical brittle fracture.

Initiation area Final fracture area Propagation area

Fig. 12.47 SEM observation. Top left: full fracture face. Top right: initiation area. Bottom left: propagation area of the fracture. Bottom right: final fracture surface

12.3

Other Destructive Examinations

1211

Conclusions and remedial actions According to the experimental analysis of the broken stud, the stud fractured after installation. The fracture surface is relatively flat, without obvious plastic deformation. The extended radial ridge feature can be seen on the fracture surface. The transition of the fracture microstructure is mainly as follows: intergranular ! intergranular & a small amount of quasi-cleavage ! dimple. No secondary crack has been observed on the fracture surface. The above morphology is consistent with the characteristic of hydrogen embrittlement fracture. In addition, the fractured stud has metallographic structure of martensitic, which is highly sensitive to hydrogen embrittlement. The hydrogen content of the stud is higher with the mass fraction of 4.6
10–4, and hydrogen is easily aggregated in the segregated area. Therefore, the cause of the stud fracturing is hydrogen-induced delayed fracture. Aiming at the characteristics of the high strength, poor toughness, segregation of metallographic structure, and high hydrogen content of failed studs, it is suggested that the inspection of raw materials should be increased, and avoiding the use of the raw materials with segregation as much as possible. By the means described above to ensure the safety of power station operation and to prevent the recurrence of similar accidents. During the production of studs, strictly implementing the dehydrogenation process according to the standard is necessary. On the premise that the strength of studs meets the standard requirements, the strength of studs shall be controlled to close to the lower limit to improve the toughness and impact resistance of studs. At the same time, the mechanical method should be used to clean the surface of the studs, and the acid cleaning method should be avoided to reduce the risk of hydrogen embrittlement. After the stud processing is completed, the studs should be heated in a vacuum furnace or an inert atmosphere for 2–4 h to anneal and to remove hydrogen.

12.3.2 Hydrogen Embrittlement Fracture of Bonnet Studs Plant main characteristics: CPR1000, PWR, 3 loops, China. Equipment/Component: Y4RRI376VN, manual ball valve, TANOWC0050. The 4 studs are used to bolt the valve cover. The design torque is 50 ± 2.5 Nm. Operating conditions: indoor atmospheric environment, room temperature. Time of operation: after initial installation to the end of the first fuel operation cycle. Failure discovery: the staff performed a change operation and found that the Y4RRI376VN valve bonnet was ejected by the medium. Further inspection revealed that the four fastening studs on the valve cover had broken.

1212

12 Hydrogen Embrittlement

Similar event frequency: no. Specimen/sample characteristics: the studs #1 and #2 broke at the thread connection, and the studs #3 and #4 broke at the junction with the nut, and there are traces of paint on the fracture, and corresponding nuts and broken studs are lost. It is shown that the studs #3 and #4 broke earlier than the studs #1 and #2. The stud material is 42 CrMo 4. It is produced in accordance with RCCM M5110, and the surface is nickel plated. All 4 studs were sent to SNPI for a failure analysis. Results No corrosion features are found on the surfaces of all 4 studs. For all the four studs, fracture occurs between the first and second threads, the #1 and #2 studs broke at the lower portion of the polished rod, whereas the #3 and #4 studs broke at the top of the polished rod (Fig. 12.48). Under the SEM (Fig. 12.49), close to the thread root, intergranular fracture with partially formed dimples on the fracture facets can be predominantly seen. Intergranular fracture with partially formed dimples on the fracture facets is a characteristic of hydrogen embrittlement in steels, which indicates that it is caused by the hydrogen embrittlement. There are two metal coatings on the studs. The results of EDAX show that the inner coating is copper and the outer coating is nickel. The total thicknesses of the metal coatings are about 10–2 lm (0.4–0.47 mil), as shown in Fig. 12.50. It can be seen that the location of the cracks is related to the stress state of the stud, as shown in Fig. 12.51. There are two micro-cracks at the thread root near the fracture on the stud #2, near the stud and nut contact area; the crack length is 25 lm (1 mil), while the length of crack at the adjacent the thread root is only 2 mm (0.08’’). The content of Mn of all studs is lower than the minimum value required by RCCM M5110, other alloy elements meet the requirements, as shown in Table 12.8.

Fig. 12.48 Left: studs’ location on the valve; right: cracking location

12.3

Other Destructive Examinations

1213

Fig. 12.49 SEM pictures of the fracture surface showing the intergranular nature of the fracture. From top to bottom: studs #1, #2, #3, and #4

1214

12 Hydrogen Embrittlement

Fig. 12.50 Presence of two metal coatings at the surface of studs

Fig. 12.51 Stud #2. View of two micro-cracks at the thread root near the fracture

The hardness values of all studs are higher than the requirements of the RCCM M5110 (Table 12.9). According to the ISO 18265 standard, the tensile strength (Rm/UTS) values are 1371 MPa (198.9 KSI), 1374 MPa (199.3 KSI), 1352 MPa (196.1 KSI), and 1354 MPa (196.4 KSI), respectively, indicating that the strength of 4 studs reaches the level of high-strength bolts. Table 12.8 Analysis results of the stud’s chemical composition (wt.%) Specimen

C

#1 #2 #3 #4 Specification for 42 CrMo 4

0.38 0.38 0.39 0.38 0.38– 0.48

S 0.003 0.003 0.009 0.003  0.015

Si

Mn

0.21 0.23 0.20 0.22 0.10– 0.40

0.55 0.55 0.54 0.55 0.75– 1.00

P 0.015 0.013 0.016 0.014  0.025

Cr

Mo

0.95 0.97 0.90 0.97 0.80– 1.15

0.15 0.19 0.15 0.15 0.15– 0.30

12.3

Other Destructive Examinations

1215

Table 12.9 Studs Brinell hardness results (HB) Specimen 1#

Test value 434.0

2# 3# 4# Specification for 42 CrMo 4

437.2 427.6 430.8 248 –352

430.8

437.2

Average value 434.0

430.7 424.5 427.6

437.3 430.8 427.6

435.1 427.6 428.7

Conclusion and remedial actions The fracture failure of the bonnet stud is due to the hydrogen embrittlement. The inferior grade of steel used and absence of a heat treatment after coating plating contributed to the failure. The studs do not conform to the design specification RCCM M5110, as these 4 studs are high-strength fasteners. It is now well established that the high-strength fasteners are susceptible to embrittlement by dissolved hydrogen, if a high-strength fastener contains dissolved hydrogen, this can result in immediate fracture at stresses approaching to the fracture stress in the absence of external hydrogen, or it may result in a delayed failure at lower stresses. Internal hydrogen embrittlement results primarily from electroplating. Other sources of hydrogen are the processing treatments such as pickling. Once the high-strength fasteners have been electroplated, a heat treatment must be carried out immediately. All bonnet studs were replaced, and the new studs strictly meet the requirements of RCCM M5110 to prevent failures.

12.3.3 Hydrogen Embrittlement Fracture of Diesel Fuel Filter Screws This destructive examination is reported in the chapter #25 (Balance Of Plant).

12.3.4 Hydrogen Embrittlement Fracture of Seawater Pump Cover Studs This destructive examination is reported in the chapter #25 (Balance Of Plant).

Reference Cattant, François. 2014. Materials ageing in light water reactors—Handbook of destructive assays. Lavoisier Editions.

Chapter 13

Boric Acid Corrosion

13.1

Background

Following the discovery of major losses of ferritic steel observed on several large RCS components (RPV, SG and pressurizer), boric acid corrosion has become a major issue for nuclear operators. The few destructive examinations results presented hereafter help in the understanding of why plants have developed comprehensive boric acid corrosion management programs.

13.2

Destructive Examinations Results and Remediation

13.2.1 Boric Acid Corrosion of 3 Reactor Coolant Pump Studs Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: RCP casing closure studs (see location on Fig. 13.15). These studs are made of LAS (AFNOR 25 CD 4). Operating conditions: maximum temperature: 200 °C (392 °F). Containment building atmosphere (in the absence of leak). Failure discovery: water was found at the lower end of 3 studs with associated corrosion. Similar event frequency: RCP studs’ corrosion has previously been observed a few times with LAS material. Specimen/sample characteristics: 3 studs were sent to the hot laboratory of Chinon. However, one was saved for additional examinations if required. © Materials Ageing Institute 2022 F. Cattant, Materials Ageing in Light-Water Reactors, https://doi.org/10.1007/978-3-030-85600-7_13

1217

1218

13

Boric Acid Corrosion

DE program and goal: determination of the corrosion depth of the 2 less corroded studs. For that intent, the following program was implemented: • VT and pictures of the corroded areas in the as-received conditions; • Lathe turning, by 0.1 mm (4 mils) deep increments until the corrosion has disappeared, with VT and pictures sequences in-between the machining passes; • PT after all corrosion traces have been eliminated; • Surface replica of the last corrosion area which has been eliminated. Results Stud #301 413 A-5e3. Figure 13.1 shows the stud #301 413 A-5e3 surface in the as-received conditions at the laboratory.

Fig. 13.1 RCP stud #301 413 A-5e3. View in the as received conditions

Destructive Examinations Results and Remediation -0.1 mm

1219

-0.2 mm

270

180

90

0

0

13.2

-0.3 mm

-0.4 mm

-0.5 mm

-0.7 mm

Fig. 13.2 RCP stud #301 413 A-5e3. Evolution of the corrosion extension at various depths. Maps drawn after lathe turning machining (scale bar: 27 mm, 1.06″)

Figure 13.2 illustrates the evolution of the corrosion through the stud. After having removed 0.8 mm (0.031″) of the stud radius, all corrosion traces have disappeared. The absence of corrosion has been confirmed by PT. Stud #30 474 A-Z 132. Figure 13.3 shows the stud #302 474 A-Z 132 surface in the as-received conditions at the laboratory. Figure 13.4 illustrates the evolution of the corrosion through the stud. After having removed 0.6 mm (0.024″) of the stud radius, all corrosion traces have disappeared. The removal of all corrosion traces has been confirmed by PT. A replica taken after the final machining (Fig. 13.5) also confirms that corrosion has been fully eliminated.

1220

13

Boric Acid Corrosion

-0.1 mm

-0.2 mm

-0.3 mm

270

180

90

0

0

Fig. 13.3 RCP stud #302 474 A-Z 132. View in the as received conditions

-0.4 mm

-0.5 mm

Fig. 13.4 RCP stud #302 474 A-Z 132. Evolution of the corrosion extension at various depths. Maps drawn after lathe turning machining (scale bar: 27 mm, 1.06″)

13.2

Destructive Examinations Results and Remediation

1221

200 μm Fig. 13.5 RCP stud #302 474 A-Z 132. Aspect of the surface after final machining. All corrosion traces have disappeared

Conclusion On the stud #301 413 A-5e3, the maximum depth of the corrosion was greater than 0.7 mm (0.028″) and less than 0.8 mm (0.031″). This has been confirmed by PT and replica. On the stud #302 474 A-Z 132, the maximum depth of the corrosion was greater than 0.5 mm (0.02″) and less than 0.6 mm (0.024″). This has also been confirmed by PT and replica.

13.2.2 Wastage of 2 Reactor Coolant Pump Studs Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: RCP casing closure studs (Figs. 13.6 and 13.15). These studs are made of LAS (AFNOR 40 NCD 07.03, Table 13.1). The French code (RCC-M M 2,311) requires for this material the following thermal treatment: annealing between 820 °C (1,508 °F) and 885 °C (1,625 °F), water quench, tempering between 590 °C (1,094 °F) and 630 °C (1,166 °F), air cooling.

1222

13

Boric Acid Corrosion

Top

Bottom

Fig. 13.6 RCP casing closure stud drawing. Dimensions in mm Table 13.1 Chemical composition of the 2 RCP casing studs (Weight %) C Stud #150 Stud #209 RCC-M 2312

0.40 0.39 0.35/ 0.46

S B > C > A; #B10: E, F > D, B > C > A; #F06: E, F > D, B > C, A; #C09: E > F > B > D > C > A; #F06’: E > F > D, B > C > A; #M06: E, F > D > B, C > A;

1748

21

Wear

Fig. 21.50 Hole #E2 of card #F08. Ligament wear dissymmetry. Left: right ligament totally worn. Right: left ligament not 100% worn

Fig. 21.51 Left: hole #F2 from card #F06. Right: hole #E3 from card #B10

• Some holes exhibit a cone shaped wear which widens towards the top or the bottom of the card (Fig. 21.51). Dimensions measurements The accuracy of the 3D measuring equipment is 3 µm (0.12 mil). The Table 21.5 gives the results of the splits width measurements, some splits are wider than the rod outside diameter: 9.65 mm (0.38’’). One will note that some splits are larger than the rod diameter with, as a consequence, the possibility for the rods to exit from the holes connected to these splits; this situation is encountered for the hole #E3 of card #F06’, the hole #E4 of card #M06 and hole #E2 from card #C09. The maximum wear at the holes inlet and inside the holes have been reported on map such as the one of Fig. 21.52.

21.3

Destructive Examinations Results and Remediation

1749

Table 21.5 Results of the splits width measurements (Lf1 = inside, Lf2 = outside). Black: no significant wear (wear < 0.1 mm/4 mils); green: incipient wear (0.1 mm/4 mils < wear < 0.2 mm/ 8 mils); orange: mild wear (0.2 mm/8 mils < wear < 0.4 mm/16 mils); red: severe wear (wear > 0.4 mm/16 mils); red in grey box: split width superior to the rod diameter

Hole #F

Hole #E

Spit width Lf (mm) E1

E2

E3

E4

F1

F2

F3

F4

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

Lf1

Lf2

ID

OD

ID

OD

ID

OD

ID

OD

ID

OD

ID

OD

ID

OD

ID

OD

G13

8.46

6.23

6.10

6.16

6.20

6.91

6.15

6.92

6.04

6.06

6.06

6.06

6.80

6.02

6.06

6.09

F06

6.54

6.62

6.18

8.36

7.34

6.44

8.80

6.22

6.02

6.03

7.94

6.05

5.99

6.00

6.05

6.06

B10

6.13

8.40

6.09

7.05

6.19

8.74

8.60

6.15

6.01

6.05

6.04

6.05

6.02

6.00

6.02

6.03

F06’

6.30

6.65

6.67

6.10

11.46

6.16

6.15

6.05

6.17

6.16

6.16

6.15

6.15

6.14

6.15

6.13

M06

7.12

6.35

6.99

9.68

9.23

6.05

11.78

6.04

6.10

6.08

6.08

6.08

6.07

6.09

6.08

6.08

C09

6.10

7.79

10.30

6.09

6.14

6.10

8.68

8.44

6.14

6.12

6.13

6.11

6.11

6.12

6.12

6.11

A07

6.00

6.06

7.88

6.14

F08

6.08

6.18

8.10

6.39

6.11

6.07

6.05

6.04

Fig. 21.52 Localization of the severely worn zones of the card #B10. In red: maximum measured wear. symbol: sketches the rod displacement inside the hole

1750

21

Wear

Fig. 21.53 Location of dimensions: Dper, D+30°, D−30°, UD and LG

The material loss at the holes inlet and the diameters have been assessed by hole type. The way these losses have been calculated is shown on Fig. 21.53. The minimum and maximum wear of the hole diameter and of the hole inlet are calculated as follows: Hole diameter: min; max{(Dper; D+30°; D−30°) – Dorigin} Hole inlet diameter: min, max{UG + UD} with UG and UD corresponding to the left and right wear at the hole inlet. The results obtained are reported hereafter. The mean wear at the holes’ inlet is around (averaged on cards B10, F06, G13, C09, F06’ and M06): • • • • • •

0.35 mm (14 mils) for holes A; 2.2 mm (87 mils) for holes B; 1.2 mm (47 mils) for holes C; 2.4 mm (94 mils) for holes D; 3.3 mm (130 mils) for holes E and 2.3 mm (91 mils) for holes F.

The mean holes diameter wear at elevation −6 mm (0.24’’) is around (averaged on cards B10, F06, G13, C09, F06’ and M06): • • • •

0.2 mm (8 mils) for holes A; 1 mm (40 mils) for holes B; 0.7 mm (28 mils) for holes C; 1.1 mm (43 mils) for holes D;

21.3

Destructive Examinations Results and Remediation

1751

Fig. 21.54 ID ligaments wear of holes #E: example of case #1 (partial wear of the ligaments)

Fig. 21.55 ID ligaments wear of holes #E: example of case #2 (total wear of the ligaments with the split width inferior to the rod diameter)

• 1.6 mm (63 mils) for holes E and • 1.6 mm (63 mils) for holes F. From the wear profiles obtained on the ID ligaments of the #E holes, three wear stages have been referenced hereafter: • Partial ligaments wear (case #1, Fig. 21.54); • Total wear of the ligaments with a split width inferior to the rod diameter (case #2, Fig. 21.55) and, • Total wear of the ligaments with a split width superior to the rod diameter (case #3, Fig. 21.56).

1752

21

Wear

Fig. 21.56 ID ligaments wear of holes #E: case #3 (total wear of the ligaments with the split width superior to the rod diameter); not encountered

SEM examination The overall wear features call for small displacements impact wear. A cold work layer exits beneath the worn surface. At the surface of the material, one can distinguish four wear types: • Type A wear: radial striation (Fig. 21.57). Micro-scratches, around 10 µm (0.4 mil) long, are visible at the oxidized surface. These scratches result from the rod displacement. These striations are typical from impact-sliding wear, also called vibration-wear or small displacements wear.

Fig. 21.57 Type A wear: radial striation

21.3

Destructive Examinations Results and Remediation

1753

Fig. 21.58 Type B wear: vertical scratches

• Type B wear: vertical scratches (Fig. 21.58). Some holes surface exhibits vertical scratches, stemming from vertical rods movements such as RCCAs moving step by step up or down or when dropped. The associated wear mechanism could be abrasion wear of a soft material (card) in contact with a hard material (nitrided rod). • Type C wear: wear with cupules (Fig. 21.59). This type of wear is observed on a small surface of the inside ligament (length limited to around 620 µm (24 mils) maximum), at the hole limit, which is a sharp edge. The cupules are elongated in the rod axial direction. The cupules dimensions

Fig. 21.59 Type C wear: wear with cupules

1754

21

Wear

Fig. 21.60 Type D wear: hammered like surface

range from 40 to 400 µm (1.6–16 mils) in length and from 10 to 50 µm (0.4–2 mils) in width. This wear mechanism is impact wear. • Type D wear: hammered like surface (Fig. 21.60). This morphology, observed ahead of the cupule’s region, is hollow and is covered with a smooth oxide layer, driving to the conclusion that the oxide has been “buttered” by contact. The hammering direction seems to be radial, indicating the rod has a radial movement. Loss of material The shape of the cards B10, F06 and G13 has been modelled from 3D measurements. From this modelling, the worn volume of each hole could be assessed, which could be translated in metal mass loss. The Table 21.6 summarises the results obtained. The holes material loss ranks as: F > E > B, D > C > A; with almost a factor of 10 between holes F and A. The average loss of material of the cards is 45 ± 10 g. One single hole can loss up to 8 g (hole #F2 of card #F06). Conclusion The 8 cards #6 examined here exhibit wear from the axial and radial movements of the rods in the cards’ holes. As expected, the softer material (stainless steel from the card) is worn by the harder material (nitrided stainless steel from the rods). Various wear mechanisms have been observed, impact wear being the prevalent.

21.3

Destructive Examinations Results and Remediation

1755

Table 21.6 Loss of material in mg. Minimum/maximum for each series of 4 holes Holes

A

B

C

D

E

F

Max

Total

G13

44/ 462 37/ 508 49/ 201 22/ 1351 51/ 1554 32/ 89 367

1731/ 3736 896/ 3879 531/ 2705 1594/ 2038 1021/ 4428 2165/ 2674 2283

171/ 2195 35/ 324 196/ 1859 400/ 2938 154/ 2418 22/ 2022 1061

639/ 3842 1398/ 2984 1307/ 2833 448/ 2913 1663/ 4468 1094/ 3099 2224

1241/ 3109 2166/ 2842 1556/ 3018 1743/ 3246 2655/ 3605 847/ 4912 2578

1995/ 3354 1426/ 8121 667/ 2605 1833/ 4496 2718/ 3756 2156/ 5035 3180

3842/ D1 8121/ F2 3018/ E2 4496/ F2 4468/ D3 5035/ F4 4830

42,282

F06 B10 F06’ M06 C09 Mean

45,046 35,056 44,791 55,160 49,313 45,275

The worst ligaments or splits wear can allow the relevant rods leaving their original hole position; fortunately, this is a concern for only a few holes. Holes F and E are those the most worn, holes A being the least. The average material loss is around 45 g per card or 2–3 g per cycle, depending on the unit. The results of this destructive examination support the RCCAs’ life limitation to 15 cycles.

21.3.5 Wear of 2 Rods Control Assembly Drive Shafts Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: RCCA drive shafts #H04 and #D12. Time of operation: the drive shaft #H04 operated 4,700,000 steps and the drive shaft #D12 operated 330,000 steps. Failure discovery: in outage, when performing remote VT of the cylinder head housings, a gap was observed between the P08 grooved drive shaft and the cylinder head housing (threaded connection locked by a welded pin). The same clearance has been observed on drive shafts #H04 and #D12. Similar event frequency: first of a kind observation of such a gap on 3 RCCAs drive shafts. Specimen/sample characteristics: Fig. 21.61 shows location of the relevant area. The area of concern is the screwed connection between the cylinder head housing and the grooved shaft.

1756

21

Wear

Fig. 21.61 RCCA drive shaft. Top: overview of the entire shaft. Middle: view of the top of the shaft. Bottom: detail of the screwed connection between the grooved RCCA drive shaft and the cylinder head housing

A 20.4 daNm torque is applied on the M36
2 thread (2 mm/0.08’’ thread pitch); lubricant is used. An anti-rotation pin (5 mm (0.2’’) in diameter, 30–60 µm (1.2–2.4 mils) clearance) is welded out of the threaded area. The RCCA drive shaft and the cylinder head housing are made of a 13% Cr martensitic SS (Z12C13). The pin is made of austenitic SS (Z5CN18.10, similar to 304). RCCA drive shafts #H04 and #D12 have been selected for DE. The axial gap on shaft #H04 was 3.4 mm (0.13’’), it was 0.3 mm (0.012’’) on the shaft #D12. Moreover, the shaft #D12 exhibited some loss of material of the pin tack weld. DE program and goal: find out the origin of the gap between cylinder head housing and the grooved drive shaft. Results The VT of the #H04 shaft confirms the 3.4 mm (0.13’’) gap between the cylinder head housing and the grooved shaft (Fig. 21.62). The pin surface is sound. The #D12 shaft exhibits a much smaller gap (0.3 mm/ 0.012’’); the pin is no more attached to the shaft and there is a lack of weld (Fig. 21.62). Axial sections have been performed at 90° from the pins.

21.3

Destructive Examinations Results and Remediation

1757

Fig. 21.62 RCCA drive shaft. Top: overview of the upper section of the #H04 shaft. Bottom left: #H04 shaft, detail view of the 3.4 mm (0.13’’) gap between the cylinder head housing (to the left) and the grooved shaft (to the right). Bottom right: # D12 shaft, detail view of the damage of the anti-rotation pin weld

#H04 results The pin got loose when the sectioning was completed. The pin hole in the shaft is widened and no more round; the hole deformation is oriented towards the top of the shaft (Fig. 21.63). The cylinder head housing thread is almost worn out. The faces of the cylinder head housing and of the grooved shaft in contact suffer from mechanical damage due to the repeated impacts between the two parts; the machining marks have disappeared (Fig. 21.64). An axial section confirms the significant wear of the thread with only around 30% of it remaining (Figs. 21.65 and 21.66). At higher magnification, a thin oxide layer can be observed on the thread flanks and not on the thread top (Fig. 21.66). This makes one think that at this stage of damage, the wear only bears on the top of the thread. This situation is different from the shaft #D12 for which wear is at an incipient stage as proven by the presence of oxide on top of the thread and the absence of it on the flanks (Fig. 21.68). The structure at the worn surface is not modified by wear. These observations are consistent with a mechanism consisting of a series of oxidation/wear sequences without material structural modifications. Given the significant thread wear, it seems that it was the pin which was holding the cylinder head housing and the groove shaft together. #D12 results The pin also got loose when the specimen was cut.

1758

21

Wear

Fig. 21.63 RCCA drive shaft. Top left: #H04 shaft, view of the thread and of the pin hole which is widen and deformed. Top right: #H04 cylinder head housing, SEM view of the thread which is almost worn out. Bottom left: #D12 shaft, view of the thread and of the pin hole. Bottom right: # D12 shaft, SEM view of the thread which appears still in good condition

Fig. 21.64 RCCA drive shaft #H04. View of the lower face of the cylinder head housing in contact with the top of the grooved shaft. Significant mechanical damage is observed

21.3

Destructive Examinations Results and Remediation

1759

Fig. 21.65 RCCA drive shaft #H04. View of an axial section of the bottom end of the cylinder head housing. The thread is almost worn out

Fig. 21.66 RCCA drive shaft #H04. Axial section of the bottom end of the cylinder head housing. Left: view of the wear of the thread. Right: presence of an oxide layer (in grey) on the thread flanks

Fig. 21.67 RCCA drive shaft #D12. View of an axial section of the bottom end of the cylinder head housing. The thread appears almost as new

1760

21

Wear

Fig. 21.68 RCCA drive shaft #D12. Left: detail view showing the incipient wear; the flank wear is around 100 µm (4 mils) on this micrograph. Right: high magnification view of the thread showing the presence of oxide (in grey) on the top and the absence of oxide on the flanks

The pin hole in the grooved shaft is almost round (Fig. 21.63).The cylinder head housing thread appears almost as new (Figs. 21.63 and 21.67). However, a high magnification view reveals that the thread flanks have started to wear. Figure 21.68 shows that the flanks wear is around 100 µm (4 mils) deep. This 0.1 mm (0.004’’) radial wear depth (0.2 mm (0.008’’) for a diameter) is consistent with the 0.3 mm (0.012’’) gap between the cylinder head housing and the grooved shaft. As previously mentioned, an oxide layer is present on the thread top but not on the flank (Fig. 21.68), a situation opposite to the #H04 thread which exhibits oxide on the flank and not on the top (Fig. 21.66). This observation shows that the thread wear starts at the flank and ends at the top. Same as for #H04 shaft, the faces of the cylinder head housing and of the grooved shaft in contact suffer from mechanical damage due to the repeated impacts between the two parts; the machining marks have also disappeared. Conclusion, remedial action For both RCCA drive shafts, the gap between the cylinder head housing and the grooved shaft is due to the wear of the thread attaching these two parts together. On the #H04 drive shaft, wear was so significant that the two components were only attached by the pin. Two mechanisms can be considered: • Fretting wear; • A tribocorrosion phenomenon, with repeated oxidation/oxide removal phases. The maintenance of this component takes into account the potential occurrence of these degradation mechanisms.

21.3

Destructive Examinations Results and Remediation

1761

21.3.6 RCCA Drive Shaft Wear Assessment Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: The driver shaft allows the RCCA to move up and down thanks to the presence of a coupling sleeve equipped with two flexible leaves (Fig. 21.69). The relevant materials are: • • • • •

Trigger: AFNOR Z5 CN 18-10 (AISI 304); Coupling sleeve: AFNOR Z12 CN 13; Locking button: cobalt alloy; Locking spring: AFNOR NC 15 FeTNbA; Protecting sleeve: AFNOR Z12 C13.

Fig. 21.69 Lower section of the RCCA drive shaft

1762

21

Wear

Operating conditions: primary water. Time of operation: 183,277 h, 899,472 steps. Failure discovery: when lifting up the L13 drive shaft for re-connecting RCCAs, the assembly tool-drive shaft-RCCA got stuck. Despite several lifting up trials, no movement could occur. The drive shaft could be disconnected only by rotation. Field remote VT showed metal overlap at the flexible leaves’ location along with at the ID surface of the spider stub, calling for an interaction between these two parts (Figs. 21.70 and 21.71). Similar event frequency: one similar event occurred on a 3-loop unit two years before the event reported here. The destructive examination revealed a significant deformation of the locking button facing with metal tearing at the coupling sleeve OD. The failure root cause analysis led to the following conclusion: a plastic deformation of the dismantling shaft bottom on which the locking button is screwed led to a misalignment of the locking button/drive shaft bottom. This misalignment induced some hammering of the coupling sleeve ID by the locking button until the final seizure of the locking button into the coupling sleeve. This seizure made the drive shaft connection to the RCCA spider impossible. Specimen/sample characteristics: the lower segment (or foot) of the drive shaft, including the coupling sleeve, was cut and sent to the hot laboratory for destructive examination. DE program and goal: the goal of this destructive examination is the locking root cause analysis.

Fig. 21.70 Field remote VT, view of the spider stub (female part of the coupling)

21.3

Destructive Examinations Results and Remediation

1763

Fig. 21.71 Field remote VT, view of the lower section of the drive shaft (male part of the coupling)

Results VT of the protecting and coupling sleeves (Figs. 21.72 and 21.73) The protecting sleeve exhibits a worn zone located at 50 mm (2’’) from the coupling leaves. This wear is observed only around angle 0° (arbitrary angle datum), in

Fig. 21.72 View of the protecting and coupling sleeves. Top: leaf #2, angle 0° (arbitrary), bottom: leaf #1, angle 90°

1764

21

Wear

Fig. 21.73 Left: view of the worn zone of the protecting sleeve. Right: view of the bottom of the coupling sleeve; top: flexible leaf #1, bottom: flexible leaf #2

the direction of the central axis of one leaf. Wear is dual orientation: both axial and circumferential. Impact and/or tearing traces are observed on the flexible leaf #2 (Fig. 21.73, right) whereas the leaf #1 is sound. After axial section of the coupling sleeve, fretting and tearing are also observed inside the leaves (Figs. 21.74 and 21.75). These degradations’ result from the contact with the locking button.

Fig. 21.74 View of the inside of the leaf #1 after longitudinal section of the coupling sleeve

21.3

Destructive Examinations Results and Remediation

1765

Fig. 21.75 View of the inside of the leaf #2 after longitudinal section of the coupling sleeve

These observations are consistent with those of the locking button. However, these inside degradations are not symmetrical. The dissymmetry between the two leaves inside surfaces results from a non-uniaxial contact between the locking button and the leaves. Also, the #1 leaf is open by 4° whereas the leaf #2 opening is only of 1° (Fig. 21.72, bottom). The root cause of this difference remains unknown (from fabrication or from operation?). VT of the dismantling shaft, of the locking button and of the trigger. The trigger presents two shiny zones localized 180° apart (Fig. 21.76). These traces are typical of severe wear or of metal upsetting from the contact with the inside surface of the coupling sleeve (facing part). These traces are oriented in the axial direction.

1766

21

Wear

Fig. 21.76 View of the trigger at angle 180°

Fig. 21.77 ID and OD view of the locking button

The examination of the lower zone of the shaft, downstream the locking button, reveals a 40 mm (1.6’’) long worn zone on the screwed length and on a small distance above (Fig. 21.76 bottom). This axial wear is aligned with the trigger wear. The examination of the outside surface of the locking button reveals the presence of circumferential wear (Fig. 21.77). However, this wear seems shallow as compared to the wear observed on the trigger. The inside surface of the locking button is sound (Fig. 21.77). Also, there is no plastic deformation of the shaft—trigger connection.

21.3

Destructive Examinations Results and Remediation

1767

Fig. 21.78 View of the locking spring (received at the laboratory in two pieces)

VT of the locking spring (Fig. 21.78) The visual examination of the locking spring (received at the laboratory in two pieces) does not evidence any degradation. Conclusion Out of some wear from fretting and metal upsetting, typical of a seizure mechanism under severe loads, no major degradation has been observed on the lower segment of the L13 RCCA driving shaft. A high contact pressure has been applied by the coupling sleeve leaves on the trigger during the connection and de-connections operations; the reason for this has not been identified.

21.3.7 Control Rod Drive Mechanism. Wear of Stationary and Movable-Gripper Latch Arms Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: #2D886 CRDM, 3 stationaries (#3133, #3142 and #3152) and 3 movables (#3130, #3131 and #3132) grippers latch arms. Operating conditions: pressure: 155 bars (2,248 psi), however, CRDM must be able to operate at a pressure as low as 5 bars (72.5 psi); temperature: 140 °C (284 ° F) < T < 280 °C (536 °F), however, CRDM must be able to operate at low temperature; environment: occluded primary water. Time of operation: 48,000 h; 1,400,000 steps for latch arms. Failure discovery: the failure history is the following: 12/30/1989: the CRDM #2D886 is locked at the 0-step position, moreover, the upwards motion is delayed; 08/12/1995: some skip or missed steps are observed; 09/07/1995: stationary-gripper malfunction (drop then locking); 10/02/1995: the CRDM is harvested; a high force is needed to remove the drive rod from the CRDM.

1768

21

Wear

Tooth #1 Bearing face Top None bearing face Tooth #2

Bearing face Top

A1: bearing face of tooth #1, A2: bearing face of tooth #2, B1: none bearing face of tooth #1, B2: none bearing face of tooth #2.

None bearing face

Fig. 21.79 CRDM grippers latch arms. Left: sketch of a latch arm. Right: teeth face definition: A1: bearing face of tooth #1, A2: bearing face of tooth #2, B1: none bearing face of tooth #1, B2: none bearing face of tooth #2

Wear is not suspected as being the root cause of these malfunctions (the root cause is the failure of the antirotation pin of the stationary gripper). But the operator took advantage of the replacement of this CRDM to investigate the latch arms wear. Similar event frequency: latch arms have been harvested for similar conditions from at least 6 other EDF PWRs (four 4 loops and two 3 loops). Specimen/sample characteristics: the latch arms are made of austenitic SS (AFNOR Z2 CN 19.10 +N2, 19% Cr and 10% Ni, similar to 304L nitrogen controlled). The teeth (Fig. 21.79) are made of stellite grade 6. DE program and goal: stellite coating inspection and wear assessment. Results VT (Fig. 21.80) A deposit covers the teeth faces, irrespective of their side (bearing or none bearing). The teeth faces suffer from mechanical damage (scratches, impacts, marks…), some of which can stem from the high force applied to pull the drive rod out of the CRDM. Some friction traces are visible on the bearing faces of the stationary-gripper latch arms. Some corrosion is also present along with some smooth zones (as smooth as polished).

21.3

Destructive Examinations Results and Remediation

1769

Fig. 21.80 CRDM grippers latch arms. Left: overview of #3131 and #3130 movable-gripper latch arms. Top right: view of tooth #1 of latch arm #3132. Bottom right: view of tooth #2 of latch arm #3131

Dimensions Wear depth has been measured on the faces of latch arms #3132 (moveable-gripper) and #3152 (stationary-gripper); the results are summarized in the Table 21.4. The bearing faces of the latch arm of the stationary-gripper are the most worn; there is no measurable wear of the none bearing faces of the same latch arm. SEM (latch arms #3132 and #3152) The observation of the teeth profiles is consistent with the results reported in the Table 21.7. On faces where no wear has been measured, the tooth profile is straight and on faces for which wear has been measured, the tooth profile exhibits a curved shape (Fig. 21.81). The bearing faces show 2 zones. The first one is an oxidized zone at the foot of the tooth, with a disturbed surface state (friction traces). In both cases, some deposit is visible. Machining marks are still visible where the worn zone ends (Fig. 21.82). Table 21.7 CRDM grippers latch arms. Results of the wear depth measurements Latch arm #

A1 (mm/inch)

B1 (mm/inch)

A2 (mm/inch)

B2 (mm/inch)

3132 (moveable) 3152 (stationary)

0.55/0.022 0.61/0.024

0.21/0.008 0

0.42/0.017 0.54/0.021

0.21/0.008 0

1770

21

Wear

Fig. 21.81 CRDM grippers latch arms. Left: profile of the none bearing face of the tooth #2 of the latch arm #3152 (stationary-gripper); no wear is visible. Right: profile of the bearing face of the tooth #1 of the latch arm #3132 (moveable-gripper); wear is clearly visible

Fig. 21.82 CRDM. Stationary-gripper latch arm #3152, tooth #1, bearing face. Left: view of an area close to the tooth’s foot; machining marks are still visible at the top of the photograph. Right: view of an area close to the tooth’s top. The arrows are pointing at a zone exhibiting iron oxide

The second one is a zone at the middle and at the top of the tooth with a smooth surface state, the print of the underlying stellite dendrites is visible (Fig. 21.83). Some deposits, i.e.: iron oxide can be observed at some particular locations (Fig. 21.82). For the latch arm #3132 (moveable-gripper) the none bearing faces look very similar to the bearing faces which makes one think that the none bearing faces are nevertheless in contact with the grooved shaft when this latter moves (Fig. 21.84). The none bearing faces of the latch arm #3152 which only holds the grooved shaft between two steps, appear different, wear free, with machining marks still visible. The print of the stellite structure is visible (Fig. 21.84). Metallography (latch arms #3132 and #3152) The stellite structure is homogeneous; the teeth have been machined in a single stellite layer, 4.4 mm (0.17’’) thick maximum (Fig. 21.85).

21.3

Destructive Examinations Results and Remediation

1771

Fig. 21.83 CRDM. Moveable-gripper latch arm #3132, tooth #2, middle zone of the bearing face. The surface looks smooth. The print of the underlying stellite dendrites is visible (left photograph)

Fig. 21.84 CRDM grippers latch arms. None bearing faces. Left: moveable-gripper latch arm #3132, tooth #2. Right: stationary-gripper latch arm #3152, tooth #1; the print of the stellite structure is visible at high magnification

Fig. 21.85 CRDM. Stationary-gripper latch arm #3152, tooth #2. Left: view of the structure in the worn zone (curved face area). Right: view of the structure close to the top of the tooth. 10% oxalic acid etch

1772

21

Wear

Fig. 21.86 CRDM. Stationary-gripper latch arm #3152, tooth #1, bearing face. Left: structure of the top of the tooth. Right: structure of foot of the tooth

The stellite structure is slightly different from the typical structure of the stellite found on valves. The carbides are broken, rounded. The eutectic matrix is almost absent. The dendrites appear hollowed out whereas the carbides appear protuberant (Fig. 21.86). The none bearing face is more oxidized than the bearing face. Hardness Measurement of the Vickers hardness under 30 kgf (66 pdf) has been carried out on the teeth of the latch arm #3152 (stationary-gripper); the results are reported in Table 21.8. The results range from 22.2 to 42.7 HRc. Except for the feet of the teeth values, the results are in accordance with the French RCCM code §8000 which specifies a 38–50 HRc range. The figures lower than 38 HRc correspond to the feet of the teeth, hence close to the SS base metal. However, the values are close to the minimum threshold of 38 HRc which means that the stellite flame deposit was maintained at high temperature during enough time to favor dilution by the base metal. Table 21.8 CRDM. Stationary-gripper latch arm #3152. Results of the hardness measurements HV30 tooth #1

HRc equivalent tooth #1

HV30 tooth #2

HRc equivalent tooth #2

Tooth foot: 287 418 Tooth middle: 401 401 Tooth top: 396

27.8 42.7 40.8 40.8 40

252 381 373 391 406

22.2 38.8 37.7 39.8 41.8

21.3

Destructive Examinations Results and Remediation

1773

Conclusion, remedial action Wear has been measured on the bearing faces of the latch arms, irrespective of the gripper type (stationary or moveable) after 1,400,000 steps. Latch arms wear has been taken into account in the new design of long-life replacement CRDMs.

21.3.8 Wear of the Alignment Pins of the Core Support Plate Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: 4 alignment pins and 2 anti-rotation washers. The alignment pins are screwed in the core support plate (Fig. 21.87). Operating conditions: primary water, 155 bars (2,248 psi), 289 °C (552 °F).

Fig. 21.87 Left: drawing of the alignment pins screwed in the core support plate (H1 and H2 vary according to the fuel type). Right: drawing of the anti-rotation washers placed at the base of the alignment pins. Dimensions in mm

1774

21

Wear

Time of operation: pin B12: 72,198 h; pin C02-180°: 80,000 h (9 cycles); pins L05−180° and F01−180°: 9 cycles (first 10-year outage); L05−180° and F01−180° washers: 11 cycles. Failure discovery: during the first inspection, at the 10-year outage. Similar event frequency: few other EDF 4 loop PWRs suffered from wear or loss of the alignment pins of the core support plate. Specimen/sample characteristics: the alignment pins are screwed in the core support plate with an anti-rotation washer underneath which is held in place by a tack weld (Fig. 21.87). The screwing torque is in the 5.8 to 6.8 m.kg (42–49 ft.pdf) range. The pins are made of cold work Z2 CND 17-12 (AISI 316L) and the washer of Z2 CN 18-10 (AISI 304L). The fuel assembly bottom nozzle is made of annealed Z5 CN 18-10 (AISI 304). The fuel bottom nozzle hardness is inferior to the pin hardness. DE program and goal: depending on the pin or the washer, the DE goals were finding out why the pin got loose and characterizing the wear damage. The DE program included: VT, laser profilometry, hardness measurements, micrography, chemical analysis, SEM, dimensions measurements; however not all techniques were applied to all specimens. Results Field VT Although the pin #B12 left its original location, its anti-rotation washer was still in place without any damage to the tack weld. The VT of the C02 pin 3 years before it was found missing, had revealed a 2 mm (0.08’’) wear (at the deepest) by the fuel assembly bottom nozzle. The wear has a beveled shape. A significant gap is visible between the pin base and the ID bore of the washer. The pin and the washer flat parts are no longer in coincidence which shows that the pin had started moving from its original position. The same VT performed once the pin had left the core support plate showed that the support plate thread is severely worn and that the washer flat parts have almost entirely disappeared. The VT of the L05 and F01 pins revealed a gap between these pins and their associated washers and also a beveled shaped wear. Hot laboratory VT Figure 21.88 shows the 4 alignment pins as received at the hot laboratory. The following observations are common to all pins: • The pin shape is now different from the original design shape; • The worn zones are shining whereas the wear free zones are covered with a dark oxide;

21.3

Destructive Examinations Results and Remediation

1775

Fig. 21.88 Core support plate alignment pins. View in the as-received conditions. ①: flat part. ② and ③: location of the deepest wear. ④: shoulder

• The pin #B12 wear is symmetrical whereas the 3 other pin wears are not (beveled shape); • The flat parts are still present; however, their corners are severely worn and their bottom end has disappeared; • The shoulder is worn over the entire circumference over 3 mm (0.12’’) high; • There is no pin deformation. Regarding the washers (Fig. 21.89), the internal flat parts are deformed (the metal has been chased) and severely damaged and worn. No trace of contact with the pin is visible on the upper face.

1776

21

Wear

Fig. 21.89 Core support plate alignment pins. View of an anti-rotation washer as received at the hot laboratory

Dimensions The B12 alignment pin is the most worn. On Fig. 21.90, the profiles of the pin #C02-180°, measured by laser profilometry every 20° of angle are compared with the design profile. The wear height is consistent with the zone of contact between the pin and the bottom nozzle of a fuel assembly. Hence the pin has been worn by the bottom nozzles of the various fuel assemblies loaded in that position.

Fig. 21.90 Core support plate alignment pin. Laser profilometry every 20° of the C02-180° pin

21.3

Destructive Examinations Results and Remediation

1777

Micrography and SEM (B12 pin) The pin structure is homogeneous and consistent with this type of material. The thread structure is severely cold worked and some metal overlaps are observed. The pin exhibits two zones of wear, a first one due to the contact with the bottom nozzles of the fuel assemblies and a second one with the anti-rotation washer. Hardness The pin #B12 hardness ranges from 250 HV0.1kgf to 356 HV0.1kgf. The pin #C02-180° hardness ranges from 198 HV0.1kgf to 331 HV0.1kgf with an average of 250 HV0.1kgf. These figures are superior to the typical hardness of 316L (* 200 HV) and are consistent with the presence of cold work. Conclusion, remedial action Only one of the 2 alignment pins of a fuel assembly is worn. The wear of the pin body and the wear of the thread are both asymmetrical and opposed on the same pin diameter (the deepest wears are located 180° from each other). However, the wear of the pin #B12 is quite symmetrical. One explanation of this is that this pin has been screwed on the washer instead of in the washer. Hence, the vibrations unscrewed the pin which could rotate and wear all over the circumference. For the other pins, the scenario could be the following: progressive wear of the flat part edges until the pin gets loose. The beveled shape of the wear indicates that the pin started to rotate in the washer. Last, nothing can substantiate that these pins were screwed with the right torque. A VT of the alignment pins of the core support plate is performed every 10-year outage. Missing pins are retrieved and replaced so as the pins with significant wear.

21.3.9 CRDM Thermal Sleeves’ Wear Assessment (ML18143B678, ML18198A275, ML18214A710 and ML18249A107) Plants main characteristics: Framatome PWRs, 900 and 1,300 MWe, 3 and 4 loops, France; Westinghouse PWR, 4 loops, USA. Equipment/Component: CRDM thermal sleeve (Figs. 21.91 and 21.92). The thermal sleeve is installed in the CRDM housing before the CRDM is welded on, trapping the thermal sleeve. The thermal sleeve is supported by an internal chamfer (ledge) in the CRDM housing. This allows the thermal sleeve freedom to move up, move down, and rotate about its axis. Both CRDM flange and thermal sleeve are made of AISI 304L. The various functions of the thermal sleeve are: • Centering and guiding the vertical translations of the RCCAs’ drive shafts;

1778

21

Wear

Fig. 21.91 Example cross-section of Westinghouse PWR closure head assembly, CRDM thermal sleeve

Fig. 21.92 CRDM flange (grey) with a thermal sleeve (yellow) installed

21.3

Destructive Examinations Results and Remediation

1779

• Protecting the CRDM (made of Alloy 690), and its J-groove weld to the head, against cold thermal shocks when RCCAs are lifted up (cold water moving down); • Create flow paths for hot water moving up in the CRDMs when RCCAs are dropped. To meet these functions, thermal sleeves can slide up and down, playing the role of check valves. EDF 900 MWe units have 61 thermal sleeves’ positions whereas 1,300 MWe and 1,450 units have 73 (including 8 unrodded positions). Operating conditions: primary water, 155 bars (2,248 psi), maximum 289 °C (552 °F). Failure discovery: During a spring outage in 2014, a control rod drive mechanism thermal sleeve wear issue was identified at a U.S. plant when a single thermal sleeve fell from the reactor vessel closure head at an unrodded CRDM during an in-service inspection. Examination of the fallen sleeve confirmed that the upper flange, which rests inside the CRDM head adapter tube, had worn through. Industry determined that the wear could be correlated to a change in elevation of the bottom of the thermal sleeve (guide funnel) when compared to the as-designed condition. Measurements of elevations taken showed significant but acceptable wear and all rodded locations had low-to-moderate wear. In December 2017, a French 4-loop unit in France (plant B2 here) experienced a complete wear through and separation of one of their thermal sleeves at a rodded CRDM location. During low-power physics testing and rod drop testing, the plant had difficulty stepping the rod into the core. The rod was freed by exercising the drive rod but was then stopped prior to full insertion during the rod drop test. The failure to insert the rod was caused by the worn thermal sleeve flange remnant. Investigation of the incident showed the same wear behavior as was discovered in 2014 in the U.S. plant. In fact, the industry first identified CRDM thermal sleeve wear as soon as 2007 at several U.S. Westinghouse PWRs. At that time, the wear was located in three places: (1) on the outside diameter of the thermal sleeve where the sleeve exits the CRDM penetration housing, (2) on the inside diameter just above the guide funnel due to contact with the drive rod, and (3) at the centering tab locations within the CRDM nozzle (Fig. 21.93). Similar event frequency: thermal sleeve wear is not unusual, fortunately total flange wear has been encountered only five times, three times on the French fleet (three units) and twice on the US fleet (one unit) as of 2019. Specimen/sample characteristics: the sample received at hot laboratory can be either the entire thermal sleeve in one or several pieces, or just the top of the thermal sleeve, or the upper remnant after through wall wear of the flange and/or even silastic molds.

1780

21

Wear

Fig. 21.93 Wear zones identified in 2007 by the US industry on W plants

DE program and goal: wear measurements for determination of maintenance criteria (wear threshold acceptable in operation). Results Unfortunately, the results of the plant B unit 2 specimens’ destructive examination were not available at the time this handbook was updated. In the 2014 US event, a single, unrodded thermal sleeve fell from the reactor vessel closure head during an in-service inspection. Examination of the fallen sleeve showed that the upper flange, which rests inside the CRDM head adapter tube (Fig. 21.93), had worn through. As the thermal sleeve is rotated or otherwise moved due to water flow within the CRDM, the corner radius of the thermal sleeve upper flange rubs against this chamfered surface and both are worn away over time.

21.3

Destructive Examinations Results and Remediation

1781

Fig. 21.94 Illustration of CRDM thermal sleeve wear

Figure 21.94 shows the original CRDM housing surface (A), the worn CRDM penetration tube surface (B), and the thermal sleeve flange remnant (C). The shaded regions of the figure represent material removed by the wear. The result was separation of the remaining remnant (dotted red outline) of the upper flange and a worn pocket in the adapter tube. This mechanism shows that the more severe the CRDM and the thermal sleeve flanges wear, the lower the thermal sleeve will go down and eventually drop. Thus, the value of the down shift of thermal sleeves is wear dependent. In other words, measuring the elevation of the thermal sleeve guide funnel, when compared to the as-designed elevation, allows having access to its level of wear, the lower the sleeve, the more severe the wear. Another consequence is as the flange and tube surfaces wear away, the thermal sleeve will move lower and become closer to the top of the upper guide tube. Figure 21.95 shows the lowering of the thermal sleeve and the contact between the guide funnel and the top of the upper guide tube. The amount of flange wear required to make contact and the actual visual indications seen will depend on the guide tube configuration used at the plant. While signs of contact between the guide funnel and the anti-rotation stud/nut may be visible before flange separation occurs, this wear pattern indicates that significant thermal sleeve flange wear has occurred, as shown on Fig. 21.95 where the wear marking (“shiny ring”) is visible on the upper guide tube top housing plate after the reactor vessel head has been removed.

1782

21

Wear

Fig. 21.95 Plant B2: contact between the guide funnel and upper guide tube

From a practical standpoint, the sleeve elevation is measured in the field and by using an elevation/wear intensity correlation, the operator can know which sleeve is worn along with the severity of this wear. In the 2017 French event, as already mentioned, the plant B2 experienced a complete wear through and separation of one of the thermal sleeves at a rodded CRDM location. During low power physics testing and rod drop testing, the plant had difficulty stepping the rod into the core. The rod was freed by exercising the drive rod, but was then stopped prior to full insertion during the rod drop test. The failure to insert the rod was caused by the thermal sleeve wear remnant, as shown in Fig. 21.96. Investigation of the incident showed the same wear behavior as was discovered in the 2014 U.S. event. Conclusion Thermal sleeve flange wear is a safety concern as may prevent RCCA drop. However, thanks to several destructive examinations, the situation is under control. The measurement of the elevation of the thermal sleeves’ bottom gives access to the level of flange wear and allows making, with good confidence, a decision about the remaining life of thermal sleeves.

21.3

Destructive Examinations Results and Remediation

1783

Fig. 21.96 Illustration of trapped CRDM flange remnant

21.3.10

Destructive Examination of 8 Thimble Tubes of the in-Core Instrumentation System

Plants main characteristics: Framatome PWRs, 1,300 MWe, 4 loops, France. Equipment/Component: in-core instrumentation system, 8 thimble tubes harvested from 2 reactors (2
4). The thimble tubes dimensions are: outside diameter = 7.5 mm (0.295’’) and wall thickness = 1.15 mm (0.045’’). The thimble tubes are made of SS: Z5 CND 17.12 (AISI 316). Figure 21.97 shows the typical layout of the in-core instrumentation system at the bottom of a 4-loop reactor. Figure 21.98 shows some details of the bottom of the RPV of a 4-loop reactor; the 5 wearing zones are also indicated. Figure 21.99 shows with some level of detail, the localization of the wearing zones ② and ③ of the 4- loop reactors (Fig. 21.100).

1784

21

Wear

Fig. 21.97 Typical layout of the in-core instrumentation system at the bottom of the RPV of the EDF 4 loop reactors. Dimensions in mm

Operating conditions: OD: primary water, 155 bars (2,248 psi). Time of operation: thimble tubes 29A11, 45N4, 47M7 and 55N6 = 5,117 h; thimble tubes 26N8, 28J8, 42H2 and 46R6 = 5,449 h. Failure discovery: thimble tubes wear has been observed which can lead to leak. Wear has been detected following the periodic tests. The deformation stemming from severe wear can lock the instrumentation chamber travelling in the tube. Similar event frequency: several EDF PWRs (both 3 and 4 loops) suffered from wear of the thimble tubes. Specimen/sample characteristics: the length of the specimens is * 2.6 m (8.5 feet). Each specimen corresponds approximately to the length between the foot of the fuel assembly and the RPV wall.

21.3

Destructive Examinations Results and Remediation

1785

Fig. 21.98 In-core instrumentation system of the 4-loop reactors. The 5 wearing zones are indicated by the rectangles 1−5. Left: lower instrumentation guide. Middle: secondary support. Right: RPV outlet. Dimensions in mm

DE program and goal: wear characterization. The DE program included: dose measurements, localization of the worn zones along the tubes, measurement of the length, depth and angular extension of the worn zones, metallography, and chemical analysis. Not all techniques were applied to all thimble tubes. Results VT and cross section The visual aspects along with cross sections of some typical worn areas are shown in Figs. 21.101, 21.102, 21.103, 21.104 and 21.105. These figures indicate that: • Wear occurs: • • • •

At the fuel assembly inlet (zone 1); When there is a change in diameter (zones 2 and 3); At the guiding outlet (zones 1 and 4); At the RPV outlet (zone 5);

• The deepest wear was measured at zones 1 and 4. These two zones are the only ones where through wall wear was observed (Fig. 21.100).

1786

21

Wear

Fig. 21.99 In-core instrumentation system of the 4-loop reactors. Drawing of the guiding columns. Wearing zones ② (top flange) and ③ (bottom flange) are indicated. The left column is a secondary support. Dimensions in mm

21.3

Destructive Examinations Results and Remediation

1787

Top of the thimble tubes

Bottom of the thimble tubes

Fig. 21.100 In-core instrumentation system. View of through wall wear. Left: wear zone #1 of thimble tube 29A11. Right: wear zone #4 of thimble tube 45N4

Metallography (thimble tube 45N4) The observation of the OD at high magnification shows that the worn zone presents horizontal ribs which indicate that the wear direction was perpendicular to the tube axis (Fig. 21.106). Axial and cross sections show the material loss due to wear along with the wall deformation. The significant wall deformation prevented the neutron probe from going inside the fuel assembly. The hollow shape of the wall at the thinnest location stems from the pressure difference between the OD (RCS pressure) and the ID. This thimble tube was leaking.

1788

21

Wear

Fig. 21.101 In-core instrumentation system. View of zone 1 wear; the cross section is located at the arrow elevation. The wear angular extension along with the thinnest wall area is indicated on the cross section. Top: thimble tube 26N8; middle: thimble tube 28J8; bottom: thimble tube 46R6

21.3

Destructive Examinations Results and Remediation

1789

Fig. 21.102 In-core instrumentation system. Thimble tube 46R6. View of zone 2 wear; the cross section is located at the black arrow elevation

Fig. 21.103 In-core instrumentation system. Thimble tube 26N8. View of zone 3 wear; the cross section is located at the black arrow elevation

1790

21

Wear

Fig. 21.104 In-core instrumentation system. Thimble tube 28J8. View of zone 5 wear; the cross section is located at the black arrow elevation

Fig. 21.105 In-core instrumentation system. View of zone 4 wear; the cross section is located at the black arrow elevation. Top: thimble tube 26N8; bottom: thimble tube 28J8; note that this tube is worn all over the circumference

21.3

Destructive Examinations Results and Remediation

1791

A

B

B

A

1 mm

1 mm

1 mm

1 mm

Fig. 21.106 In-core instrumentation system. Worn zone #4 of the thimble tube 45N4. Top left: OD view, note the transverse surface ribs. Top right: AA axial section. Bottom left: BB cross section. Bottom right: wall deformation (top right specimen polished)

1792

21

Wear

Conclusion, remedial action This DE helped refining the wear shape – NDE signal correlation. Thimble tubes wear results from the turbulent flow in the RPV bottom head, the thin tubes impacting the thick and stiffer guiding structures. The thimble tubes were replaced with thicker tubes to provide more margins for wear protection. The larger OD modifies the hydraulic conditions and the thicker tube wall allows deeper wear.

21.3.11

Destructive Examination of Four Thick Thimble Tubes of the in-Core Instrumentation System

Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: in-core instrumentation system, 4 thimble tubes (#26, #41, #46 and #47). The thick thimble tubes dimensions are: outside diameter = 8.6 mm (0.34’’) and wall thickness = 1.65 mm (0.065’’). The thimble tubes

Dimensions in mm

Thimble tubes

Fig. 21.107 Typical layout of the EDF 3 loops in-core instrumentation system at the bottom of the RPV. On the left drawing, the 6 wearing zones are indicated by P1 to P6

21.3

Destructive Examinations Results and Remediation

1793

are made of SS: Z5 CND 17.12 (AISI 316). Figure 21.107 shows the typical layout of the in-core instrumentation system at the bottom of the 3 loop reactors. The 6 wearing zones (P1–P6) are indicated. Operating conditions: OD: primary water, 155 bars (2,248 psi), temperature close to 285 °C (545 °F). Time of operation: 34,500 h. Failure discovery: thimble tubes wear was observed which can lead to the neutron probe locking and also to leak. To slow down this degradation, some units have been equipped with thicker tubes. 4 thick thimble tubes were harvested from this unit for assessment of the behavior of these thicker tubes after 34,500 h of operation. Similar event frequency: several EDF PWRs (both 3 and 4 loops) suffered from wear of the thimble tubes. Specimen/sample characteristics: the specimens were selected based on the ET inspection results. By selecting these 4 tubes, the operator tried to select as representative a set of tubes as possible of the worn zones population. The length of the various specimens ranges from 3 m (9.8 feet) to 3.6 m (11.8 feet). DE program and goal: wear characterization and assessment of the benefit brought by thicker thimble tubes. To achieve this, the DE results were compared with those obtained from a standard 3 loop reactor thimble tube (#06). The DE program included: dose measurements, localization of the worn zones along the tubes, measurement of the length, depth and angular extension of the worn zones. Results VT and laser profilometry The 0 elevation is the lower face of the core support plate (it is the reference for field NDE). Figures 21.108, 21.109, 21.110, 21.111, 21.112, 21.113 and 21.114 present some typical examples of each worn zone (P1–P6). P1 wear zone (which corresponds to the fuel assembly bottom nozzle elevation) is visible on all tubes. The P1 wear is deep on about 10 mm (0.41’’) long and then slowly decreases going up. P1 defect angular extension exceeds 180°, which is not the case for the other defects, all less than 180°. Upper (P1–P3) and lower (P4–P6) defects seem to be located at the opposite on a same diameter. Only one tube exhibits a shallow wear at the P6 elevation (20 µm/0.8 mils deep, Fig. 21.114). P3, P4 and P5 wear shape corresponds to the geometry of the guiding structure in front of their respective locations but a steep wear is also observed between P3 and P4 without being in

1794

21

Wear

120° rotation

Fig. 21.108 In-core instrumentation system. Thimble tube #46, worn zone #P1. Diameter (Y axis) and elevation (X axis) in mm

front of any geometry change. One explanation could be the 4 m (13 feet) displacement of the thimble tubes anytime the core is loaded or off-loaded. The deepest wear was observed at the P1 location of thimble tube 41: 350 µm (13.8 mils) which corresponds to 21% of the wall thickness.

21.3

Destructive Examinations Results and Remediation

1795

Fig. 21.109 In-core instrumentation system. Thimble tube #41, worn zone #P1. Diameter (Y axis) and elevation (X axis) in mm

Fig. 21.110 In-core instrumentation system. Thimble tube #41, worn zone #P2. Diameter (Y axis) and elevation (X axis) in mm

1796

21

Wear

120° rotation

Fig. 21.111 In-core instrumentation system. Thimble tube #26, worn zone #P3. Diameter (Y axis) and elevation (X axis) in mm

21.3

Destructive Examinations Results and Remediation

1797

Fig. 21.112 In-core instrumentation system. Thimble tube #46, worn zone #P4. Diameter (Y axis) and elevation (X axis) in mm

Fig. 21.113 In-core instrumentation system. Thimble tube #47, worn zone #P5. Diameter (Y axis) and elevation (X axis) in mm

1798

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Wear

Fig. 21.114 In-core instrumentation system. Thimble tube #47, worn zone #P6. Diameter (Y axis) and elevation (X axis) in mm

Metallography Sectioning of 3 worn zones have been performed: • On the P1 wear of thimble tube 41 (thick tube wall, deep wear); • On the P5 wear of thimble tube 26 (thick tube wall, shallow wear); • On the P4 wear of thimble tube 06 as a reference (“normal” tube wall thickness, deep wear). The results of the metallography are summarized in Table 21.9. This table provides the following: • For the P1 zone of tube #41 (Fig. 21.115), the cold work layer thickness ranges from 0 to 10 µm (0 to 0.4 mil) (Fig. 21.116). The oxide layer thickness is less than 4 µm (0.16 mil). No under layer crack is observed. • As for the P5 zone of tube #26 (Fig. 21.117), the same observations apply: the cold work layer thickness ranges from 0 to 10 µm (0–0.4 mil), the oxide layer thickness is less than 4 µm (0.16 mil) and no under layer crack is observed. The roughness is higher in the worn area (0.9 µm/0.035 mil) than in the sound area (0.5 µm/0.02 mil). • For the P4 zone of tube #06 (Fig. 21.118), the oxide layer is thicker with a maximum of 7 µm (0.28 mil). Cracks running parallel under the surface are observed 180° opposite of the maximum depth wear area (Fig. 21.119); the crack features indicate propagation by corrosion. No cold work layer has been evidenced. SEM observation confirms the oxide presence and reveals the

21.3

Destructive Examinations Results and Remediation

1799

Table 21.9 In-core instrumentation system. Summary of the metallography observations

Analysis Worn zone Roughness Out of worn zone Under layer cracking Surface oxides thickness (e) Indentations spacing SEM surface examination Thickness of the cold work layer

Zone P1 of tube #41, deep wear

Zone P5 of tube #26, shallow wear

Zone P4 of tube 06, deep wear

Dose rate too high to perform this measurement

Ra = 0.9 µm (0.035 mil) Ra = 0.5 µm (0.02 mil) No e < 4 µm (0.16 mil) 50–100 µm (2–4 mils)

Ra = 0.15 µm (0.006 mil) Ra = 0.8 µm (0.0315 mil) Yes e < 7 µm (0.28 mil) 50–100 µm (2–4 mils)

Dose rate too high

–

0,15%) for base metal and welds so as to mitigate FAC phenomenon for the remaining plant life.

25.3.11

Flow-Assisted Corrosion of High-Pressure Feed Water Heat Exchangers Low Carbon Steel Tubes (Coste and Rousvoal 2018)

Introduction The first high pressure feed water heat exchangers installed on French Nuclear Power Plants secondary circuits were originally made of low carbon steel. Because of the operating conditions (temperature and fluid velocity), flow assisted corrosion occurs and leads to progressive wall thickness losses. When the tube residual thickness reaches a value close to 20% (low carbon steels have a nominal thickness of 2 mm and a nominal outer diameter of 20 mm), a leak is likely to occur. If the leaking tube is not rapidly plugged (with a frame time of approximately 1 week), the risk of damaging the adjacent tubes increases with time. As a conservative measure, these tubes may also be plugged even though it drastically increases the total number of plugged tubes. The calculated limit for the feed water heat exchangers is around 15% plugged tubes. This maximum limit is related to the mechanically acceptable maximum pressure drop between inlet and outlet of the water box: beyond this value, there is a risk to plastically deform and break the separator plate between both sides of the water box. When flow accelerated corrosion is present in the bundle, the number of plugged tubes increases with the operating years. When the maximum design limit of 15% is reached, the heat exchanger has to be replaced. The replacement cost of two FW heat exchanger is approximately 8 M€ (the heat exchangers of both trains are often replaced at the same time for economics). The replacement lasts about 40 days. Taking into account the industrial capacity (manufacturing and mounting of heat exchangers), the economic aspect and the number of FW heat exchangers with low carbon steel potentially affected by FAC (216), EDF had to establish a replacement program at a national level.

25.3

Steam and Water Circuits

2083

High Pressure Heat Exchangers Fleet and Tube Material In the Table 25.4, EDF NPPs are sorted into 3 series: • CP0/CP1 series (24 units): two trains with one R5 and one R6 high pressure feed water heat exchangers each (R5 and R6 are set vertically); • CP2 and PALUEL series (14 units): two trains with one R5 and four trains with one RCS each. R5 and RCS are set horizontally. RCS heat exchangers cool the MSRs’ condensates; • 1300/N4 series (20 units): two trains with one R5 and one R6 each. R5 and R6 are set horizontally. EDF fleet is then composed of 216 high pressure feed water heat exchangers. Tubes are made of low carbon steel (ASTM A106 grade B) except the latest four 1300 family units and the four N4 family units, which tubes are made of ferritic stainless steel (AISI 444). So, in total only 32 high pressure feed water heat exchangers (out of a total of 216) are not sensitive to flow assisted corrosion. The tubes were manufactured before year 2000 and they are seamless tubes. All tubes have a nominal thickness of 2 mm. The new heat exchangers tubes are made of ferritic stainless steel (AISI444). Those tubes were manufactured after 2000 (year when the manufacturing process changed to rolled and weld tubes). Table 25.4 Main characteristics of EDF high pressure feed water heat exchangers Series

HX type

Operating pressure (bars)

Inlet temperature (°C)

Outlet temperature (°C)

Flow rate (kg/s)

Tube length (mm)

Tube OD (mm)

Total number of tubes

Flow rate per tube (kg/s)

CP0 CP1

R5 R6

70

183 200

200 220

758 758

17,404 12,444

18 18

2350 2350

0.322 0.322

CP2

R5 RCS

70

187 187

220 222

637 61

14,845 12,865

20 18

1670 263

0.381 0.232

Paluel

R5 RCS

80

182 186

205 235

924 100

14,255 12,100

20 18

2479 240

0.373 0.417

1300

R5 R6

80

177 201

201 227

1074 1074

15,400/ 14,615 15,580/ 15,200

20 20

3243 3255

0.331 0.330

N4

R5 R6

80

181 208

208 229

1201 1201

17,552 17,552

18 18

2943 2582

0.408 0.465

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Balance of Plant

Surveillance of Heat Exchangers Tubes The condition of high-pressure feed water heat exchanger tubes is regularly monitored during operation cycles and outages: – Efficiency monitoring: the heat transfer coefficient may decrease due to the presence of iron oxides (magnetite). In this case, tubes have to be cleaned mechanically (for example using high pressure water jet); – Drain flow rate monitoring: the drain flow rate (measured on the shell outlet) increases in case of tube leak. When reaching a threshold between 5 and 10 kg/s according to the feed water heat exchanger type, the high-pressure train concerned by the leak is isolated, the leak identified and the leaking tube is plugged; – A leakage test using helium is regularly performed during outages to check the integrity of the bundle; – Remote field eddy current testing: an inspection strategy of the remaining tube thickness has been set since 2008. A first inspection on 20% of the heat exchanger tubes has to be performed. Depending on the bundle condition, a second inspection is planned within 5 years with a sampling rate up to 100% of the tubes; – A hydraulic pressure test, specific to the French regulation on pressure equipment, has to be done every 10–12 years during outage. The loss of power production from the moment a leak is detected to the moment when the leaking tube is plugged is between 0 and 4 production days, due to the constrain of slightly reducing the reactor power to isolate the heat exchanger train. Moreover, when a leak is detected, it is necessary to plug the leaking tube as quick as possible (say less than one week) in order to avoid collateral damage on adjacent tubes by the steam jet from the leak. Tube Degradations Pitting Corrosion Pitting corrosion may affect the inner of tube made of low carbon steel and of ferritic stainless steel. The origin of this degradation is an uncomplete drying and cleaning of the tubes in outage. The presence of stagnant water within the tubes often leads to the initiation of small pits at the tube lower generating line. The small size of these cavities makes them undetectable by Eddy Current techniques. Only remote visual inspection may detect pitting corrosion; however, it is difficult to size the depth of pits by this means. An example of such degradations is given in Fig. 25.63: pitting corrosion was observed on a ferritic stainless-steel tube (R6 type feed water heat exchanger—1300 series). Small pits are clearly visible on both pictures. This mode of degradation is hopefully not very frequent and does not set the lifetime of feed water heat exchangers.

25.3

Steam and Water Circuits

2085

Fig. 25.63 Pitting corrosion inside a ferritic stainless-steel tube

Flow Assisted Corrosion (Outer Diameter) A specific degradation may be observed on heat exchanger tubes in low carbon steel from CP1 and 1300 series: close to particular drain or vent nozzles and due to specific thermo-hydraulic conditions, FAC may affect the external surface of the tube, inducing a wall thickness drop down to leakage. The steam jet from the leak may impact the adjacent tubes, generating leaks in turn. For the 1300 series, the area of the bundle affected by OD FAC is close to the two nearest vent nozzles (extraction of non-condensable gas) to the tube plates (one on each side of the exchanger—nozzle n°1 in Fig. 25.64). Figure 25.65 left shows the tube wall thinning near the gap plate. The degradations are localized on each side of the heat exchanger, close to the two nozzles as it can be clearly seen on the

Fig. 25.64 Schematic view of a high-pressure feed water heat exchanger (1300 series)

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map presented in Fig. 25.65 right. This mode of degradation affects only a small part of the bundle and can be managed by preventively plugging a few rows of tubes close to the nozzles. For the CP1 series, a very similar localized tube degradation occurs on the R5 feed water heat exchangers, close to the drains from the shell side of the R6 exchanger inlet nozzle (see Fig. 25.66).

Fig. 25.65 Left: FAC of tubes OD (1300 series). Right: cartography of plugged tubes (dark dots). Red arrows point at the position of the nozzles

Fig. 25.66 CP1 series. Left: schematic view of a feedwater R5 heat exchanger (dimensions in mm). Right: cartography of plugged tubes (dark dots). The red arrow points at the position of the nozzle

25.3

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2087

Fig. 25.67 Visual aspect of the tube inner surface due to flow assisted corrosion

Flow Assisted Corrosion (Inner Diameter) By flowing through the tubes, the feedwater induces some wall thinning over time. A typical visual aspect of the tube inner surface is given in Fig. 25.67. The wall thickness loss may be very different from one tube to another: there is no specific law and the degradation seems to randomly affect the bundle. This mode of degradation sets the lifetime of the equipment. Corrosion Rates for High Pressure Feed Water Heat Exchangers EDF has developed a software, named BRT-CICERO™, to evaluate wall thickness loss of pipes as a function of time. The corrosion rates for the heat exchangers described in Table 25.4 have been calculated using this EDF model. Results are presented in Table 25.5 for two pH values (low: 9.2 and high: 9.6). For these calculations, the chromium content has been taken equal to 0 (which corresponds to the maximum corrosion rate). For a given pH value, the main influencing parameters are the temperature and the flow rate of the feedwater. The corrosion rate is directly proportional to the flow rate and decreases almost linearly with the water temperature (see Fig. 25.68). For a Table 25.5 Corrosion rates for high pressure feedwater heat exchangers Series

Heat exchanger type

Inlet temperature (°C)

Flow rate per tube (kg/s)

Tube OD (mm)

Corrosion rate (mm/10,000 h) pH = 9.2 pH = 9.6

CP0/CP1

R5 R6 R5 RCS R5 RCS R5 R6

183 200 187 187 182 186 177 201

0.322 0.322 0.381 0.232 0.373 0.417 0.331 0.330

18 18 20 18 20 18 20 20

0.180 0.142 0.151 0.124 0.157 0.225 0.148 0.107

CP2 Paluel 1300

0.109 0.091 0.093 0.076 0.095 0.137 0.087 0.069

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Balance of Plant

Fig. 25.68 Impact of water temperature on corrosion rate (pH = 9.2, flow rate per tube = 0.3 kg/s, tube outer diameter = 20 mm, chromium content = 0%)

given unit, the tubes of the R5 heat exchangers are expected to lose thickness more rapidly than that of R6 heat exchangers: the difference between R5 and R6 corrosion rate, for a pH of 9.2, is −21% for the CP0/CP1 series and −28% for the 1300 series. Comparison Between Modelling and Remote Field Eddy Current Testing Measurements For each high-pressure feedwater heat exchanger family, the curve of the tube wall thickness loss as a function of operating time has been established using the EDF model with a chromium content of 0% (which is the most conservative situation: the corrosion rate is in fact maximum). For each operating cycle, the corrosion rate is calculated using the pH, calculated itself from the chemical composition of the feedwater during the cycle (ammonia, morpholine, ethanolamine and hydrazine content). The thickness loss during that cycle is then calculated from the corrosion rate and the operating time. At last it is corrected from the thinning effect described earlier. This curve has been compared to the thickness measurements made on real heat exchanger tubes during outage. The nondestructive method used for these measurements is remote field eddy current testing. A sampling rate of at least 20% of the total amount of tubes is recommended to obtain a good representativity of the whole bundle. An electromagnetic probe is inserted in the tube inlet and the measurement of the signal is achieved on the half-length of the tube (that is until the U bend). The maximum value of the thickness loss is then recorded as well as the

25.3

Steam and Water Circuits

2089

position where this maximum is achieved. For this comparison between calculated thickness and measured one, the mean value of the 10 tubes with the highest thickness loss is used (to avoid specific effects due to only one raw measurement). The accuracy of remote field eddy current testing is expected to be better than ±5% even though it was not completely assessed (an expertise program on tube extracted from a replaced heat exchanger is currently going on). The comparison between thickness measurements and calculation has been achieved for 12 R5-type heat exchangers from 3 series: • 1300, high pH, 2 heat exchangers from one unit (3 thickness measurements per exchanger); • 1300, low pH, 6 heat exchangers from 3 units (1 thickness measurement per exchanger); • CP2, 4 heat exchangers from 2 units (1 thickness measurement per exchanger). 1300 Series at High pH (see Fig. 25.69)

Thickness loss

For heat exchanger n°1 a rather good agreement is observed between the theoretical curve and the thickness measurements performed in 2009, 2010 and 2016 on the same exchanger. The evolution of the thickness loss with operating time follows the theoretical curve. For heat exchanger n°2, the corrosion rate is lower but the evolution of the thickness loss with operating time is also in good agreement with calculation. The difference of behavior between the two heat exchangers (same manufacturers, same operating conditions and chemistry) could be explained by a difference in chromium content in the chemical composition of tube materials.

Operation time (full power hours)

Fig. 25.69 Wall thickness loss vs operating time (1300 series—high pH)

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1300 Series at Low pH (see Fig. 25.70)

Thickness loss

Five out of the 6 thickness loss measurements are in good agreement with the theoretical curve. One measurement presents a wall thickness value which is higher than the calculated one (unit 3, heat exchanger n°1). By comparison with the previous curve (1300, high pH), the corrosion rate is much lower: the thickness loss is 61% for high pH and 88% for low pH after 177,000 operating hours.

Operation time (full power hours)

Fig. 25.70 Wall thickness loss vs operating time (1300 series—low pH)

Steam and Water Circuits

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Thickness loss

25.3

Operation time (full power hours)

Fig. 25.71 Wall thickness loss vs operating time (CP2 series—high pH)

CP2 Series (see Fig. 25.71) All four wall thickness measurements are below the calculated curve. For a same unit, the difference of thickness loss for the two heat exchangers is important. An explanation to this could be the difference of the chemical composition (chromium content) of the tube material. Evaluation of the End-of-Life of a HP Feedwater Heat Exchanger The end-of-life of a high-pressure feedwater heat exchanger may be defined as the moment where the bundle reaches its design maximum plugging limit (around 15%). This value is related to the mechanical resistance of the channel head divider plate: the pressure drop between the inlet and the outlet of the channel head increases with the number of plugged tubes until a maximum acceptable value depending on the heat exchanger series (around 4–5 bars (58–73 PSI)). The bundle condition may be assessed from remote field eddy current testing thickness loss measurements: for each tube, the wall thickness loss after a given operating time (t) may be calculated by extrapolating the wall thickness loss measured after an operating time (t’) using our model and more specifically using the tube thinning effect (provided that the pH of the feedwater does not change in the meantime). The end-of-life may be defined as the operating time (t) when the percentage of tubes with a wall thickness loss higher than 81% (as the result of the calculation of the limit of the tube mechanical resistance after thinning) is reached.

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Fig. 25.72 Evolution of the bundle condition. Left: after 178,241 h of operation (remote field eddy current testing thickness measurements). Right: after 237,656 h of operation (calculation)

To illustrate this methodology, the evolution of the bundle condition of a 1300 series (low pH) heat exchanger (unit 1—R5 n°1 in Fig. 25.69) is shown on Fig. 25.72 left (bundle condition in 2016 from the remote field eddy current testing thickness measurements on 649 tubes) and on Fig. 25.72 right (bundle condition from calculation). The operating time when the maximum plugging value is reached is 237,656 h. With a load factor of 0.78 (estimated from the history of the unit 1), it represents a remaining lifetime of 8.7 years after 2016. Conclusion The destructive examination of low carbon tubes pulled out from high-pressure feedwater heat exchangers has revealed that various degradation modes occurred, depending upon the exchanger series: i.e., flow assisted corrosion and pitting corrosion. These degradations lead progressively to tube leaks and power losses. Flow Assisted Corrosion affecting the inner part of low carbon tubes for all exchanger series is responsible for the major part of power losses and sets the lifetime of heat exchangers. A simple model using the BRT CICERO™ software has been developed to evaluate the corrosion rate of the tube wall. The results of this model were compared to wall thickness measurements obtained using remote field eddy currents. The agreement is rather good, especially for the 1300 series. Finally, the remaining lifetime of a heat exchanger may be estimated from the bundle condition obtained at a given time using remote field eddy current thickness measurements on a representative number of tubes. This assessment enables to optimize economically the replacement of feedwater heat exchangers suffering from flow assisted corrosion.

25.3

Steam and Water Circuits

25.3.12

2093

Examination of Cracks in Pressure Sensing Lines of the Feedwater System and the Strategy of NPP Goesgen for Replacement (Wermelinger and Schinhammer 2019)

Plant main characteristics: Goesgen is a 3-loop PWR built by KWU/Siemens with an output capacity of 1060 MWe. It started its commercial operation in 1979. Equipment/Component: the feedwater-system supplies the secondary side of the steam generators with water during normal operation. Operating conditions: from 1979 to 1982, a phosphate conditioning was used for the secondary side water chemistry. Since 1982, NPP Goesgen applies in the secondary water circuit the high all volatile treatment, in which hydrazine (N2H2) is used to set the pH-value above 9.8. During normal operation, the water of the secondary side has an oxygen concentration of tensile strength 272.0

359.7

392.3

25.3

Steam and Water Circuits

2121

Fig. 25.111 Pipeline movement during transient condition

S101 is under compression and S103 is under tension. Because of the screw loosening of S103 at its back end, it trips under the large transient tension, thus leads to the disconnecting of the hydraulic rod and the connector. Then the pipeline continues to move around the balance position until the amplitude gradually decreases and stops vibration (Fig. 25.111). Under the transient condition, the axial force amplitudes and varying trends of S101, S102 and S103 are basically the same for condition (1) and condition (2). The maximum values of the axial force are 35.2 KN, 40.0 KN and 110.5 KN, respectively which exceed the design load of (Table 25.8). Table 25.8 Comparison of calculated transient load and the design load Snubber number

Calculated transient load kN

Design load kN

S101 S102 S103

35.2 40.0 110.5

28.662 38.901 77.151

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According to the transient dynamics calculation, the failure process can be deduced as follows: (1) Before the emergency load rejection, there is a fatigue crack on the back end hydraulic rod of S102; (2) During the emergency load rejection, due to the sudden action of the main steam valve and the GCT-C valve, an intense two-phase flow happens in the pipeline between the main steam control valve at the inlet of the high-pressure cylinder and the GCT-C pipe. This leads to a large transient displacement at −Y direction and results in the interference between the rear end connector and the bracket. Fracture of the hydraulic rod occurs due to the instantaneous transverse load. At the same time, the front screw of S102 is also bent due to the instantaneous large load; (3) When the pipeline movement speed at the −Y direction decreased to 0 and started to move forward to the +Y direction, S103 is under tension. The fretting wear between the connector and the rod makes a gap generated. The transient large displacement in the +Y direction makes the rear hydraulic rod pulled out from the connector. Conclusion and Remedial Actions Brackets’ wrong installation and incorrect choice are main reasons for the hydraulic rod fracture and loosening. The poor purity of the base material of the hydraulic rod is the promoting factor for the fracture. At the same time, the excessive pipe vibration accelerates the threaded connection loosening and will form microcracks furtherly. Measures to solve the problem include: (1) Install the damper correctly according to the design requirements; (2) Make sure that the rated load of snubbers not less than the transient load during the normal operation; (3) Reduce the pipe vibration level in the steady-state operation to avoid looseness of the threaded connection; (4) Improve material purity and impact performance; (5) Optimize the snubber structure to reduce the intermediate threaded connection. Improve the connection reliability between snubber components. The relevant nuclear power plant has implemented the above measures (1), (2) and (4), in 2018. No similar events occur since such measures have been adopted.

25.4

Condenser

25.4

2123

Condenser

25.4.1 2013 Destructive Examination of a Brass Condenser Tube, from a Four-Loop Plant Plant main characteristics: Framatome PWR, 1300 MWe, 4 loops, France. Equipment/Component: condenser 2 CEX 104 CS. Box #4. 15 tubes spacer plates made of AFNOR E24.3. Operating conditions: ID: raw water (Loire river), pressure = 3 bars (43.5 PSI) and temperature *30 °C (86°F). OD: secondary water/steam, condenser vacuum. Time of operation: about 2 months. Failure discovery: a raw water ingress was detected on December the 12th 2013, into the condenser box #4. A helium test identified the tube #27 from the line #47 of the group # 10 as broken. A remote VT showed the rupture was localized at the first spacer plate, inlet side. The bundles of boxes #2, #4 and #6 had been refurbished at the previous outage. Because of installation difficulties in tubes removal/installation operations, the contractor had to install temporary supports at some tube spacer plates. Because of this first of a kind rupture, the relevant broken tube has been pulled out for destructive examination. Specimen/sample characteristics: rolled and welded (TIG process) brass tube (CuZn30As). Box #4, group #10, line #165, order #27 (CDS coordinates), Figs. 25.112 and 25.113. OD = 17.925 mm (0.706″), wall thickness = 1 mm (0.04″) and length = 13,845 m (45.42 ft). DE goal: failure root cause analysis. Results VT 6 segments, about 150 mm (6″) long each, of the broken tube were received at the laboratory. The rupture end does not exhibit any deformation or wear, only the spacer plate location is visible (Fig. 25.114). Circumferential indications are visible on the ID, a few millimetres away from the rupture (Fig. 25.115, left). After axial cut of the tube, these circumferential short indications are visible over half of the tube circumference (Fig. 25.115, right).

2124

25 Group 5

Group 6

Group 7

Group 8

Group 9

Group 4

Group 3

Group 10

Group 1 Group 2

Balance of Plant

Group 12 Group

Fig. 25.112 Condenser, box #4 map

Fig. 25.113 Location of the broken tube: box #4, group #10, line #47, tube n°27 (CDS coordinates: group #10, line #165, order #027)

25.4

Condenser

2125

Fig. 25.114 View of the segment containing the rupture (black arrow). The dotted line points at the weld

Fig. 25.115 ID circumferential indications

Micrography 8 specimens have been examined, see location on Fig. 25.116. SPECIMEN #1 (see location on Fig. 25.116)

Segment 0-1

Tube bottom Segment 3-4

Segment 1-2

Segment 4-5

Segment 2-3

Segment 5-R

Dimensions in mm

Fig. 25.116 Specimens’ locations (Ech = specimen, AC = chemical analysis)

Rupture

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The examination of the specimen #1, which corresponds to an axial section out of the broken area, reveals the presence of ID intergranular shallow cracks. These 50– 100 µm (2–4 mils) deep defects come with oxides deposits (Fig. 25.117). Pink spots call for copper presence (Fig. 25.118, left). The structure is normal (Fig. 25.118, right). These evidences call for a zinc de-alloying phenomenon. SPECIMEN #2 (see location on Fig. 25.116) This specimen has also been cut through a circumferential crack close to the rupture and exhibits similar features. However, some transgranular propagation is observed at cracks’ tips (Fig. 25.119). A circumferential indication caught by this section corresponds to an ID initiated crack (Fig. 25.120). Its propagation is transgranular, straight and slightly branched at the tip (Fig. 25.121).

Fig. 25.117 Specimen #1, ID, axial section, no etch. Intergranular propagation and oxides deposits

ID

OD

Fig. 25.118 Specimen #1, axial section. Left: detail of Fig. 25.117 left. Right: view after etching

25.4

Condenser

2127

Fig. 25.119 Specimen #2, ID, axial section. Propagation is intergranular at the crack mouth and transgranular at the crack tip. Left: no etch, polarized light. Right: after etching

Fig. 25.120 Specimen #2, ID, axial section. Transgranular circumferential crack. Left: no etch. Right: after etching

Fig. 25.121 Specimen #2, ID, axial section. Crack tip with little branching. Left: no etch, polarized light. Right: after etching

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Fig. 25.122 Specimen #3, ID, circumferential section. Overview after etching. Defects are localized in a limited sector

SPECIMEN #3 (see location on Fig. 25.116) A circumferential section shows that cracking is localized in a limited sector (Fig. 25.122). SPECIMEN #4 and SPECIMEN #5 (see location on Fig. 25.116) These specimens are defects free. SPECIMEN #6 (see location on Fig. 25.116) The specimen #6 has been cut in the middle of the as-received segment. The ID exhibits the first signs of damage: presence of oxides deposits and intergranular attack (Fig. 25.123). SPECIMEN #7 (see location on Fig. 25.116) The ID exhibits a damage similar to the one observed on the specimen #1, however, its depth seems inferior: 50 µm (2 mils) as compared to 50–100 µm (2–4 mils) for specimen #1 (Fig. 25.124). SPECIMEN #8 (see location on Fig. 25.116)

Fig. 25.123 Specimen #6, ID, axial section. Left: no etch. Right: IGA after etching

25.4

Condenser

2129

Fig. 25.124 Specimen #7, ID, axial section. No etch. Damage similar to specimen #1

Fig. 25.125 Specimen #8, ID, circumferential section. No etch. Left: overview. Right: detail of zone 2

In the same area, but on a circumferential section, the ID damage is visible on a sector of around 130° (Fig. 25.125). The material zinc depletion decreases when going away from the rupture. Transgranular cracks are observed only at the spacer plate location. SEM The rupture face is oxidized. The rupture occurred by two different mechanisms. Brittle areas are visible (Fig. 25.126).

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Fig. 25.126 SEM view of the brittle fracture

ID

Crack rim

Crack rim

ID

Fig. 25.127 ID circumferential crack. Specimen opened but not broken apart in laboratory. Left: LOM view. Right: SEM view; the central zone corresponds to the laboratory ductile tearing

A circumferential indication observed by VT has been opened but not broken apart in the laboratory (Fig. 25.127, left). The central zone corresponds to the ductile tearing from the laboratory fracture (Fig. 25.127, right). The defect rims are oxidized over a 50–100 µm (2–4 mils) width, thus, the intergranular nature of the defect cannot be confirmed in this zone. Beyond this zone, the surface appears transgranular with secondary cracks (Fig. 25.128).

25.4

Condenser

2131

Fig. 25.128 ID circumferential crack. Transgranular fracture with secondary cracks

EDS Analyses The first analysis bears on a zone where intergranular propagation, oxides deposits and pink spots have been observed. Cl traces have been detected (Fig. 25.129). EDS maps confirm that the deposits correspond to copper oxides and that some zinc is missing (Fig. 25.130, bottom left). Cl is also detected in this area (Fig. 25.130, top left). A second analysis bears on a crack tip (Fig. 25.131). EDS confirms the presence of Cl traces (Fig. 25.132).

Fig. 25.129 Specimen #A, circumferential section, ID, EDS analysis, Cl traces

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Fig. 25.130 Location of Fig. 25.129. K ray maps. Top left: Cl, top right: oxygen, bottom left: Zn and bottom right: Cu

Fig. 25.131 Crack tip EDS analysis: presence of Cl traces at the tip of a secondary crack

25.4

Condenser

2133

Fig. 25.132 Crack tip EDS maps. Left: Cl, middle left: O, middle right: Zn and right: Cu

Chemical Analysis The tube composition meets the specification for CuZn30As. The arsenic content is close to the middle of the specification (0.045 for 0.02/0.06% specified). The role of the arsenic is to reduce the risk of corrosion induced by Zn de-alloying. Hardness Measurements Hardness measurements have been carried out in the base metal of the segment containing the rupture. On axial section, the mean hardness is 71 HV1, whereas on circumferential section, the mean hardness is 77 HV1. These results meet the specification (75–105 HV) and are consistent with the fabrication MTR (76 HV1 on circumferential section). HV0.1 line scans did not evidence any difference between the bulk and the surfaces. Conclusion The various evidences gathered here call for a rupture under a SCC mechanism ID initiated in a Zn de-alloyed and depleted zone. This type of degradation has already been observed previously, however, always initiated in hard rolled zones, thus this case is unique so far. No root cause has been evidenced regarding the zinc de-alloying phenomenon. SCC initiation close to a spacer plate could be favoured by stress concentration at this location and pollutants concentration in the bottom of zinc de-alloyed pits, moreover, residual stresses from fabrication and installation may have play a role. Even if it may not be related, tubes installation was not trouble free: plastic caps deteriorated when running through the spacer plates and tubesheets, requirement for aligning some spacer plates using actuators in order to allow tubing. Additional tubes extractions are planned to improve this rupture mechanism understanding.

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Balance of Plant

25.4.2 2016 Destructive Examination of a Brass Condenser Tube, from a Four-Loop Plant Plant main characteristics: Framatome PWR, 1300 MWe, 4 loops, France (same as above). Equipment/Component: condenser 2 CEX 104 CS, box #4 (Fig. 25.112). 15 tubes spacer plates made of AFNOR E24.3. Operating conditions: ID: raw water (Loire river), pressure = 3 bars (43.5 PSI) and temperature *30 °C (86°F). OD: secondary water/steam, condenser vacuum. Time of operation: around 3 years. Failure discovery: following the 2013 destructive examination, 6 additional tubes were pulled out in July 2016 for the hereafter reasons: • Supplement to Group #10, line #165, order #027, to confirm the previous destructive examination results; • Group #10, line #168, order #022: characterization of an EC indication; • Group #10, line #163, order #029: characterisation of the impact EC indication; • Group #04, line #104, order #008; too short hard roll in 2013; • Group #05, line #052, order #013; tube located in a zone where tubes replacements were difficult in 2013; • Group #06, line #048, order #007, too short hard roll in 2013. Specimen/sample characteristics: rolled and welded (TIG process) brass tube (CuZn30As). Box #4, group #10, line #165, order #27 (CDS coordinates. OD = 18 or 17.925 mm (0.709 or 0.706″), wall thickness = 1 mm (0.04″) and length = 13,750 m (45.11 ft). DE goal: the destructive examination goal has been split into 4 categories: • Confirmation of the 2013 destructive examination results (supplement to group #10, line #165, order #027); • Characterization of EC indications (tubes Group #10, line #168, order #022 and group #10, line #163, order #029); • Check for the impact of the tubing problems on the tubes condition (tubes group #04, line #104, order #008; group #05, line #052, order #013 and group #06, line #048, order #007) and • Check for the impact of a progressive abrasion, in term of wall thickness decrease, on the remaining life of the tubes. Results Dimensional Measurements The OD and wall thickness have been measured on each tube.

25.4

Condenser

2135

Fig. 25.133 Angles reference

The weld has been taken as angle 0°. Angles increase clockwise when looking in the flow direction (Fig. 25.133). Dimensional measurements are carried out at angles 45, 135, 225 and 315°. The OD measurements results are reported in Fig. 25.134 and wall thickness results in Fig. 25.135. A first analysis of the dimensions shows: • Regarding OD results, except for tube group #06, line #048, order # 007, all tubes have homogeneous values and superior to the nominal vendor specification; • For the two first categories (broken and with EC indication), pulled out from group #10, the thickness does not deviate from the nominal thickness value and the figures are homogeneous;

Fig. 25.134 Tubes diameters in mm. Red dotted lines: specification. Tubes segment inlet and outlet are measured out of the hard roll zone

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Balance of Plant

Fig. 25.135 Tubes wall thickness in mm. Red dotted line: specification. Tubes segment inlet and outlet are measured out of the hard roll zone

• For the third category (tubes with difficulties at installation/removal), pulled out from groups #4, #5 and #6, the thickness is clearly inferior to the expected figure, by 11.3% in average, and even more for the minimum thickness outlet of tubes group #04, line #104, order #008 and group #05, line #052, order #013). The thickness loss is rather homogeneous for each tube (between generatrixes and ends) and also between these 3 tubes. The results of the dimensional measurements seem to confirm a progressive abrasion mechanism (or erosion by abrasion), however this abrasion mechanism is not observed on the group #10 of tubes. Micrography On each of the following tubes: • • • •

Group Group Group Group

#10, #10, #10, #06,

line line line line

#165, #168, #163, #048,

order order order order

#027; #022: #029; #007;

the visual examination shows the presence of printed numbers: “17.925 mm  1 mm”, which can be assumed as OD and wall thickness dimensions.

25.4

Condenser

2137

BROKEN TUBE: group #10, line #165, order #027 This tube was received in14 segments, from 595 to 1227 mm (23.4–48.3″) long (Fig. 25.136). No apparent deformation is visible. There are some colours’ variations, from yellow/orange to blue/black. Some black zones are also observed with an apparent periodicity, which are the spacer plates’ locations. Several bright scratches from contact with the spacer plates during the extraction out of the condenser are visible (Fig. 25.137). The hard roll is visible outlet or tubesheet side. The opposite tube end exhibits one face of the rupture, the other face having already been sent to the laboratory in 2013 for destructive examination. This rupture was located at the first spacer plate location, inlet side. Despite the field repair (introduction of a cone into the tube to hold it in place), the surface did not experience major damage and thus can be examined. The tube ID exhibits some circumferential cracks close to the rupture (Fig. 25.138).

Inlet

Outlet

Fig. 25.136 Tube group #10, line #165, order #027, as-received at the laboratory

Fig. 25.137 Tube group #10, line #165, order #027, as-received at the laboratory. View of OD fresh scratches

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Balance of Plant

Fig. 25.138 Tube group #10, line #165, order #027, view of the rupture end

The VT of the tube ID shows: • The presence of circumferential cracks close to the rupture at the spacer plate #1 location (Fig. 25.139), all around the circumference; • The presence of circumferential cracks at the next tubes spacer plates. Their number decreases with the distance from the first plate and they disappear after the plate #5 (Fig. 25.140). Fig. 25.139 Tube group #10, line #165, order #027, view of the rupture zone

Weld

90∞weld

25.4

Condenser

2139

Fig. 25.140 Tube group #10, line #165, order #027, circumferential cracks. Left: spacer plate #4. Right: spacer plate #5, last plate location exhibiting cracks. White line: axial section location

TUBE WITH EC INDICATIONS: group #10, line #168, order #022 16 tube segments were received at the laboratory with lengths ranging from 69 to 1308 mm (2.72–51.5″); as opposed to the broken tube, the tube segment between the inlet and the first tube spacer plate is present here. The same range of colours as on the tube group #10, line #165, order #027 is observed again. On the OD, the tubes spacer plates locations are visible because of the oxidation of these plates. Fresh scratches are also visible (Fig. 25.141). The tube ID exhibits two axial linear indications: • The first one is located in the first 300 mm (12″), inlet side, close to the weld line, with a length limited to 40 mm (1.6″) (Fig. 25.142); • The second one is at angle 160° (0° = weld) and runs from the tube inlet to the first spacer plate, it looks like grey/green oxides deposits (Fig. 25.143). For clarification purpose, cross sections are going to be carried out on these two indications.

Fig. 25.141 Tube group #10, line #168, order #022, OD. Left: spacer plate #1 location, fresh axial scratches. Right: spacer plate #2 location, axial and zig-zag fresh scratches

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25

Balance of Plant

Section plan Flow direction

Fig. 25.142 Tube group #10, line #168, order #022, ID. Top: view of the axial linear indication following the weld. Bottom left: Zone A. Bottom right: zone B

Cross section plan Axial linear indication

Axial linear indication

Fig. 25.143 Tube group #10, line #168, order #022, ID. View of the axial linear indication at angle 160° (0° = weld line)

TUBE WITH EC INDICATIONS: group #10, line #163, order #029 17 tube segments were received at the laboratory with lengths ranging from 72 to 1101 mm (2.83–43.3″). The OD aspect is similar to the tube group #10, line #168, order #022 one (Fig. 25.144). The text print visible at the spacer plate #1 location (Fig. 25.144, right) is from the vendor (“Valtimet”). The fact this text is still visible shows this tube has not been operating for long.

25.4

Condenser

2141

Fig. 25.144 Tube group #10, line #163, order #029, OD, axial scratches, spacer plate #1. Left: angle 0° (weld line). Right: angle 180° (opposite to the weld)

Fig. 25.145 Tube group #04, line #104, order #008, OD. Left: theoretical spacer plate #1 location. Right: spacer plate #2 location

A careful ID VT did not evidence any defect, including at the EC indication location. No further examination will be carried out on this tube. TUBE WITH INSTALLATION ISSUES: group #04, line #104, order #008 22 tube segments were received at the laboratory with lengths ranging from 67 to 1001 mm (2.64–39.4″). As opposed to the other tubes, the tube spacer plate #1 location is not visible on the OD of this tube, whereas the other spacer plates locations are clearly visible from marks likely resulting from tube/plate contact (Fig. 25.145). The spacer plate #1 location has been deformed by the tool used to pulled out the relevant tube segment (Fig. 25.145, left). Nothing worth to be mentioned has been evidenced on the ID, except white deposits and green spots (Fig. 25.146). TUBE WITH INSTALLATION ISSUES: group #06, line #048, order #007 12 tube segments were received at the laboratory with lengths ranging from 743 to 1443 mm (29.6–56.8″). As compared with the previous tube, the zones of tube/spacer plate contact are less visible.

2142

25

Balance of Plant

Fig. 25.146 Tube group #04, line #104, order #008, ID, angle 0° (weld line). Left: spacer plate #2. Right: spacer plate #3

Fig. 25.147 Tube group #06, line #048, order #007, OD, tube spacer plate #1. Left: angle 0° (weld line). Right: angle 180°

This tube OD exhibits axial scratches (Fig. 25.147, left) and vendor text print (Fig. 25.147, right). The ID is defect-free. TUBE WITH INSTALLATION ISSUES: group #05, line #052, order #013 41 tube segments were received at the laboratory with lengths ranging from 27 to 1233 mm (1.06–48.5″). The tube deformations along with the high number of segments call for problems to pull this tube out of the condenser (Fig. 25.148). The ID is defect-free, only damage induced by the extraction tools are visible.

25.4

Condenser

2143 Outlet

Inlet

Fig. 25.148 Tube group #05, line #052, order #013, OD, presence of deformations

Micrography BROKEN TUBE: group #10, line #165, order #027 The rupture occurred close to the spacer plate #1. Close to the rupture, cracks are visible (Fig. 25.149, top). They are ID initiated, rather linear, transgranular and with branched tip Fig. 25.149, bottom). This cracking morphology is typical from SCC. The maximum crack’s depth is 0.29 mm (11.4 mils) on Fig. 25.149; of course, the tube broke from a deeper crack. Metallic copper is present in oxides and into the crack the closest to the rupture (Fig. 25.150). This translates into a de-alloying mechanism with zinc release. OD

ID

Zone 1 (broken)

Flow direction

Fig. 25.149 Tube group #10, line #165, order #027, ID. Circumferential cracks close to the rupture. Bottom left: zone #4 after etching. Bottom right: zone #3 after etching

2144

25

Balance of Plant

Fig. 25.150 Tube group #10, line #165, order #027, ID. Left: rupture face section after etching. Right: zone 5 detail, Cu presence into the crack

OD

ID

Flow direction

Fig. 25.151 Tube group #10, line #165, order #027, ID. Top: spacer plate #2 location. Bottom left: detail of zone 1 after etching. Bottom right: detail of zone 4 after etching

As for the spacer plate #1 location, cracks are also observed at the spacer plate #2 location (Fig. 25.151) with the following characteristics: ID initiated, linear and transgranular and branched. The maximum crack depth at this spacer plate location is 0.42 mm (16.5 mils).

25.4

Condenser

2145

Cu is again observed into the oxides because of de-alloying (Fig. 25.152). The spacer plate #5 location is almost crack free (Fig. 25.153, top). The few cracks observed there have similar characteristics as the cracks observed elsewhere. The only differences are: they are fewer and they are less deep (Fig. 25.153, right). Metallic copper is once again observed as the consequence of a de-alloying mechanism (Fig. 25.153, left).

Fig. 25.152 Tube group #10, line #165, order #027, ID, spacer plate #2 location. Left: detail of zone 2 after etching. Right: detail of zone 3 after etching, Cu presence

OD

ID Flow direction

Fig. 25.153 Tube group #10, line #165, order #027, ID. Top: spacer plate #5 location. Bottom: detail of zone 1. Left: Cu presence. Right: after etching

2146

25

Balance of Plant

Fig. 25.154 Tube group #10, line #165, order #027, ID, circ. section at 850 mm from the tube outlet. Left: after etching, attack limited to 2 or 3 grains. Right: Cu presence

To check the cracks density “decrease with the flow direction”, a last section has been performed at 850 mm (33.5″) from the tube outlet. Some indications, no deeper than 2–3 grains are visible at the ID (Fig. 25.154, left). Metallic copper is also present (Fig. 25.154, right). In conclusion, SCC cracks are present along with de-alloyed zones. This result is consistent with the result of the other broken segment destructive examination performed in 2013. The damage is decreasing along with the distance from the spacer plate #1. TUBE WITH EC INDICATIONS: group #10, line #168, order #022 A cross section of the weld at the EC indication location does not evidence any surface breaking defect (Fig. 25.155). However, an interdendritic cavity, from hot cracking, 60 µm (2.4 mils) deep, is visible on Fig. 25.155 right. Another cross section, at the location of the second EC indication of this tube, at angle 160°, does note evidence any defect either. Thus, the two EC indications remain unexplained. TUBE WITH INSTALLATION ISSUES: group #04, line #104, order #008 A cross section in the weld area reveals corrosion/oxidation spots both at ID and OD, along with a weld defect (gas bubbles, Fig. 25.156). Once again, metallic copper is present (Fig. 25.157).

25.4

Condenser

2147

Fig. 25.155 Tube group #10, line #168, order #022, ID, after etching. Top: weld cross section showing the absence of surface breaking defect at the EC indication location. Bottom left: detail of zone #1. Bottom right: detail of zone #2

Hardness Measurements (HV1 and HV0.1) Hardness measurements show: • The tube with installation issues (group #04, line #104, order #008) exhibits a hardness slightly superior to the hardness of the broken tube (group #10, line #165, order #027); • A microhardness profile similar for all tubes, both in axial and circumferential directions, with a minimum in the centre and a higher hardness at OD for the broken tube (group #10, line #165, order #027); • Hardness figures similar to those obtained on the first segment of the broken tube received in 2013. The NF EN 12 451 (dated from August the 18th, 2012) specification states that the CuZn30As brass hardness should be in the 75/105 HV range. The results meet this specification; however, some values exceed the lower limit.

2148

25

Balance of Plant

Gas bubbles

Fig. 25.156 Tube group #04, line #104, order #008. Top: circumferential section at the weld line. Bottom left: zone A detail after etching. Bottom right: zone B detail after etching

Fig. 25.157 Tube group #04, line #104, order #008, ID. Zone C detail. Left: no etch. Right: after etching

25.4

Condenser

2149

Conclusion The examination of the remaining segments of the broken tube (group #10, line #165, order #027), supports the conclusion drew from the 2013 destructive examination of the first tube segment received at the laboratory. The rupture under a SCC mechanism is supported by this new destructive examination. The news is that cracking is present elsewhere at the tube ID with an intensity decreasing along with the distance from the spacer plate #1 following the flow direction. In general, the hardness is inferior to the hardness measured on the tube segment examined in 2013. As concern the tubes with EC indications (tube group #10, line #168, order #022 and tube group #10, line #163, order #029), no defect has been found that can be related to any of these EC indications. Regarding the tubes with problems at installation, no evidence has been found that could explain these difficulties. Last, three tubes exhibit some limited and progressive wall thickness decrease by erosion/abrasion.

25.4.3 Destructive Examination of Titanium Condenser Tubes from a Three-Loop Plant Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: Condenser 3 CEX 001 CS. Operating conditions: ID: sea water, inlet = 11 °C (51.8°F), outlet = 22,5 °C (72.5°F), pressure = 3 bars (43.5 PSI). OD: low pressure steam, pressure: 45.7 mbar (0.67 PSI). Time of operation: tubes pulled out in 2010: 29 years, tubes pulled out in 2012: 31 years. Failure discovery: during the leak test of the space between the carbon steel and the Cu–Al alloy tubesheets of the box #3 in 2009, many leaking tubes were detected at both inlet and outlet tubesheets ending up in the plugging of 181 tubes. During the 2010 outage, an EC inspection was performed. As the result of this inspection, 5 tubes were pulled out from the condenser (red circles on Fig. 25.158). Because these 5 tubes were severely damaged during the extraction, their destructive examination resulted in incomplete information. Thus, a second series of 12 tubes was pulled out in 2012 (black, green and purple circles on Fig. 25.158). Specimen/sample characteristics: rolled and welded titanium grade 2 tubes. OD = 19 mm (0.75″), wall thickness = 500 µm (19.7 mils). See the tubesheets/ tubes junction on Fig. 25.159.

2150

25 Group A

Balance of Plant

Group B Group

Group

Group E

Group F

Group

Group

Fig. 25.158 Localization of the pulled tubes. Red and black circles: box #3. Green circle: box #2 and purple circle: box #4

VDA zone

Hard Roll

VDAB zone

Zone between tubesheets

VDC zone

Hard Roll

Free span

Conventional Island Demineralized Water

Steam

Carbon steel

Fig. 25.159 Tubesheets/tubes junction and definitions (dimensions in mm)

Sea water Cu-Al alloy

25.4

Condenser

2151

DE goal: First series of 5 tubes: • • • •

Checking for the presence of cracks; Localizing the cracks; Finding the cracking root cause and Improving the understanding of the damage mechanism. Second series of 12 tubes:

• Check whether the damage mechanism found previously was active at the outlet of the carbon steel tubesheet (sea water ingress risk); • Describe in detail the cracking features; • Check for the role of the anodes on cracking and • assess the damage extension over the various condenser boxes. The Issue Except one particular plant, the condensers of the French sea water plants are equipped with titanium tubes and Cu-Al alloy tubesheets. Twinning these two materials in contact with sea water induces a galvanic coupling risk, the Cu-Al tubesheet playing the role of sacrificial anode for the titanium tube bundle, titanium being nobler. In order to mitigate this galvanic coupling risk, a cathodic protection using applied current has been installed at sea water plants. One of the difficulties is maintaining the potential at a target value. When the potential exceeds an upper limit, a major hydrogen adsorption and diffusion takes place in the tubes bulk. Given the very low solubility of hydrogen in the alpha matrix of the grade 2 titanium, this hydrogen will end up in forming titanium hydrides from TiHx type. In addition to the applied potential, hydrides formation is enhanced by several factors, including: • The temperature: hydrides formation is a thermally activated mechanism; • The hydrogen exposure time; • The presence of a surface passive film: this film slows hydrogen diffusion into the material; • The cold work level: the higher the cold work, the larger will be hydrides formation; • The stresses: high stresses enhance hydrides formation. Moreover, the hydrides orientation is stresses dependent; • The pH: a low pH enhances hydrides formation and • The material structure: given the hydrogen low solubility in the monophasic alpha structure, the titanium grade used in plants is more susceptible to hydrides formation than biphasic alpha/beta or monophasic beta structures.

2152

25

Balance of Plant

Field Experience Hydrides formation in titanium tubes has been observed at two US plants in 1987 for which the protection potential was not properly applied. At EDF, several tubes pulled out of 7 different units have already been examined in laboratory. These examinations have shown that the hydrides formation mechanism mainly occurs at tubes ID, inlet and outlet sides. The hydrides layer contains elongated needles and can reach 100 µm (4 mils) thick, or 20% of the tube wall thickness. This layer is around 200 mm (8″) long, and decreases with the distance from tubes ends. Isolated hydrides have also been observed into the tube wall which seem to decrease from ID to OD. Although the ID hardness is influenced by hydrides presence, mechanical testing close to tubes ends does not evidence any properties change due to this hydride’s presence. Results Obtained on the First Series of 5 Tubes Pulled Out in 2010 As-Received Condition These tubes present severe deformations from their extraction from the condenser (Fig. 25.160). VT TUBE GROUP #D, LINE #125, ORDER #007 Except severe deformations, this tube segment does not exhibit any defect. TUBE GROUP #F, LINE #182, ORDER #033 OD tearing results from pulling the tube out of the condenser (Fig. 25.161). Cracks are visible close to the rupture from extraction (Fig. 25.162). Circumferential cracks either through-wall or not through-wall are visible in the VDC area. On the ID, axial and circumferential cracks can be observed close to the rupture, VDC side (Fig. 25.163). As concerns the VDAB area, a circumferential crack-like indication is visible (Fig. 25.164). TUBE GROUP #E, LINE #161, ORDER #034 This tube exhibits similar damage as tube group #F, line #182, order #033. TUBE GROUP #H, LINE #184, ORDER #006 This tube exhibits similar damage as tube group #F, line #182, order #033.

25.4

Condenser

Group #B, line #050, order #008

Group #D, line #125, order #007

Group #E, line #161, order #034

Group #F, line #182, order #033

Group #H, line #184, order #006

Fig. 25.160 First series of tubes in as-received condition

2153

2154

25

Balance of Plant

Fig. 25.161 Tube group #F, line #182, order #033. Top: view in as-received conditions. Bottom left: detail VDC. Bottom right: through-wall defect in VDC area

Fig. 25.162 Tube group #F, line #182, order #033. Top: detail of the rupture, VDC area. Bottom left: detail zone A. Bottom middle: detail zone B. Bottom right: detail zone E

25.4

Condenser

2155

Fig. 25.163 Tube group #F, line #182, order #033. ID axial and circumferential cracks

Fig. 25.164 Tube group #F, line #182, order #033. Circumferential indication, VDAB side

Scanning Electron Microscope Examination TUBE GROUP #F, LINE #182, ORDER #033 The specimen taken out of the VDC zone exhibits a brittle aspect along with multiple cracks visible over the whole tube thickness (Fig. 25.165). As observed on tube group #E, line #161, order #034, the transgranular propagation is fragile. TUBE GROUP #E, LINE #161, ORDER #034. The VDC side specimen exhibits a brittle and transgranular rupture (Fig. 25.166).

2156

25

Balance of Plant

Fig. 25.165 Tube group #F, line #182, order #033. Brittle features

Hydrides presence on ID

Fig. 25.166 Tube group #E, line #161, order #034. Brittle features

TUBE GROUP #H, LINE #184, ORDER #006 The specimen exhibits the same features as previously observed VDC side except a circumferential cracking observed close to the inside surface (Fig. 25.167). Metallography TUBE GROUP #D, LINE #125, ORDER #007 The specimen #1 is crack free. The tube wall thickness is 430 µm (17 mils) in the hard roll area whereas it is 490 to 500 µm (19.3–19.7 mils) in the free span (Fig. 25.168). Band of hydrides, about 60 µm (2.4 mils) thick are present on the ID (Fig. 25.169, left) and more scarcely in the bulk and with a tilted orientation (Fig. 25.169, right).

25.4

Condenser

2157

Fig. 25.167 Tube group #H, line #184, order #006. Brittle aspect and secondary axial cracks (right: zone B of the left image)

Carbon steel tubesheet Specimen #2

Cu-Al alloy tubesheet and VDC side Specimen #1

OD ID

Fig. 25.168 Tube group #D, line #125, order #007 specimen. The tube is thinner in the hard-rolled area

Fig. 25.169 Tube group #D, line #125, order #007, specimen #1. Left: band of hydrides in the ID cold-worked layer, in the Cu-Al alloy tubesheet zone. Right: tilted hydrides in the bulk, also in the cold-worked material from hard-rolling

2158

25

Balance of Plant

Fig. 25.170 Tube group #D, line #125, order #007, specimen #1. Hydrides precipitation in the zone between the two tubesheets

Between the tubesheets, a hydrides precipitation is seed for needles formation at the ID (Fig. 25.170). The specimen #2 is also crack free. TUBE GROUP #F, LINE #182, ORDER #033 Specimen #1 Circumferential cracks (ID and OD initiated) are observed on the tube, in the Cu-Al alloy tubesheet zone (Fig. 25.171). After etching, the specimen hydrides appear as (Fig. 25.172): • Hydrides present at both ID and OD, with a radial orientation in the Cu–Al alloy tubesheet zone (Fig. 25.173); • In the roll transition zone, some axial hydrides form an ID layer, whereas others hydrides are radial over the first ID half wall thickness (Fig. 25.174, left);

Print from extraction

Cu-Al alloy tubesheet limit

Fig. 25.171 Tube group #F, line #182, order #033, specimen #1. View of ID and OD circumferential cracks

25.4

Condenser

2159 OD

ID

Fig. 25.172 Tube group #F, line #182, order #033, specimen #1. View after etching

Fig. 25.173 Tube group #F, line #182, order #033, specimen #1. Zone C detail. Hydrides present in the Cu-Al alloy tubesheet zone

• In the zone between the two tubesheets, the hydrides are axial over a layer 40 µm thick at the ID (Fig. 25.174, right). Specimen #2 In the carbon steel tubesheet zone, the tube exhibits an almost through-wall circumferential indication (Fig. 25.175). After etching, this indication appears as a hydrides alignment, initiated in a 60 µm (2.4 mils) thick hydrides ID layer and running up to the OD where it is 20 µm (0.8 mil) wide (Fig. 25.176).

2160

25

OD

Balance of Plant

OD

ID

ID

Fig. 25.174 Tube group #F, line #182, order #033, specimen #1. Left: zone A detail; axial and radial ID hydrides present in the roll transition zone. Right: zone B detail; axial hydrides in free span (less than 40 µm (1.6 mils) thick layer)

ID

OD Carbon steel tubesheet limit

Fig. 25.175 Tube group #F, line #182, order #033, specimen #2. Circumferential crack in the carbon steel tubesheet zone

ID

OD

Fig. 25.176 Tube group #F, line #182, order #033, specimen #2 after etching. Through-wall hydrides alignment in the carbon steel tubesheet zone

25.4

Condenser

2161

TUBE GROUP #E, LINE #161, ORDER #034 Specimen #1 (VDC side) The VDC side specimen exhibits an OD initiated crack (Fig. 25.177, left). This crack propagates into radial hydrides. A local copper deposit is visible at OD, likely as the result of the tube extraction process (Fig. 25.177, right). In the Cu-Al alloy tubesheet hard roll zone, radial hydrides can be through-wall (Fig. 25.178). Specimen #2 (VDAB side) Between the tubesheets, band of hydrides are visible (Fig. 25.179, left). In the bulk, hydrides have various orientations (Fig. 25.179, right).

OD

Cu deposit

Extraction damage ID

Fig. 25.177 Tube group #E, line #161, order #034, specimen #1. Left: crack in the Cu-Al alloy tubesheet zone. Right: extraction print and OD copper deposit

ID

OD

Fig. 25.178 Tube group #E, line #161, order #034, specimen #1. Through-wall radial hydrides

2162

25

Balance of Plant

Fig. 25.179 Tube group #E, line #161, order #034, specimen #2. Zone between the tubesheets. Left: ID bands of hydrides. Right: bulk hydrides

TUBE GROUP #H, LINE #184, ORDER #006. Specimen #1 (Cu-Al alloy tubesheet side) This specimen exhibits OD radial cracks corresponding to the cracking of hydrides alignments, this cracking can be 60% through wall (Fig. 25.180, left). The ID hydrides layer is 60 µm (2.4 mils) thick and contains cracks propagating into radial hydrides (Fig. 25.180, middle and right). Specimen #2 (carbon steel tubesheet side) This specimen also exhibits OD radial cracks corresponding to the cracking of hydrides alignments, this cracking can be 60% through wall (Fig. 25.181). The ID hydrides layer is 60 µm (2.4 mils) thick. ID

OD

Fig. 25.180 Tube group #H, line #184, order #006, specimen #1. Left: OD, 60% through-wall crack propagated in hydrides. Middle: ID, 60 µm (2.4 mils) thick hydrides layer. Right: middle picture detail, radial crack propagated in hydrides

25.4

Condenser

2163 OD

ID 1 mm

Fig. 25.181 Tube group #H, line #184, order #006, specimen #2. OD radial cracks corresponding to the cracking of radial hydrides

Results obtained on the second series of 12 tubes pulled out in 2012 VT TUBE GROUP #D, LINE #135, ORDER #010 An ID PT reveals the presence of 2 linear axial indications, located close to extraction scratches in the VDAB zone (Fig. 25.182). TUBE GROUP #B, LINE #080, ORDER #002 Mechanical damage is observed on the OD. TUBE GROUP #D, LINE #140, ORDER #015 OD defects are visible in the VDAB zone (Fig. 25.183, left). These defects are through-wall as also visible at ID (Fig. 25.183, right). TUBE GROUP #E, LINE #153, ORDER #017 This tube has been broken at two locations, one being in the carbon steel tubesheet zone (Fig. 25.184, top). This later goes with a deformation and an axial weld

Fig. 25.182 Tube group #D, line #135, order #010. Left: ID PT. Right: detail B

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Fig. 25.183 Tube group #D, line #140, order #015. Left: axial crack in the VDAB zone. Right: ID view of the same crack

Deformation

Weld

Fig. 25.184 Tube group #E, line #153, order #017. Top: overview of the tube broken at 2 locations. Bottom: zone A, deformation and axial tearing along the weld

tearing (Fig. 25.184, bottom). Similar deformation and axial cracking are observed at the second rupture (Fig. 25.185, left). A similar tearing is observed in the VDC zone (Fig. 25.185, right). TUBE GROUP #D, LINE #147, ORDER #009 The carbon steel tubesheet zone exhibits damages from the extraction tool. TUBE GROUP #E, LINE #153, ORDER #014 This tube exhibits the same damage as the tube group #E, line #153, order #017.

25.4

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Fig. 25.185 Tube group #E, line #153, order #017. Left: zone B, deformation by the extraction tool and axial tearing along the weld. Right: zone C, axial crack in a zone deformed by the extraction tool

TUBE GROUP #E, LINE #161, ORDER #032 This tube does not present any particular damage or indication. TUBE GROUP #C, LINE #140, ORDER #002 This tube does not present any particular damage or indication. TUBE GROUP #C, LINE #048, ORDER #015 Except a metal overlap in the carbon steel tubesheet zone, this tube does not present any particular damage or indication. TUBE GROUP #D, LINE #135, ORDER #012 This tube does not present any particular damage or indication. TUBE GROUP #C, LINE #080, ORDER #002 This tube exhibits a weld tearing, as a consequence of its pulling out from the condenser. TUBE GROUP #G, LINE #193, ORDER #046 The rolled areas are so damaged that this tube cannot be examined. Metallography TUBE GROUP #D, LINE #135, ORDER #010. Specimen BD In the free span, the ID layer has a low hydrides density (Fig. 25.186, left). Other tilted hydrides are present in the VDA zone (Fig. 25.186, right). In the carbon steel tubesheet zone, the wall is cold worked over its whole thickness, more ID hydrides are present and axial hydrides are visible in the bulk material.

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OD

ID

ID

Fig. 25.186 Tube group #D, line #135, order #010, specimen BD. Tilted hydrides close to the ID (before and after etching)

Specimen DC The section crosses the two axial PT indications previously mentioned. Several defects are visible on the ID. The two PT indications are the larger ones (Fig. 25.187, left and right). The cracks propagated into hydrides alignments (Fig. 25.187, middle). TUBE GROUP #B, LINE #080, ORDER #002 An axial section covering the VDA and VDAB zones reveals a significant cold work in the carbon steel tubesheet zone as compared the non-cold worked free span structure and the absence of crack.

OD

OD

ID ID

Fig. 25.187 Tube group #D, line #135, order #010, specimen DC. Left: cross section of an axial PT indication. Right: cross section of the second axial PT indication. Middle: the crack propagated into hydrides

25.4

Condenser

2167

OD

ID

Fig. 25.188 Tube group #B, line #080, order #002. View of the correlation between hydrides concentration and cold-work

OD ID Generatrix line #1 ID OD Generatrix line #2

Fig. 25.189 Tube group #D, line #140, order #015. Overview of the VDA—VDAB axial section

Figure 25.188 shows the hydrides gradient, depending on the cold work level, i.e. in VDA and VDAB hard roll transition zones. In the carbon steel tubesheet zone, hydrides are distributed over the whole wall thickness and are mainly axial. For comparison purpose, the bulk hydrides in the hard roll transition zones have various orientations whereas ID hydrides stay axial. TUBE GROUP #D, LINE #140, ORDER #015 Major deformations and scratches stemming from the extraction are visible on a specimen covering both VDA and VDAB zones (Fig. 25.189). Regarding hydrides, the observations on this specimen are similar to other observations: higher hydrides concentration in hard rolled zones and concentration decrease starting in the roll transition zones and presence of compact ID layer of hydrides. Major ID scratches from the extraction tool are visible (Fig. 25.190, left). These ID scratches come with cracks propagated in hydrides alignments (Fig. 25.190, right) and severe cold work and also with an OD Cu-Al layer (Fig. 25.190, left).

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OD

ID

Fig. 25.190 Tube group #D, line #140, order #015. Left: ID deformations by the extraction tool and presence of an OD Cu-Al layer. Right: cracks developed in hydrides

TUBE GROUP #E, LINE #153, ORDER #017 Cracks in the carbon steel tubesheet zone are visible close to the broken surface; they propagate in hydrides alignments (Fig. 25.191, left). A hydrides compact layer is present at ID. At the VDA location, in addition to the presence of an ID layer of hydrides, this tube is particular because of: • Hydrides are present in the bulk material; • A hydrides layer similar to the one observed at the ID is also visible at the OD (Fig. 25.191, middle) and • Radial hydrides are also visible at the OD (Fig. 25.191, right).

OD

OD

Fig. 25.191 Tube group #E, line #153, order #017. Left: cracks close to the rupture and propagating into hydrides. Middle: hydrides layer at OD. Right: radial hydrides at OD

25.4

Condenser OD

2169 OD

Fig. 25.192 Tube group #D, line #147, order #009. Left: absence of crack in the VDAB zone. Right: cracks close to an extraction tool scratch

Given the localisation of these hydrides in the VDA zone, this tube is considered as unique. TUBE GROUP #D, LINE #147, ORDER #009 An axial section has been performed from zone VDA to zone VDAB. No crack has been observed except at the extraction scratches location (Fig. 25.192). As already observed on other tubes, the hard roll transition zones exhibit a cold work gradient (Fig. 25.193). After etching, the tube shows, in the carbon steel tubesheet zone, few hydrides despite a significant cold-work (Fig. 25.194). At the ID, the hydrides density is rather low as compared to other tubes (Fig. 25.194). The cracks visible close to extraction damages remain limited to radial hydrides (Fig. 25.195).

OD

ID

Fig. 25.193 Tube group #D, line #147, order #009. VDA zone, cold work gradient

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Fig. 25.194 Tube group #D, line #147, order #009. Carbon steel tubesheet zone, view of the structure after etching, only a few hydrides are visible

Fig. 25.195 Tube group #D, line #147, order #009. Left: crack observed close to extraction damage. Right: detail of the left figure

Conclusion The various examinations have revealed the presence of compact hydrides layers at the ID up to the VDA zone, with a density decreasing with the distance from the tube end. Radial hydrides, sometimes through wall in the Cu-Al tubesheet and in the VDAB zones, have been observed. Radial hydrides can also be present in the VDA zone, however never through wall (except for the tube group #E, line #153, order #017 which is unique). The hydrides density is cold-work dependent: hard roll length density > hard roll transition zone density > free span between the two tubesheets density; however, no influence of the distance from the anode has been evidenced. Cracks propagating in hydrides alignments are often associated with damages from the tube extraction, thus these cracks result from the extraction. In the absence of extraction damage, the examinations cannot state about the origin of the other cracks: operation or extraction.

25.4

Condenser

2171

25.4.4 Brass Tubes with Erosion Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: steam to condense. Time of operation: 36,000 h. Failure discovery: presence of OD erosion on the impact tubes. Specimen/sample characteristics: brass tubes 70/30 with arsenic. Outside diameter = 26 mm (1.02′), wall thickness = 1.2 mm (0.047″). One tube has been harvested for destructive examination. Results On the OD, the eroded length is limited to a short distance. The surface has a sponge aspect over about one fifth of the tube circumference (Fig. 25.196). A cross section through the most damaged zone reveals a very rough surface composed of joined erosion craters generated by the impact of the water droplets contained in the steam (Fig. 25.197). The remaining wall thickness at the bottom of some craters is around 0.6 mm (0.024″) which about half of the original wall thickness (Fig. 25.198).

5 mm Fig. 25.196 Left: view of the eroded area. Right: OD surface eroded each sides of a partition plate

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Balance of Plant

2 mm

Fig. 25.197 Left: erosion sponge aspect generated by the impact of the water droplets contained into the steam. Right: cross section of an eroded tube

Fig. 25.198 Cross section showing the rough surface generated by erosion

200 µm

Conclusion and Remedial Action This condenser is doomed to replace the brass impact tubes with stainless-steel (AFNOR Z2 CN 18-10/AISI 304L) tubes or titanium tubes, which are materials much more resistant to erosion by wet steam.

25.4

Condenser

2173

25.4.5 Comparison Between Titanium and Stainless-Steel Tubes Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: steam to condense. Time of operation: 32,000 h. Failure discovery: several tubes have been harvested in order to compare the behavior of titanium and stainless-steel tubes regarding their erosion resistance. Specimen/sample characteristics: tubes made of titanium, of austenitic stainless-steel (AFNOR Z2 CN 18-10/AISI 304L) and of ferritic stainless steel (AFNOR Z2 CT 18/AISI 439). Outside diameter = 26 mm (1.02′), wall thickness = 0.7 or 0.8 mm (0.0276 or 0.0315″). These tubes have been installed when the impact tubes have been partially replaced. Results All the harvested tubes exhibit more or less severe damage. For each of them, the remaining wall thickness in the bottom of the erosion craters has been measured (Figs. 25.199 and 25.200). 304L austenitic stainless-steel and titanium exhibit the best resistance to erosion. Finding out which is the best of these two types of materials is difficult because

Titanium

Fig. 25.199 Left: cross section of a titanium tube. Right: macrography of the left tube. The minimum remaining wall thickness is 0.35 mm (13.8 mils) for 0.7 mm (27.6 mils) initially (dimensions in mm)

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439SS

Fig. 25.200 Left: cross section of an AFNOR Z2 CT 18 (AISI 439) stainless-steel tube. Right: macrography of the left tube. Erosion is very severe with a remaining wall thickness down to 0.18 mm (7.1 mils) for 0.7 mm (27.6 mils) initially (dimensions in mm)

location dependent. By contrast, the ferritic stainless-steel behavior is absolutely terrible with a loss of wall thickness reaching 75%. The tubes mechanical properties have been measured in order to check for a possible correlation between the UTS and the resistance to erosion by water droplets impact. Here, the erosion by water droplets impact is considered as similar to fatigue cycles. 304L exhibits the highest UTS (620–630 MPa/89.9–91.4 KSI). On another hand, the titanium (UTS = 460 MPa/66.7 KSI) and 439 steel (UTS = 480 MPa/69.6 KSI) tubes tensile strengths are not correlated to their erosion resistance.

25.4.6 Titanium Tubes Exhibiting OD Wear Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: steam to condense. Time of operation: 18,000 h. Failure discovery: during an outage, tubes exhibiting major friction wear traces were detected. As the result, two such tubes have been harvested for destructive examination, the remaining damaged tubes have been plugged (both inlet and outlet) and left in place. Specimen/sample characteristics: tubes made of titanium. Outside diameter = 19 mm (3/4″), wall thickness = 0.5 mm (0.02″).

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Condenser

2175

Results Some tubes exhibit friction wear on a segment running between two support plates. The worn zones are located every 60°, which corresponds to the location of the neighbour tubes. One of the worn zones exhibits a festooned axial opening (Fig. 25.201). This opening corresponds to the rupture of a very thin remaining wall ligament. These worn zones are the result of the friction between adjacent tubes; the vibrations of these tubes stem from the steam flow (Fig. 25.202).

Fig. 25.201 Tube worn by its neighbours because of vibrations induced by the steam flow. An axial opening occurred in the middle of the most damaged zone

Fig. 25.202 Cross section showing the worn zones located every 60° of angle, which corresponds to the location of the neighbor tubes

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Conclusion, Remedial Action Inserting some backing bars between the relevant tubes (tubes located at the upper periphery) would prevent the tubes contact along with their vibrations. These bars should be made of material meeting the nuclear standards regarding their composition, especially regarding their sulphur and chlorine content (less than 10 ppm). Wood is strictly forbidden because of the potential release of tannins.

25.4.7 Leaking Ferritic Stainless-Steels Tubes Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: condenser. Operating conditions: river water. Time of operation: plant commissioning. Failure discovery: an inspection of all the tubes of a channel head has been triggered by a chemistry deviation. This inspection revealed the presence of 26 leaking tubes. Specimen/sample characteristics: tubes made of ferritic stainless steel AFNOR Z2 CT 18 (AISI 439L). Outside diameter = 18 mm (0.71″), wall thickness = 0.6 mm (0.024″).

Fig. 25.203 AFNOR Z2 CT 18 (AISI 439L) ferritic stainless-steel tubes exhibiting pitting corrosion and leaks close to the tube inlet, in a zone damaged by the flushing tool used in fabrication

25.4

Condenser

2177

Results The damaged tubes exhibit ID corrosion craters at the lower generatrix and 50– 60 mm (2–2.4″) distant from the water inlet. In this zone, one can see the grooves generated by the flushing tool used during the condenser fabrication (Fig. 25.203). A few leaks have also been observed out of the grooved area (Fig. 25.204). These corrosion craters are the result of the high sensibility of the AFNOR Z2 CT 18 (AISI 439L) ferritic stainless-steel to pitting corrosion in presence of confined water or under deposits (Fig. 25.205). On these tubes, the grooves have destroyed the passive film. Thus, corrosion could initiate in stagnant water or under deposits during outages because of a counter slope, the lower elevation being tube inlet side. Outlet side, the tubes showing grooves damage also exhibit pitting corrosion but none of the pits is through wall. This incipient corrosion is the signature of future severe pitting corrosion in areas with stagnant water like festooned sections between two support plates.

4 mm

2 mm

Fig. 25.204 Left: through wall pit located 240 mm (9.5″) from the tube inlet in a groove free area. Right: cross section showing corrosion craters

Fig. 25.205 Cross section of a deep pit

100µm

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Balance of Plant

Conclusion, Remedial Action Remedial actions could include: • Maintain some water flowing into the tubes during outages, which implies keep running the circulating pumps even during outages; • In case of long outage, either fill the tubes bundle with demineralized water, or dry the tubes ID.

25.4.8 Leaking Brass Tubes Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: river water. Time of operation: a few months after plant commissioning. Failure discovery: leaks have been detected. Specimen/sample characteristics: admiralty brass tubes 70/29/1 Sn, harvested from the top of the groups. Results (Figs. 25.206, 25.207 and 25.208). The cracks are observed on the tubes located at the top of the groups of tubes in a channel head. They are ID initiated, out of the hard roll zone*, towards the outlet tube end.

2 mm

Fig. 25.206 Left: ID initiated SCC cracks. Right: SCC crack broken open in the laboratory. The darker area corresponds to the field cracking

25.4

Condenser

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Fig. 25.207 Multiple ID initiated cracks

50 µm

Fig. 25.208 SCC crack tip. These cracks are transgranular and little branched

10 µm Micrography along with SEM examination show these cracks are from stress corrosion cracking. Regarding initiation, the stress parameter seems to prevail, as confirmed by field stress measurements.

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Fig. 25.209 View of the ID of a tube suffering from abrasion. The black zones correspond to the old original surface

The cracks likely result from the tubes being locked into some support plates. *Stress corrosion cracks, ID initiated in the hard roll area, have been observed on sister units, likely as the result of over-torqueing during the rolling process. In order to prevent such cracking, the hardness increase between the free span and the rolled area, has been limited to 20/30 Vickers points.

25.4.9 Arsenical Cartridge Brass Tubes with Erosion Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: river water. Time of operation: 37,000 h. Failure discovery: tubes have been harvested in order to find out the nature of field eddy current signals. Specimen/sample characteristics: arsenical cartridge brass 70/30. OD = 26 mm (1.02″). Wall thickness = 1 mm (0.04″). Results The tubes OD is defect free. The tubes ID exhibits dark islands of excessive thickness compared to the remaining reddish surface (Fig. 25.209). These islands correspond to the original tube surface whereas the remaining surface has been eroded in operation by solid particles contained into the river water (Figs. 25.210 and 25.211). These particles, carried by the cleaning balls, generate channels which will eventually merge, leaving some none eroded islands behind. This erosion can remove up to one third of the wall thickness.

25.4

Condenser

2181

2 mm Fig. 25.210 Cross section through the dark islands of the original surface showing thickness variations

Fig. 25.211 SEM examination of a zone with dark islands of the original surface; these islands are crossed by erosion striae

Conclusion, Remedial Action The only remedial action is reducing the frequency of cleaning by the cleaning balls, as low as reasonably achievable to keep the condenser operating in good conditions.

25.4.10

Leaking Arsenical Cartridge Brass Tubes

Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: condenser.

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Operating conditions: condensed steam. Time of operation: plant commissioning. Failure discovery: a leak has been discovered on one tube during a 3 bars (43.5 PSI) channel head hydrotest. Specimen/sample characteristics: arsenical cartridge brass 70/30. OD = 26 mm (1.02″). Wall thickness = 1 mm (0.04″). Results The tube OD exhibits several defects over a few millimeters distance (Fig. 25.212). Their direction is perpendicular to the tube axis and their length ranges from a few tenths to 2 mm (0.08″). Axial sections reveal the presence of several OD initiated defects with the same orientation (Fig. 25.213). A metal overlap, parallel to the surface has also been observed (Figs. 25.214 and 25.215). The leak results from fabrication defects, either due to the presence of a foreign object, or to a lack of compacity of the metal during the tube drawing operation.

Fig. 25.212 Fabrication defects visible on the tube

1 mm

Fig. 25.213 Axial section through the defects

1 mm

25.4

Condenser

2183

200 µm Fig. 25.214 Higher magnification of the previous defects

50 µm Fig. 25.215 Even higher magnification of the previous defects

25.4.11

Leaking Titanium Tubes

Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: condenser. Time of operation: 0 h. Failure discovery: during the hydrotest of the space between the two tubesheets, several tubes exhibited leaks into the hard roll, steel tubesheet side. Specimen/sample characteristics: rolled and seamed titanium tubes. OD = 19 mm (3/4″). Wall thickness = 0.5 mm (0.02″).

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Balance of Plant

Results The examination of the ID reveals the presence of hard rolling tool traces showing that the tube was rolled twice (Fig. 25.216). The first rolling was misplaced (half into the tubesheet, half out of it) whereas the second was implemented at the right location. The weld bead is shifted as the consequence of the tube twisting because of the wrong position of the first hard rolling (Fig. 25.217). This area suffers from cracking along the weld bead groove. A micrography shows this cracking is from low cycle fatigue (Fig. 25.218). This fatigue cracking was triggered by the wrong location of the hard roll into the steel tubesheet (Fig. 25.219). This phenomenon was duplicated in the laboratory.

Fig. 25.216 View of the tube ID showing the presence of a double hard roll, one being performed out of the tubesheet

4 mm Fig. 25.217 View of the twisting generated by hard rolling the tube out of the tubesheet

25.4

Condenser

2185

50 µm

Fig. 25.218 Cross section into the cracking located into the space between the two tubesheets

Fig. 25.219 SEM view of the fracture surface showing striae from fatigue

50 µm

Conclusion, Remedial Action The distance between the two tubesheets has been measured. These distances have been sorted into 3 categories, according to their value. The assessment of the 3 most popular distances allowed to position the hard roll at the most accurate location, depending on the relevant category of distance between the two tubesheets. Moreover, the hard roll length into the steel tubesheet has been slightly decreased.

2186

25.4.12

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Balance of Plant

Tubesheet General Corrosion

Plant main characteristics: Framatome PWR, 900 MWe, 3 loops, France. Equipment/Component: condenser. Operating conditions: sea water. Time of operation: 3,500 h. Failure discovery: during the inspection of the condenser channel heads, a thick greenish layer of products was observed on the tubesheet, sea water inlet side (Fig. 25.220). Specimen/sample characteristics: the tubesheet is made of copper–aluminum alloy (AFNOR UA 9 N 5 Fe 3 Mn), the tubes are made of titanium. Replicas were taken from the tubesheet for the micrographic examination. Results The greenish products* covering the inlet tubesheet sometimes exhibit draining like aspects. These products are more abundant on the tubes in-between ligaments. When removed the underlaying surface appears to be corroded over about 1 mm (0.04″) deep. This corrosion is deeper at the tubesheet-tubes crevices. The outlet tubesheet is also covered with greenish products, however with a lower thickness. Replicas taken on the tubes in-between ligaments, after a light grinding (a few tenths of millimetres), reveal the presence of multiple corrosion pits (Fig. 25.221). This corrosion results from a preferential attack of the aluminum-rich phase (Fig. 25.222). This corrosion was triggered by concentrated sea water slowly

Fig. 25.220 Condenser corroded inlet tubesheet

25.4

Condenser

2187

200 µm

Fig. 25.221 Corrosion pits observed in the tubes in-between tubesheet ligaments

50 µm

10 µm

Fig. 25.222 View of the selective corrosion of the aluminum rich phase

draining during long shutdown periods. The tubes’ slope drains the remaining water towards the inlet channel head. As a consequence, concentrated sea water flows out of the tubes on the inlet tubesheet and corrodes the ligaments in-between the tubes. *By X-rays diffraction, these products has been characterized as copper oxychlorides (atacamite and paratacamite). Conclusion, Remedial Action Nozzles spraying fresh water have been installed in order to rinse both the tube bundle and the tubesheet as soon as the plant is shutdown.

2188

25.4.13

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Balance of Plant

Channel Head with Rust

Plant main characteristics: Framatome PWR, 1,300 MWe, 4 loops, France. Equipment/Component: condenser, channel head. Operating conditions: sea water. Time of operation: 2,000 h. Failure discovery: rust products have been observed on the weld joining the buttering to the copper–aluminum coating of the channel head (Fig. 25.223). Specimen/sample characteristics: metal chips harvested from the weld joining the buttering to the copper–aluminum coating of the channel head. Then, the weld was core drilled to get larger specimens from damaged zones. Both weld and buttering are made of copper–aluminum alloy with 2.5% Ni, 1% Fe and 1% Mn. The channel head coating is made of 3% Ni copper–aluminum alloy. Results Preliminary examination of the chips showed the weld contained dendrites very iron-rich, up to 70% (Fig. 25.224). The assumption that the corrosion was following these iron-rich dendrites triggered the decision to proceed to core drilling in damaged zones. The examination of these last specimens confirmed the presence into the weld and the buttering of a network of iron-rich dendrites resulting from the

Fig. 25.223 View of the channel head. Presence of rust on the weld joining the buttering to the copper–aluminum coating

25.4

Condenser

2189

5 µm

Fig. 25.224 On the left side of this micrograph, one can see a pine needle like dendrite. This type of iron-rich dendrite has been observed in both the buttering and the copper–aluminum filler metal

25 µm

10 µm

Fig. 25.225 Left: image showing the iron distribution and one iron-rich dendrite. Right: preferential corrosion of the iron-rich dendrites network

melting of the underlaying sleeve steel (Fig. 25.225). This anomaly results from an excessive welding energy along with a reduced number of passes. The iron segregation into growing dendrites is due to the low solubility of iron into the copper– aluminum alloy. The very dense network of dendrites is responsible for the high sea water corrosion rate.

2190

25.5

25

Balance of Plant

Raw and Raw-Service Water

25.5.1 Galvanic Corrosion of Rubber Lined Service Water Pipes Adjacent to Titanium Heat Exchangers (Matthews 2013) Plants main characteristics: Framatome PWR, 900 MWe, 3 loops, South Africa. Equipment/Component: the ESWS for each unit consists of two 100% redundant and identical trains supplying seawater from the intake basin, where it is filtered and pumped through a plate heat exchanger and out to the ocean via the common outflow together with the secondary side service water. The majority of the pipework of the ESWS is reinforced concrete piping, however within the heat exchanger room internally rubber lined carbon steel pipework is used. Each flanged carbon steel pipe is internally lined with rubber which continues over the flange faces, see Figs. 25.226 and 25.227.

Fig. 25.226 Schematic of the rubber lined carbon steel pipework of the ESWS leading to and from a heat exchanger. The location (unit and train) of those spool pieces observed with significant corrosion are indicated

25.5

Raw and Raw-Service Water

2191

The carbon steel pipes have a nominal diameter of 600 mm (23.6″) with a nominal wall thickness of 9.5 mm (0.375″) and are lined with approximately sheets of 6 mm (0.24″) pre-cured butyl rubber, which are glued onto the carbon steel surfaces. The butyl sheets are joined using a tapered overlapping scarf joint. Butyl rubber generally has excellent permeability resistance to seawater and acts as a physical barrier between the seawater and the carbon steel. Operating conditions: both units use seawater for cooling of the secondary circuit in the condenser as well as cooling of the primary circuit via the essential service water system. During accident conditions the latter system is designed to evacuate heat from the primary systems to the ultimate heat sink. Heat is transferred from the Equipment Cooling Water System, which is a two-train redundant closed loop system, to the ESWS via a titanium plate type heat exchanger. There are 323 titanium plates, a total of approximately 700 m2 (7535 ft2) of available surface area, across which heat is transferred between the systems. Seawater is pumped at a design flow rate of 2650 m3/h (11,668 gpm), which equates to approximately 2.6 m/s (8.5 ft/s) through the pipes. Time of operation: two units commissioned in 1984 and 1985 respectively. Failure discovery: in August 2007 (unit 1) and January 2008 (unit 2) all the rubber lined spool pieces across both trains and both units were replaced with new piping. Together with new spool pieces the inspection frequency changed. Internal visual inspections of the rubber lining were conducted on both trains every refueling outage (approximately 18 months apart), however after installing the new spool pieces, the inspection frequency was reduced to every second refueling outage. On December the 8th, 2009, approximately 28 months after new butyl rubber lined spool pieces were installed, a through wall leak (estimated at 50 mm (2″) in diameter) was observed on the ESWS spool piece near to the heat exchanger. This leak was located adjacent to a fillet weld of T-spool piece and also corresponded to a scarf joint of the rubber lining, see Figs. 25.228 and 25.229. Ultrasonic testing was performed on 100% of the external surface of the carbon steel spool pieces on both trains of both units to detect for wall thinning. Several other locations of significant wall thinning were detected across all trains. Thereafter successive short duration outages were planned for both units for maintenance of the ESWS. Before the maintenance outages started UT measurements were repeated in those areas of wall thinning after 30 days.

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Balance of Plant

Fig. 25.227 Photograph of the general layout of the flanged rubber lined pipework connected to the plate heat exchanger

Fig. 25.228 Location of the first leak (circled) adjacent to the weld on a T-spool piece (Unit 1, Train B)

25.5

Raw and Raw-Service Water

2193

Fig. 25.229 Internal view of the first through-wall hole located at the junction of overlapping butyl rubber sheets. (Unit 1 Train B)

Material loss was measured in some locations, most notably in a diffuser spool piece connected to the heat exchanger outlet where a wall loss of 4.4 mm (0.017″) was measured in 30 days. A leak was observed at this location 13 days after the last measurement, see Figs. 25.230, 25.31 and 25.232. Results It was apparent that there was a generic condition that affected the integrity of both trains of both units. The main concerns related to nuclear safety were the risk of possible flooding of the heat exchanger rooms if the leaks were to expand, and secondly the possible clogging of the heat exchanger with loose rubber lining leading to reduced flow. Internal inspections were conducted of all rubber lined spool pieces where significant wall losses were detected by UT inspections, see Fig. 25.226. Every area of significant general corrosion corresponded to a join between rubber lining sheets. The significant amount of wall loss at the affected locations was initially surprising, i.e. up to 4.4 mm/month (0.017″/month) measured from UT wall loss measurements. It was also evident that once the adhesion of the rubber lining had failed the corrosion of the carbon steel undercut the adhesive bond of the lining thereby

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Balance of Plant

Fig. 25.230 Location of the second leak (2 through wall holes) on a diffuser spool piece at the heat exchanger outlet (Unit 2, Train A)

Fig. 25.231 Internal view of the second leak that occurred at a longitudinal seam joint between rubber sheets, as removed (Unit 2, Train A)

25.5

Raw and Raw-Service Water

2195

Fig. 25.232 Internal view of through wall holes after surrounding rubber removed, showing the progressive delamination of rubber lining with the holes located where carbon steel was first exposed (Unit 2, Train A)

causing further detachment of the lining, aided in some cases by the flow of the seawater. A number of issues where found to have contributed to the failure of the rubber lining. The pre-cured butyl rubber was glued to the carbon steel, rather than curing the rubber after application in an autoclave, which results in an improved bond strength. Since the rubber lining included a significant amount of conductive carbon black the spark testing, as means of detecting discontinuities, was not possible across the rubber lining joints. There was evidence suggesting that the glueing of the scarf joints between sheets was not optimal. However, while the lining failure was considered to be the primary cause of the loss of system integrity, the rapid corrosion of the carbon steel pipe material that lead to leaks within the inspection interval was cause for concern. Various corrosion rates for carbon steel immersed in flowing seawater are quoted in published literature however all values are