Degradation Assessment and Failure Prevention of Pipeline Systems [1st ed.] 9783030580728, 9783030580735

Table of contents :
Front Matter ....Pages i-viii
Front Matter ....Pages 1-1
Non-destructive Mechanical Testing of Pipelines (Gabriella Bolzon)....Pages 3-14
In-Service Degradation of Pipeline Steels (Hryhoriy Nykyforchyn)....Pages 15-29
Non-destructive Electrochemical Evaluation of Pipeline Degradation (Olha Zvirko, Oleksandr Tsyrulnyk)....Pages 31-44
Structural and Fractographic Features of Gas Pipeline Steel Degradation (Halyna Krechkovska, Myroslava Hredil, Oleksandra Student)....Pages 45-59
Determination of the Residual Lifetime of Gas Pipeline with Surface Crack Under Internal Pressure and Soil Corrosion (Ivan Shtoyko, Jesus Toribio, Viktor Kharin, Myroslava Hredil)....Pages 61-73
Front Matter ....Pages 75-75
A Tentative Summary of Corrosion Issues in Pipelines Transporting Hydrocarbons (Giovanna Gabetta)....Pages 77-87
Risk-Based Inspection and Integrity Management of Pipeline Systems (Stefano P. Trasatti)....Pages 89-98
A Model of a System for Gas Transmission Pipeline Integrity Monitoring (Vasyl Chekurin, Roman Kushnir, Yuriy Ponomarev, Myroslav Prytula, Olga Khymko)....Pages 99-114
The VERNE System for Underwater Test of Pipeline Integrity (G. Nardoni, D. Nardoni, M. Bentoglio)....Pages 115-122
Detection and Assessment of Defects in Gas Pipelines (Vasyl Kostiv, Roman Banakhevych, Hryhoriy Nykyforchyn)....Pages 123-134
Hydrogen Embrittlement and Microdamage of 316L Steel Affecting the Structural Integrity, Durability and Safety of Pipelines (Jesús Toribio, Javier Ayaso)....Pages 135-143
Effect of Environmental Composition on Fatigue Crack Growth and Hydrogen Permeation in Carbon Pipeline Steel (Ihor Dmytrakh, Rostyslav Leshchak, Andriy Syrotyuk)....Pages 145-159
Development of Improved Materials for the Production of Forged Integral Buckle Arrestors (Francesca Cena, Giovanna Gabetta, Giuseppe Cumino)....Pages 161-173
Assessment of Operational Degradation of Pipeline Steel Based on True Stress–Strain Diagrams (Ihor Dzioba, Olha Zvirko, Sebastian Lipiec)....Pages 175-187
Effect of Impact-Oscillatory Loading on the Variation of Mechanical Properties and Crack Resistance of Pipe Steel (Mykola Chausov, Pavlo Maruschak, Andrii Pylypenko, Andriy Sorochak)....Pages 189-201
Prediction of Residual Service Life of Oil Pipeline Under Non-stationary Oil Flow Taking into Account Steel Degradation (Oleksandr Andreykiv, Oksana Hembara, Iryna Dolinska, Yaroslav Sapuzhak, Nataliya Yadzhak)....Pages 203-216
Application of the Magnetoacoustic Emission Method for Estimation of Pipelines Material State (V. Skalskyi, Ye. Pochaps’kyi, O. Stankevych, B. Klym, N. Melnyk)....Pages 217-229
Corrosion-Mechanical Failure of Pipe Steels in Hydrogen Sulfide Environments (Myroslav Khoma, Vasyl Vynar, Maryan Chuchman, Chrystyna Vasyliv)....Pages 231-239
Determination of Preconditions Leading to Critical Stresses in Pipeline During Lowering (Yurii Melnychenko, Lubomyr Poberezhny, Volodymyr Hrudz, Vasyl Zapukhliak, Ihor Chudyk, Taras Dodyk)....Pages 241-252

Citation preview

Lecture Notes in Civil Engineering

Gabriella Bolzon Giovanna Gabetta Hryhoriy Nykyforchyn   Editors

Degradation Assessment and Failure Prevention of Pipeline Systems

Lecture Notes in Civil Engineering Volume 102

Series Editors Marco di Prisco, Politecnico di Milano, Milano, Italy Sheng-Hong Chen, School of Water Resources and Hydropower Engineering, Wuhan University, Wuhan, China Ioannis Vayas, Institute of Steel Structures, National Technical University of Athens, Athens, Greece Sanjay Kumar Shukla, School of Engineering, Edith Cowan University, Joondalup, WA, Australia Anuj Sharma, Iowa State University, Ames, IA, USA Nagesh Kumar, Department of Civil Engineering, Indian Institute of Science Bangalore, Bengaluru, Karnataka, India Chien Ming Wang, School of Civil Engineering, The University of Queensland, Brisbane, QLD, Australia

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Gabriella Bolzon Giovanna Gabetta Hryhoriy Nykyforchyn •

•

Editors

Degradation Assessment and Failure Prevention of Pipeline Systems

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Editors Gabriella Bolzon Dipartimento di Ingegneria Civile e Ambientale Politecnico di Milano Milano, Italy

Giovanna Gabetta Oil&Gas Sector Milano, Italy

Hryhoriy Nykyforchyn Karpenko Physico-Mechanical Institute National Academy of Sciences of Ukraine Lviv, Ukraine

ISSN 2366-2557 ISSN 2366-2565 (electronic) Lecture Notes in Civil Engineering ISBN 978-3-030-58072-8 ISBN 978-3-030-58073-5 (eBook) https://doi.org/10.1007/978-3-030-58073-5 © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 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

Preface

Pipelines represent an extremely safe way to transport hydrocarbons across the world. A barrel of crude oil or petroleum product shipped by pipeline reaches its destination safely more than 99.99% of the time. In addition, most incidents do not impact the public or the environment, since they are occurring and wholly contained within the operators’ facilities. Efforts are however necessary to ensure that health, safety, security, and environmental concerns are addressed throughout all planning, construction, and operational phases of pipeline operations. Integrity management programs can prevent releases and accidents by defining adequate evaluation, inspection, and maintenance procedures. The research project G5055 ‘Development of novel methods for improved safety assessment of gas pipelines with security implications,’ supported by NATO Science for Peace and Security (SPS) program, addressed some of the safety issues listed above. The main results of this project are collected in this volume together with the contribution of experts operating in the wider fields of pipe safety, with the aim of offering the overall picture of the technical discussion going on in this area. The SPS G5055 project was dedicated to the study of steel degradation in gas pipeline. Tests were performed on some serviced pipeline sections provided by utilizers settled in Italy and in Ukraine, operating in wide production and distribution areas. The research focus was on non-destructive mechanical tests and electrochemical evaluation of degradation. The objective was to describe and if possible to model the in-service degradation of pipeline steel via the examination of structural and fractographical features. In fact, during their lifetime, pipelines are exposed to demanding working conditions and aggressive media. In long-term exploitation, material aging increases the risk of fracture and the possibility of significant economic losses and severe environmental consequences. Thus, understanding damage evolution in steel represents a main purpose to be persecuted in order to predict reliably the residual life of pipelines and the connected risks. Failure in operation of the considered strategic infrastructures can be prevented by continuous monitoring. Non-destructive experimental techniques can evidence in-bulk degradation phenomena like material embrittlement, particularly critical in v

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gas transportation systems for the danger of bursts and explosions. Data collected on site and inserted in validated prediction models allow to estimate the evolution of the ongoing processes and to plan the retrofitting interventions that ensure the maintenance of adequate safety margins. Crack growth in pipeline steel is often assisted by hydrogen, by a mechanism that depends strongly on the physico-chemical characteristics of transported fluid. Hydrogen embrittlement is considered in a few papers in this book, together with the main corrosion issues that are known to cooperate to pipeline degradation. The capability of detecting defects is mandatory to improve the safety performance of the investigated systems and of related components; some innovative methods are described to evidence the presence of corrosion and its evolution with time. Improved safety of pipelines can be provided by assessing different damaging scenarios in a risk-based context, with the combination of complementary inspection techniques. Finally, a significant contribution to pipeline safety is provided also by the ongoing technological progresses in materials and components, partly described in this book. Milano, Italy

Gabriella Bolzon Co-Director of NATO SPS G5055 Project

Lviv, Ukraine

Hryhoriy Nykyforchyn Co-Director of NATO SPS G5055 Project

Milano, Italy

Giovanna Gabetta Industrial Advisor of the Project

Contents

Project Results Non-destructive Mechanical Testing of Pipelines . . . . . . . . . . . . . . . . . . Gabriella Bolzon

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In-Service Degradation of Pipeline Steels . . . . . . . . . . . . . . . . . . . . . . . . Hryhoriy Nykyforchyn

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Non-destructive Electrochemical Evaluation of Pipeline Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Olha Zvirko and Oleksandr Tsyrulnyk

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Structural and Fractographic Features of Gas Pipeline Steel Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Halyna Krechkovska, Myroslava Hredil, and Oleksandra Student

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Determination of the Residual Lifetime of Gas Pipeline with Surface Crack Under Internal Pressure and Soil Corrosion . . . . . . . . . . . . . . . . Ivan Shtoyko, Jesus Toribio, Viktor Kharin, and Myroslava Hredil

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Open Issues A Tentative Summary of Corrosion Issues in Pipelines Transporting Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Giovanna Gabetta

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Risk-Based Inspection and Integrity Management of Pipeline Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stefano P. Trasatti

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A Model of a System for Gas Transmission Pipeline Integrity Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vasyl Chekurin, Roman Kushnir, Yuriy Ponomarev, Myroslav Prytula, and Olga Khymko

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Contents

The VERNE System for Underwater Test of Pipeline Integrity . . . . . . . 115 G. Nardoni, D. Nardoni, and M. Bentoglio Detection and Assessment of Defects in Gas Pipelines . . . . . . . . . . . . . . 123 Vasyl Kostiv, Roman Banakhevych, and Hryhoriy Nykyforchyn Hydrogen Embrittlement and Microdamage of 316L Steel Affecting the Structural Integrity, Durability and Safety of Pipelines . . . . . . . . . . 135 Jesús Toribio and Javier Ayaso Effect of Environmental Composition on Fatigue Crack Growth and Hydrogen Permeation in Carbon Pipeline Steel . . . . . . . . . . . . . . . 145 Ihor Dmytrakh, Rostyslav Leshchak, and Andriy Syrotyuk Development of Improved Materials for the Production of Forged Integral Buckle Arrestors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161 Francesca Cena, Giovanna Gabetta, and Giuseppe Cumino Assessment of Operational Degradation of Pipeline Steel Based on True Stress–Strain Diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175 Ihor Dzioba, Olha Zvirko, and Sebastian Lipiec Effect of Impact-Oscillatory Loading on the Variation of Mechanical Properties and Crack Resistance of Pipe Steel . . . . . . . . . . . . . . . . . . . . 189 Mykola Chausov, Pavlo Maruschak, Andrii Pylypenko, and Andriy Sorochak Prediction of Residual Service Life of Oil Pipeline Under Non-stationary Oil Flow Taking into Account Steel Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 Oleksandr Andreykiv, Oksana Hembara, Iryna Dolinska, Yaroslav Sapuzhak, and Nataliya Yadzhak Application of the Magnetoacoustic Emission Method for Estimation of Pipelines Material State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217 V. Skalskyi, Ye. Pochaps’kyi, O. Stankevych, B. Klym, and N. Melnyk Corrosion-Mechanical Failure of Pipe Steels in Hydrogen Sulfide Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231 Myroslav Khoma, Vasyl Vynar, Maryan Chuchman, and Chrystyna Vasyliv Determination of Preconditions Leading to Critical Stresses in Pipeline During Lowering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241 Yurii Melnychenko, Lubomyr Poberezhny, Volodymyr Hrudz, Vasyl Zapukhliak, Ihor Chudyk, and Taras Dodyk

Project Results

Non-destructive Mechanical Testing of Pipelines Gabriella Bolzon

Abstract Strategic infrastructures made of pipelines transporting hydrocarbons across the world are exposed to the risk of failure due to damage accumulation during operation. The degradation process is promoted by material aging and enhanced by harsh service conditions. Severe consequences can be prevented by the long-life monitoring and integrity assessment of materials and components. Structural diagnosis can be assisted by non-destructive mechanical testing. This chapter provides an overview on the procedures at present available for pipeline steels in this context. The information content of hardness and instrumented indentation tests is specifically addressed. The focus is on the reliability of the predictions that can be provided by small sampling sizes when experimental information and numerical simulations are combined. The significance of such methodology for the evaluation of the current properties of exercised pipelines is illustrated together with the relevant validation studies. The gains resulting from the progressive technological advancements are also evidenced. Keywords Pipelines · Failure prevention · Structural diagnosis · Non destructive testing · In-situ analysis

1 Introduction Strategic infrastructures made of pipelines transporting hydrocarbons across the world are exposed to the risk of failure due to damage accumulation during operation. The degradation process is promoted by material aging and enhanced by harsh service conditions, due to either the presence of aggressive agents in the fluids and to the characteristics of the surrounding environment [1].

G. Bolzon (B) Dipartimento di Ingegneria Civile e Ambientale, Politecnico di Milano, Milano, Italy e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_1

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The maintenance of adequate safety levels poses significant challenges and implies large maintenance investments that may be adequately planned through the implementation of effective structural health monitoring systems [2, 3]. Thus, failure prevention costs can be payed back by the reduction of interventions in emergency and by the reconversion of existing pipeline systems to different uses, as expected in the transition from the carbon to the hydrogen era [4]. Distributed corrosion represents a common threat of steel components. In oil and gas infrastructures, corrosion can be evidenced by specific in-line inspection tools and dedicated sensors [5, 6]. Visual examination and ultrasonic measurement permit to detect the presence of flaws, which may trigger localized (pitting) corrosion [7]. These dangerous phenomena are often preceded or accompanied by diffuse material degradation. Ductility represents a crucial material characteristic to prevent bursts and explosions in gas transportation system. This property can be compromised by material aging, enhanced by physical–chemical processes involving hydrogen and water [8–10]. Embrittlement phenomena may become critical especially at low operating temperatures, which represent typical working conditions of pressure vessels [11–13]. Ductility is usually determined by standard mechanical tests performed on samples extracted from the pipe (or vessel) wall and machined in the shapes and dimensions prescribed by Standards [14, 15]. A non-invasive alternative proposed for industrial power generation systems and for nuclear plants consists of the small punch test. In this methodology, a small disc is cut from a thin (a few mm thick) metal layer removed from the component to be investigated. The sample is punched by a spherical ball. The applied load is recorded versus the induced deflection. Conventional mechanical properties like yield strength, ultimate tensile strength and ductileto-brittle transition temperature are inferred from the collected measurement by semiempirical relationships [16, 17]. This mechanical characterization approach has been proposed also for the estimation of fracture toughness, starting from the identification of the crack initiation point in the deformation process. However, facing this challenging task implies the use of sophisticated measurement techniques, which are seldom available [18, 19]. Several investigations have evidenced a significant correlation between the embrittlement (i.e., the reduction of elongation at failure) and the variation of other mechanical properties of exercised metals [8, 10, 11, 20]. This is for instance the case of the tensile strength, which can be reliably estimated by several experimental procedures. A truly non-destructive, fast and rather inexpensive technique is based on instrumented indentation, which represents the quite natural evolution of the classical hardness tests [21, 22]. Indentation does not require to machine any specimen. In this approach, a hard steel or diamond tip of pre-fixed shape is pressed against the polished surface of the component to be investigated. The load can be applied directly on the operated structure through specifically designed equipment and anchorage systems [23, 24]. The force value is controlled continuously together with the penetration depth of the tip. These data produce the so-called indentation curves, which are exploited

Non-destructive Mechanical Testing of Pipelines

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in parameter identification procedures based on either semi-empirical formulae [23, 25] or (more and more frequently) on inverse analysis tools [24, 26]. The reliability of the material characteristics calibrated on the basis of instrumented indentation tests has been often discussed. In some circumstances, in fact, several parameter sets can approximate the load-penetration curves to the same extent. This limitation can be circumvented by exploiting the geometry of the residual imprint left on the material surface [27]. This additional information can be acquired by a variety of tools, also depending on the magnitude of the applied load and on the induced penetration depth [26, 28, 29]. The relevant equipment is now easily available on the market, even in portable format, and can be mounted on frames moving on rails or on the arms of collaborative robots for the probing of the material characteristics over large distances; see e.g. [30–32]. The load levels considered in [24, 26] conform to standard specification for structural applications. The experimental output is therefore truly representative of the bulk material properties, with a large spatial resolution that permits to evidence gradients in material properties. This is an interesting feature for diagnostic applications since damage processes often spread through structural components starting from an initial small volume or surface. The effectiveness of in situ diagnostic analyses depend on the portability and manoeuvrability of the indentation tools and on the acquisition speed of the imaging devices. These operative characteristics can be enhanced by the reduction of the maximum applied load. The feasibility of this potential technical advancement has been partly verified in the research work summarized in this chapter.

2 Indentation-Based Structural Diagnosis Tool The alteration of the mechanical properties induced by the bulk degradation of pipeline steel is reflected by the output of hardness and indentation tests [20, 23, 33]. Thus, the structural integrity of in-service components can be monitored by the routine application of these fast non-destructive techniques. When required, the collected information can be exploited in inverse analysis procedures to return a reliable quantification of the damage extent and severity [34].

2.1 Damage Detection Diffuse damage processes produce variations on the main characteristics of metals. The modification of the mechanical properties can be evidenced by traditional laboratory tests performed on material samples extracted from operated components. Alternatively, the variation of the material characteristics can be inferred from the output of indentation tests performed in situ. This non-destructive approach has been

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Fig. 1 Indentation curves of as-received (dashed lines) and degraded (continuous lines) X60 and X70 pipeline steel (rough data)

verified on different types of pipeline steels, tested in laboratory in as-received status and in artificially aged and degraded conditions [20, 33]. In some experiments, a Rockwell tip was pressed against the metal surface at increasing load, up to 200 N maximum force, and then removed. The indentation curves corresponding to X60 and X70 steel samples are for instance visualized in Fig. 1. Despite some dispersion, the curves permit to distinguish the different material status. In particular, the maximum penetration depth in the as-received sample are larger than in degraded conditions, evidencing that the undergone processes induced material hardening. This effect was confirmed by the output of standard uniaxial tests performed on cylindrical tensile specimens with circular cross section of 4.9 mm diameter. Results, also in terms of constitutive parameters, are fully comparable to those evidenced by indentation despite the different volumes involved by the alternative experiments. In fact, the estimated radius of the steel surface in contact with the Rockwell tip during the loading process represented in Fig. 1 is about 250 µm. The residual deformation left on a metal surface by indentation reflects significantly the material characteristics. The geometry of the imprint can be acquired in a variety of modes and returned in digital format as a set of coordinates. These data can be used to identify the main constitutive parameters of pipeline steels and their evolution with time.

2.2 Damage Quantification Damage extent is correlated to the variation of bulk material properties like the elastic modulus, the initial yield limit and the hardening coefficient of metals. These parameters can be evaluated from the information collected from non-destructive indentation tests performed in situ, on components in use. The measurements can be processed in almost real time by inverse analysis tools resting on the combination of

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Fig. 2 The validated material calibration procedure illustrated in [26]

experimental and computing procedures partly proposed and developed in different research areas [35, 36]. An approach effective in the present context consists of the steps schematically represented in Fig. 2. The whole procedure can be summarized as follows, while details are given in [26]. 1. An axisymmetric (Rockwell, in this case) tip is pressed against the material to be tested until a given reaction force is achieved. The load is progressively released and the tool is eventually removed. During the loading–unloading process, an instrumented indenter returns the force level versus the penetration depth of the tip. 2. In all cases (i.e., even with the use of a hardness tester that does not return the load-penetration curve) the geometry of the permanent impression left on the surface of the sampled material is mapped, storing the relevant three-dimensional coordinates in digital format. These data are processed to return the profile of the residual imprint, which is expected to be axisymmetric in the case of an isotropic material. The corresponding confidence limits serve as indicators of the representativeness of the test and of the isotropy of the material response. 3. The data describing the geometrical profile of the residual imprint (and, possibly, the load vs. penetration curves) constitute the input of an inverse analysis procedure based on the comparison between the measurements and the output of a simulation model of the test. The computational results depend on a set of material parameters, which are sequentially updated in order to minimize the discrepancy between the experimental and the computational output. 4. The reliability of the final estimates is checked through the comparison between the actual and the recalculated system response.

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Fig. 3 a Finite element discretization for the simulation of axisymmetric indentation processes; b detail of the mesh in the contact region

A realistic simulation of the indentation processes is performed by finite element analyses, non-linear in terms of constitutive models and geometrical effects. The contact conditions and the large irreversible strain developing under the indenter tip are accurately reproduced by fine meshes like the one visualized in Fig. 3, where the discretized domain has an extension of a few millimeters and the typical element size in the contact region is of the order of a few micrometers. At the same time, the operative procedures that permit the minimization of the scatter between experimental data and computational results are iterative [37]. The large computational burden can be alleviated by surrogate analytical models that replace the finite element analyses, using radial-basis functions (RBFs) to generalize the results of a training set of numerical simulations performed off-line. This kind of fast and flexible interpolation means is exploited in computer graphics for the effective reconstruction and representation of moving 3-dimensional objects [38]. Accuracy is improved by the filtering of experimental and numerical noises by means of proper orthogonal decomposition (POD) techniques, of common use in the field of signal processing [39]. The above mentioned tools permit to achieve an optimal compromise between the conflicting requirements of an accurate simulation of the system response with diagnostic analyses performed in almost real-time [40, 41]. Thus, the consequences of accidental or local defectiveness, which may alter the safety assessment of the pipeline section, can be overcome by the prompt repetition of the test.

2.3 Sampling Size The output of instrumented indentation tests carried out on pipeline steel at 200 N maximum force is shown in Fig. 1 [20, 33]. As already noticed, the as-received and degraded material conditions are distinguishable at this load level despite the observed scatter in the indentation curves. The representativeness of the results obtained from indentation at 200 N maximum load has been verified also by the comparison of results gathered from independent

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Fig. 4 Experimental and simulated response to instrumented indentation of X70 steel [34]

investigations. In particular, a fairly good correspondence was found between the experimental response to indentation of X70 steel and the numerical simulation of the test performed using the constitutive (stress–strain) law returned by traditional tensile tests, see Fig. 4 [34, 42]. This concurrence can be attributed to the microstructure of pipeline steel, with typical grain size significantly lower than the material volume affected by indentation performed at either 1.5 and 0.2 kN maximum load, as visualized in Fig. 5. The graphs compare the simulated profile of the imprints left on the material by a Rockwell tip, while the apparent contact surface at 200 N force (about 200 µm radius) is likened to the micrographs presented in [20] and [33]. Indentation tests are commonly performed also at much smaller scale, in the range 1–5 N maximum force [43, 44]. The relevant instrumentation is easily equipped by loading frames of high relative stiffness, capable of an accurate control of the tip penetration depth. These devices provide highly valuable information for several

Fig. 5 Simulated profile of the imprint geometry compared to the microstructure of typical pipeline steels [20, 33]

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applications, but proved to be inadequate in the present context due to a large dispersion of the output curves that reflect the inhomogeneities and the imperfections of pipeline steel at the microscale [45]. Former studies have verified that Rockwell indentation tests carried out on metals at load levels consistent with Standards for structural applications [46] provide results in terms of elastic limits and ultimate strength, which are equivalent to those of uniaxial tensile tests when the geometry of the residual imprint is taken into account [24, 26]. The outperformance of this information source in material characterization problems, compared to the load-penetration curves, has been demonstrated also in [47]. The reproducibility of the residual deformation produced by axisymmetric Rockwell indentation carried out at 200 N maximum load has been verified considering a pipeline steel in reference and hardened conditions. The corresponding indentation curves are shown in Fig. 6. Larger penetration depth and larger dispersion of the results are observed in the initial status. The graphs in Fig. 7 visualize the mean profiles of the residual deformation. The mapping was performed several days after indentation and the anomalies in the bottom of the imprints represented in Fig. 7a are due to the deposition of dust particles difficult to be removed. Elsewhere, the profiles concerning the investigated samples are quite repetitive, except for the roughness of the free surface. The larger penetration depth and the more pronounced piling-up of the graphs in Fig. 7a compared to those in Fig. 7b reflect the larger ductility of the metal in its initial conditions. The graphs visualized in Figs. 6 and 7 are more directly compared in Fig. 8 where all indentation curves and a representative pair of the imprint profiles are redrawn. It is worth noticing that the indentation curves relevant to the different material states are partially overlapped, see Fig. 8a. On the contrary, the residual deformation is significantly different. Only the initial portion of the graphs in Fig. 8b is almost perfectly superimposed. In fact, most part

Fig. 6 Indentation curves produced by an axisymmetric Rockwell tip on pipeline steel in: a reference and b hardened conditions

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Fig. 7 Half mean profiles of the imprints produced by an axisymmetric Rockwell tip on pipeline steel: a output of different tests of the same sample; b results obtained from mechanically hardened pipeline steel

Fig. 8 Comparison between the indentation response of pipeline steel in reference (light lines) and hardened (dark lines) conditions: a indentation curves of Fig. 6; b two representative imprints from Fig. 7

of the profile beneath the free surface reproduces the geometry of the Rockwell tip while the region around the small crater created by the indenter contains significant information about the irreversible material response, and presents the largest sensitivity with respect to the plastic parameters [48]. The geometry of the residual deformation shown in Figs. 7 and 8 was acquired by the same multifocal microscope that recovered the imprints visualized in [26], produced by 2 kN maximum force. The measurement accuracy is comparable at these different scales, but the geometry reconstruction time is much shorter at the lower load (a few seconds instead of a few minutes).

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G. Bolzon

3 Closing Remarks This contribution provides an overview on procedures at present available for the monitoring and the diagnostic analysis of steels in gas transmission lines. Techniques based on non-destructive tests that can be performed in situ, on operating components, are considered. Indentation based approaches supported by simulation models of the experiment represent flexible and promising tools in this context. The experience gained with these techniques is widely illustrated. Benefits due to technology advancement are evidenced. The portability and the manoeuvrability of testing devices for in situ measurements are continuously improved while accuracy is enhanced. Also, significant reduction of processing times and costs is offered by the computing facilities available at present, providing simulation results of increased reliability for effective safety assessment procedures. All together, the mentioned tools permit an adequate planning of retrofitting operations that can extend the lifetime of existing infrastructures. Thus, prevention costs can be paid back by the reduction of interventions in emergency and by the reconversion of existing pipeline systems to different uses, as for instance expected in the transition from the carbon to the hydrogen era. Acknowledgements This paper summarizes the work carried out within the research project ‘Development of novel methods for the prevention of pipeline failures with security implications’ with the substantial contribution of G. Cornaggia, H. Nykyforchyn, B. Rivolta, M. Talassi, O. Zvirko. The financial support provided by NATO in the frame of the ‘Science for Peace and Security’ program is gratefully acknowledged (SPS G5055 project). Thanks are also due to P. P. Zonta and to his Company (EniProgetti, eni group) for the support offered to the studies presented in this contribution.

References 1. Bolzon, G., Boukharouba, T., Gabetta, G., Elboujdaini, M., Mellas, M. (eds.): Integrity of pipelines transporting hydrocarbons. In: Proceedings of the NATO Advanced Research Workshop on Corrosion Protection of Pipelines Transporting Hydrocarbons, Biskra, Algeria, 26–28 April 2010. Earth and Environmental Science NATO Science for Peace and Security Series C: Environmental Security. Springer, Heidelberg (2011) 2. Pirani, S., Yafimava, K.: Russian gas transit across Ukraine post-2019: pipeline scenarios, gas flow consequences, and regulatory constraints. Oxford Institute for Energy Studies, Oxford, UK (2016) 3. Haesen, E., Vingerhoets, P., Koper, M., Georgiev, I., Glenting, C., Goes, M., Hussy, C.: Investment needs in trans-European energy infrastructure up to 2030 and beyond. In: Final Report. ECOFYS Netherlands B.V., 2017 Publications Office of the European Union, Luxembourg (2018). 4. Sherif, S.A., Barbir, F., Veziroglu, T.N.: Wind energy and the hydrogen economy—review of the technology. Sol. Energy 78, 647–660 (2005) 5. Ren, L., Jiang, T., Jia, Z., Li, D., Yuan, C., Li, H.: Pipeline corrosion and leakage monitoring based on the distributed optical fiber sensing technology. Measurement 122, 57–65 (2018)

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6. Wright, R.F., Lu, P., Devkota, J., Lu, F., Ziomek-Moroz, M., Ohodnicki, P.R., Jr.: Corrosion sensors for structural health monitoring of oil and natural gas infrastructure: a review. Sensors 19, 3964 (2019) 7. Gupta, A., Sinbad, A.: Introduction to pigging & a case study on pigging of an onshore crude oil trunkline. Int. J. Latest Technol. Eng. Manage. Appl. Sci. 5, 18–25 (2016) 8. Hardie, D., Charles, E.A., Lopez, A.H.: Hydrogen embrittlement of high strength pipeline steels. Corros. Sci. 48, 4378–4385 (2006) 9. Capelle, J., Gilgert, J., Dmytrakh, I., Pluvinage, G.: Sensitivity of pipelines with steel API X52 to hydrogen embrittlement. Int. J. Hydrogen Energy 33, 7630–7641 (2008) 10. Nykyforchyn, H., Lunarska, E., Tsyrulnyk, O.T., Nikiforov, K., Gennaro, M.E., Gabetta, G.: Environmentally assisted in-bulk steel degradation of long term service gas trunkline. Eng. Fail. Anal. 17, 624–632 (2010) 11. Fassina, P., Bolzoni, F., Fumagalli, G., Lazzari, L., Vergani, L., Sciuccati, A.: Influence of hydrogen and low temperature on behavior of two pipeline steels. Eng. Fract. Mech. 81, 43–55 (2012) 12. Chernov, V.M., Kardashev, B.K., Moroz, K.A.: Low-temperature embrittlement and fracture of metals with different crystal lattices—dislocation mechanisms. Nuclear Mater. Energy 9, 496–501 (2016) 13. Benac, D.J., Cherolis, N., Wood, D.: Managing cold temperature and brittle fracture hazards in pressure vessels. J. Fail. Anal. Prev. 16, 55–66 (2016) 14. ISO Standards 148-1: Metallic materials—Charpy pendulum—impact test. International Organization for Standardization, Geneva, Switzerland (2016) 15. ASTM Standards E 1820-20: Standard test method for measurement of fracture toughness. American Society of Testing and Materials, West Conshohocken, USA (2020) 16. Fleury, E., Ha, J.S.: Small punch test to estimate the mechanical properties of steels for steam power plant: I mechanical strength. Int. J. Press. Vessels Piping 75, 699–706 (1998) 17. Campitelli, E.N., Spätig, P., Bonadé, R., Hoffelner, W., Victoria, M.: Assessment of the constitutive properties from small ball punch test: experiment and modeling. J. Nucl. Mater. 335(3), 366–378 (2004) 18. Chang, Y.S., Kim, J.M., Choi, J.B., Kim, Y.J., Kim, M.C., Lee, B.S.: Derivation of ductile fracture resistance by use of small punch specimens. Eng. Fract. Mech. 75, 3413–3427 (2008) 19. Cárdenas, E., Belzunce, F.J., Rodríguez, C., Peñuelas, I., Betegón, C.: Application of the small punch test to determine the fracture toughness of metallic materials. Fatigue Fract. Eng. Mater. Struct. 35, 441–450 (2014) 20. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Mechanical analysis at different scales of gas pipelines. Eng. Fract. Mech. 90, 434–439 (2018) 21. ISO Standards 14577–1: Metallic materials—instrumented indentation test for hardness and materials parameter—part 1: test method. International Organization for Standardization, Geneva, Switzerland (2015) 22. ISO/TR Standards 29381: Metallic materials—measurement of mechanical properties by an instrumented indentation test—indentation tensile properties. International Organization for Standardization, Geneva, Switzerland (2008) 23. Seok, C., Koo, J.: Evaluation of material degradation of 1Cr-1Mo-0.25V steel by ball indentation and resistivity. J. Mater. Sci. 41, 1081–1087 (2006) 24. Bolzon, G., Gabetta, G., Molinas, B.: Integrity assessment of pipeline systems by an enhanced indentation technique. ASCE J. Pipeline Syst. Eng. Pract. 6(1), 1–7 (2015) 25. Jang, J.I., Choi, Y., Lee, J.S., Lee, Y.H., Kwon, D., Gao, M., Kania, R.: Application of instrumented indentation technique for enhanced fitness-for-service assessment of pipeline crack. Int. J. Fract. 131(1), 15–33 (2005) 26. Bolzon, G., Molinas, B., Talassi, M.: Mechanical characterisation of metals by indentation tests: an experimental verification study for on-site applications. Strain 48(6), 517–527 (2012) 27. Bolzon, G., Buljak, V., Maier, G., Miller, B.: Assessment of elastic–plastic material parameters comparatively by three procedures based on indentation test and inverse analysis. Inverse Probl. Sci. Eng. 19(6), 815–837 (2011)

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28. Mulford, R., Asaro, R.J., Sebring, R.J.: Spherical indentation of ductile power law materials. J. Mater. Res. 19, 2641–2649 (2004) 29. Shao, Y., Qin, W., Liu, H., Qu, J., Peng, X., Niu, H., Gao, B.Z.: Multifocal multiphoton microscopy based on a spatial light modulator. Appl. Phys. B 107(3), 653–657 (2013) 30. https://www.alicona.com/en/products/portablerl/. Accessed on 26 Feb 2020 31. https://nanovea.com/portable-profilometer/. Accessed on 26 Feb 2020 32. https://www.easyarm.it/eng/index.php. Accessed on 26 Feb 2020 33. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Micro and macro mechanical analysis of gas pipeline steels. Proc. Struct. Integrity 5, 627–632 (2017) 34. Bolzon, G., Talassi, M.: Toward a non-destructive diagnostic analysis tool of exercised pipelines: models and experiences. Proc. Struct. Integr. 13, 648–651 (2018) 35. Bolzon, G.: Advances in experimental mechanics by the synergetic combination of full-field measurement techniques and computational tools. Measurement 54, 159–165 (2014) 36. Stavroulakis, G.E., Bolzon, G., Waszczyszyn, Z., Ziemianski, L.: Inverse analysis. In: Reference Module in Hashmi, S. (ed.) Materials Science and Materials Engineering, pp. 1–39. Elsevier, Oxford, UK (2016) 37. Papadrakakis, M., Lagaros, N.D., Tsompanakis, Y., Plevris, V.: Large scale structural optimization: computational methods and optimization algorithms. Arch. Comput. Methods Eng. 8, 239–301 (2001) 38. Carr, J.C., Beatson, R.K., Cherrie, J.B., Mitchell, T.J., Fright, W.R., McCallum, B.C., Evans, T.R.: Reconstruction and representation of 3D objects with radial basis functions. In: Fiume, E. (ed.), Proceedings of SIGGRAPH 2001, Computer Graphics Annual Conference, Los Angeles, CA, 12–17 July 2001, pp. 67–76. ACM Press, New York (2001) 39. Ly, H.V., Tran, H.T.: Modeling and control of physical processes using proper orthogonal decomposition. Math. Comput. Model. 33, 223–236 (2001) 40. Bolzon, G., Talassi, M.: Model reduction techniques in computational materials mechanics. In: Zavarise, G., Boso, D.P. (eds.) Bytes and Science, pp. 131–141. CIMNE, Barcelona (2012) 41. Schilders, W.H., Van der Vorst, H.A., Rommes, J. (eds.): Model order reduction: theory, research aspects and applications. Springer, Berlin (2008) 42. Bolzon, G., Rivolta, B.: Mechanical characterization of metals by small sampling size. Proc. Struct. Integr. 21, 185–189 (2019) 43. Bhushan, B.: Handbook of micro/nano tribology. CRC Press, Boca Raton (1999) 44. Bolzon, G., Bocciarelli, M., Chiarullo, E.J.: Mechanical characterization of materials by microindentation and AFM scanning. In: Bhushan, B., Fuchs, H. (eds.) Applied Scanning Probe Methods XII—Characterization, pp. 85–120. Springer, Berlin (2008) 45. Bolzon, G., Zvirko, O.: An indentation based investigation on the characteristics of artificially aged pipeline steels. Proc. Struct. Integr. 3C, 172–175 (2017) 46. ISO Standards 6508–1: Metallic materials—rockwell hardness test—part 1: test method. International Organization for Standardization, Geneva, Switzerland (2016) 47. Meng, L., Breitkof, P., Le Quilliec, G.: Identification of material parameters using indentation test—study of the intrinsic dimensionality of P-h curves and residual imprints. In: Proceedings of NUMIFORM 2016, 12th International Conference on Numerical Methods in Industrial Forming Processes, Troyes, France, 4–7 July 2016. MATEC Web of Conferences 80, 100012, pp. 1–5 (2016) 48. Bolzon, G., Maier, G., Panico, M.: Material model calibration by indentation, imprint mapping and inverse analysis. Int. J. Solids Struct. 41, 2957–2975 (2004)

In-Service Degradation of Pipeline Steels Hryhoriy Nykyforchyn

Abstract Long-term operation of structural steels causes an essential decrease of the mechanical properties, especially characteristics of brittle fracture and SCC resistance. General regularities of in-service degradation of pipeline steels are analysed in the chapter. On these base two stages of pipeline steels degradation are distinguished in the chapter. The first one is deformation aging which is characterized by improvement of characteristics of strength and hardness but from the other hand a decrease of plasticity and brittle fracture resistance. The stage II is the stage of in-bulk steel dissipated microdamaging, which is more dangerous with regard to a loss of pipeline integrity. Operational degradation of the mechanical properties of the steels is accelerated by their hydrogenation from the inner surface of the pipe, which indicates the hydrogenating ability of transported hydrocarbons. The accelerated method of pipeline steels degradation is substantiated. It is based on the common method of deformation ageing of steels by plastic strain with subsequent heat treatment up to 250 °C, however, it additionally involves preliminary hydrogen charging. Keywords Steels · Degradation · Damaging · Hydrogen · Fracture

1 Introduction More than half of oil and gas transmission pipelines in Ukraine have been operating beyond the calculated service time. Substantiation of the possibility of their further safe operation is of strategic and economic importance. Pipeline integrity is dependent on a number of factors: the quality of coating, the stress state of pipes, the corrosive activity of transported media, etc. Besides, structural integrity is determined by mechanical and other properties of metal, which determine bearing capacity of an object, namely, its capability to withstand the applied mechanical loads in specific H. Nykyforchyn (B) Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_2

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H. Nykyforchyn

operating conditions. Apart from the mechanical properties, corrosion resistance, resistance to stress corrosion cracking (SCC) and hydrogen assisted cracking (HAC) and fatigue strength should be taken into account. Therefore, in recent years, considerable attention has been paid to this problem in Ukraine [1–6]. In general, longterm operation of structural steels leads to significant worsening of their physicomechanical properties, which determine workability of an object. This aspect is essential, since in order to justify the further safe operation of responsible structures, it is necessary to take into account not the initial, but the current properties of the material. It was shown that the characteristics of brittle fracture resistance reduce the most intensively [7, 8], thereby the material becomes especially susceptible to the action of corrosive-hydrogenating media due to enhanced susceptibility of operated steels to SCC and HAC [5, 9, 10], and also corrosion fatigue [3]. For assessment of the current technical condition of pipeline steel non-destructive techniques based on instrumental indentation [11–14] and electrochemical methods [15–18] can be used during operation. Special aspect of operational degradation of pipelines is the damaging role of hydrogen. Hydrogen can be active in enhancing fracture mechanisms, especially at the stage of crack propagation [5, 19]. Role of hydrogen is also taken into account as a factor of delamination in a pipe wall due to creation of high pressure in defects [20–23]. Furthermore, hydrogen can facilitate operational degradation of metal when acting combined with working stresses [24, 25].

2 General Regularities of In-Service Degradation of Long Term Operational Structural Steels 2.1 Strength, Plasticity and Brittle Fracture Resistance Table 1 summarizes the mechanical testing results for 17H1S (equivalent to X52), X52, X60 and X70 pipeline steels in the as-received state (spare pipes) and after their operation for 25–51 years. Data are obtained using longitudinal specimens (relative to the rolling direction). Table 1 shows that plasticity and brittle fracture resistance of steels decreases as a result of long-term service. However, the expected reduction of both plasticity characteristics was not always observed. In some cases, the influence of operation time on steel elongation was controversial, namely, for the 17H1S and X52 steels this parameter increased whereas reduction in area decreased. Similar effects have been known for operated steels of power engineering facilities [26, 27] and explained by their intensive in-bulk microdamaging. Opening a large number of microcracks during loading of a specimen contributes to its overall deformation, thus, elongation can even increase despite a significant decrease of brittle fracture characteristics.

In-Service Degradation of Pipeline Steels

17

Table 1 Mechanical properties of different pipeline steels after their long-term operation Pipe steel

Service time (years)

σUTS (MPa)

σY (MPa)

RA (%)

δ(%)

KCV (J/cm2 )

17H1S

0 (As-received)

470

301

65.9

21.2

255

624

380

72.0

23.9

129

564

413

74.0

29.0

348

30

541

368

55.3

26.3

175

36

606

453

64.0

21.0

110

38

520

357

73.1

25.4

154

40

515

302

69.2

26.3

125

51

610

449

67.0

24.5

56/33

X52

0

475

355

72.9

22.7

350

412

X521

30

451

268

64.4

20.8

189

127

536

362

54.6

29.7

173

79

592

510

81.9

23.2

342

X522 X60

0 25

633

502

71.1

18.5

225

X70

0

615

521

73.4

22.3

277

37

641

547

74.5

23.0

350/310

J 0.2 (kN/m)

Note KCV values in the denominator refer to transverse specimens relative to the pipe axis

Impact toughness KCV, and fracture toughness determined by J-integral show a most essential decrease during service. The sensitivity of the J-integral method to operational degradation is higher. It is suggested that such low brittle fracture resistance of the operated steels is caused by accumulation of defects in metal during long-term operation [28]. It is important to note that when the components of impact toughness value are separated in crack initiation and propagation [29, 30], it is shown that KCV decreased during operation mainly due to a decrease in the component of crack propagation, which in fact is fracture mechanics parameter. Thus, comparative mechanical testing of operated and non-operated steels leads to the conclusion that brittle fracture characteristics are the most sensitive to in-service changes in metal, and among them— parameters of crack growth resistance expressing the fracture resistance of material in a local volume.

2.2 Stress Corrosion Cracking of Operated Pipeline Steels Slow strain rate tests were performed to evaluate the susceptibility to the near-neutralpH stress corrosion cracking (SCC) of the long-term operated pipeline steels. The 17H1S, X60 and X70 steels were studied. Smooth cylindrical specimens cut from the operated gas pipelines in the longitudinal direction (direction of rolling) were

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H. Nykyforchyn

Table 2 Mechanical properties of studied pipeline steels Pipe steel

Service time (years)

RASCC (%)

RAair (%)

SCC sensitivity parameter (KSCC )

17H1S

0 (As-received)

66.1

65.9

0

51.1

72.0

0.29

71.6

74.0

0.03

30

45.8

55.3

0.17

36

53.0

64.0

0.17

51

66.8

67.0

0

0 (As-received)

77.6

81.9

0.05

25

67.3

71.1

0.05

0 (As-received)

53.6

73.4

0.27

37

53.8

74.5

0.28

X60 X70

tested by tension with the strain rate of 3 × 10–3 s−1 and 1 × 10–6 s−1 for the test in air and environment, respectively. The simulated soil solution NS4 saturated with CO2 was used as corrosive environment. Tests were performed under the open circuit condition (at corrosion potential) under room temperature. Reduction in area of the studied steels, determined in air RAair , and reduction in area, determined in test solution RASCC , as well as SCC sensitivity parameter Kscc (Kscc = 1 – [RAscc /RAair ] are reported in Table 2. No susceptibility of the 17H1S pipeline steel in the as-received state to SCC in NS4 test solution, saturated CO2 was revealed. The as-received X60 steel exhibited very low sensitivity to SCC: reduction in area and elongation insignificantly decreased. Resistance to SCC of the 17H1S pipeline steel decreased after long-term operation. At the same time long-term operation didn’t influence the susceptibility of the X60 steel to stress corrosion cracking: X60 steel in both studied states had the same value of stress corrosion cracking sensitivity parameter (see Table 2). Tests on the X70 steel having a higher strength indicated the susceptibility of the steel in both investigated states to SCC in NS4 solution saturated with CO2 under open circuit conditions.

2.3 Regularities of Corrosion Fatigue Crack Growth in Steels Taking into Account Their Operational Degradation The durability of structural elements is usually divided into two components: the stage of crack initiation and the stage of crack propagation. The crack propagation stage is considered, as a rule, using fracture mechanics. In cyclic loading, the main tool to describe the fracture process under cyclic loading is the fatigue crack growth curve— the dependence of fatigue crack growth rate da/dN (a—crack length, N—number of loading cycles) on stress intensity factor range K.

In-Service Degradation of Pipeline Steels

19

Experience shows that cracks usually occur at the outer surface of a pipe, due to the aggressive action of the soil environment in case of loss of protective properties of the insulation coating. Corrosion fatigue crack growth in as-received and operated 17H1S, X60 and X70 pipeline steels was studied in NS4 solution (pH 7) using 0.5CT specimens. The tests were done at room temperature under stress ratio R = 0.1 and frequency f = 10 Hz (in air) and 1 Hz (in corrosive environment). The lateral surfaces of the specimen were polished up to 2000 grit and pre-cracked in fatigue to provide a sharpened fatigue crack which removed the effect of the machined starter notch and eliminated the effects on subsequent crack growth rate data caused by changing crack front shape or pre-crack loading history. Crack extensions were measured visually on both sides of the specimens with accuracy of 0.05 mm after a different number of loading cycles. Stress intensity factor range K th was determined in the K-decreasing test procedure conducted by shedding force in a series of decremental steps. As a result, the fatigue crack growth curves da/dN = f (K), which are presented in Fig. 1, were built for each specimen. Figure 1 shows that the negative effect of operation is noticeable only for the 17H1S steel; the threshold value of stress intensity factor range K th for the operated steel is somewhat lower comparing to the steel in the initial state. Any significant changes at the Paris region were not observed for all tested steels; therefore, steel operation does not affect fatigue crack growth in this range of K values. Corrosion fatigue crack growth tests performed in the model soil solution NS4 revealed a negative effect of the aggressive medium only for the X70 operated steel

Fig. 1 Effect of operation on fatigue crack growth of different pipeline steels in air

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H. Nykyforchyn

Fig. 2 Effect of corrosion environment NS4 on fatigue crack growth of the X70 steel in the operated state

(Fig. 2): in the middle range of K values some acceleration of fatigue crack growth is observed, that indicates susceptibility of the steel to environmentally assisted crack growth under cyclic loading. On the other hand, if this acceleration is conditionally considered as a plateau, it is suggested [9] that an SCC mechanism is active under conditions of cyclic loading. This effect could be considered as manifestation of steel operational degradation of the X70 steel. However, it should be pointed out that no other negative effect of long-term operation impact strength KCV was found for this steel. Contrariwise, impact toughness was even somewhat higher after operation. Thus, it can be concluded, that the brittle fracture resistance determined in air (KCV) and the corrosion fatigue crack growth resistance have different sensitivity to service degradation of the pipeline steel.

3 Role of Hydrogen in In-Bulk Service Degradation of Pipeline Steels The values of the average hydrogen concentration CH in some studied pipeline steels measured by desorption at different temperatures are presented in Table 3 [31]. It is revealed that the operated X522 steel, taken from inner bottom pipe section, is characterized by a higher amount of CH in comparison to that for the X52 steel in the as-received state and even for the X521 steel with the same operation time. This

In-Service Degradation of Pipeline Steels

21

Table 3 Concentration of hydrogen CH in API X52 5L pipeline steel measured by desorption at different temperatures T Pipeline steel

Service time (years)

Pipe section

T (◦ C)

Total CH (ppm)

200

400

600

X52

0 (As-received)

1.40

0.07

0.04

1.5

X521

30

Top, outer

0.10

0.50

0.60

1.2

X521

30

Bottom, inner

0.01

1.00

0.40

1.4

X522

30

Top, outer

0.30

0.60

0.80

1.7

X522

30

Bottom, inner

0.15

0.80

4.15

5.1

result is an evidence of hydrogenation of pipe wall from the inner surface as a result of electrochemical interaction of metal with water which tends to accumulate at the pipe bottom. It should be also noted that the method is effective to measure residual hydrogen content since the tests were carried out after more than one year later than pipes were put out of operation. The peculiarity of this research is the following. A higher concentration of residual hydrogen is concerned with more intensive in-bulk microdamaging, which act as traps for hydrogen. Damaging in turn leads to a decrease first of all in resistance to brittle fracture. Therefore, a correlation exists between hydrogen content in steels and their impact toughness, as derived from Table 4. Here, lower values of impact toughness correspond to higher hydrogen concentrations in the operated metal, as compared to the as-received steel. Special role of transported hydrocarbons as a source of hydrogenation of a pipe wall is illustrated in Table 5. It could be noticed that if specimens for Charpy testing are cut closer to the internal surface of the pipe, then the values of KCV are lower. This result cannot be related to the gradient of properties in the pipe wall for a non-operated pipe, since the as-received metal is more likely to have an inverse relationship. Thus, hydrogenation of the pipe wall from the inside is an important factor in accelerating the operational degradation of the metal [24, 32]. The mechanism of this acceleration consists in intensification of in-bulk dissipated microdamaging, Table 4 Concentration of hydrogen CH measured by extraction, and impact toughness of pipeline steels Pipeline steel

Steel state

10HS

As-received

10HS

Operated 28 years

X52

As-received

X522

Operated 30 years

X522

Operated 30 years

CH (ppm)

KCV (J/cm2 )

–

1.6

180

Top

2.6

95

–

1.5

196

Top

2.4

77

Bottom

4.2

57

Pipe section

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H. Nykyforchyn

Table 5 Mechanical properties of the 17H1S pipeline steel Steel state

Service time (years)

As-received Operated

28 years 31 years

Pipe section

Hardness HRB

KCV (J/cm2 )

Inner

90

206

Outer

95

194

Inner

87

165

Outer

89

169

Inner

78

115

Outer

81

133

which in turn results in a drastic decrease of resistance to brittle fracture of pipeline steels.

4 Stages of Operational Degradation of Pipeline Steels Figure 3 illustrates two stages of operational degradation of structural steels on the whole, and particularly pipe steels: deformation ageing (stage I) and development of dissipated damaging (stage II) [22]. At the stage I, strength and hardness rise whereas plasticity and brittle fracture resistance decrease. Stage II is implemented after a certain period of operation. Its main peculiarity is a possible decrease of strength and hardness together with further decline in brittle fracture resistance. Besides, atypical changes in elongation with the plasticity parameter are eventual. This characteristic can even rise due to contribution of opening of microcracks into the total elongation. However, the tendency to delamination in ferritic-pearlitic pipe steels led to modification of stage II, with two substages in it, namely, the formation of randomly oriented defects (substage IIA), and development of damages oriented along the texture with a reduction of cohesion between ferrite and pearlite strips in a course of service (substage IIB). In this case, when testing standard axial specimens of such Fig. 3 Scheme of the two-stage in-bulk steel degradation: stage I—deformation aging; stage II includes two substages: IIA—disoriented dissipated damaging, and IIB—damage accumulation in the rolling direction

In-Service Degradation of Pipeline Steels

23

metal for impact strength determination, the fracture plane intersects the delaminations oriented along the pipe generatrix. This requires increased fracture energy and, therefore, results in overestimated resistance to brittle fracture despite further intensification of operational degradation of metal.

5 Accelerated Method of Steel Degradation As shown above, hydrogenation of metal during corrosion process, together with working stresses, facilitates the development of in-bulk damaging at microscale, which is the main reason for a drastic decrease of resistance to brittle fracture. Based on this, a method of accelerated degradation of pipeline steels has been elaborated [9, 24, 25]. It is consisted in the deformation aging of steel preliminary charged with hydrogen. Specimens were cut from reserve pipes. The accelerated degradation procedure is as follows: electrolytic hydrogenation of specimens in H2 SO4 solution (pH 2) during 95 h, followed by tensile loading up to 2.8% axial strain, and then aging at 250 °C for 1 h. Cathodic current density for hydrogen charging varied from 0.33 to 20 mA/cm2 depending on the steel strength. The highest value (icat = 20 mA/cm2 ) was considered for the 17H1S steel, icat = 10 mA/cm2 for the X60 steel and the lowest value (icat = 0.33 mA/cm2 ) concerned the X70 steel due to a different susceptibility of these steels to hydrogen embrittlement. Figure 4 illustrates a microstructure of the 17H1S steel degraded in laboratory conditions, in longitudinal and transversal directions. The steel has a typical ferritepearlite microstructure. The grain size was quite non-uniform. Narrow strips of pearlite grains are separated by wide bands of ferrite grain aggregations. Any special differences between the microstructure of the degraded steel in comparison with that of the as-received state were not revealed. However, the damages along the interfaces between non-metallic inclusions and the matrix, as well as along the interfaces between ferrite and pearlite grains were noted. Such damages were practically not observed in the microstructure of the as-received steel. Based on this, it was concluded that accelerated degradation of the 17H1S steel microstructure, induced in laboratory, was manifested by weakening interphase boundaries. Moreover, boundaries between ferrite and carbide lamellae within pearlite were also weakened, since they have easily been removed during specimen polishing. This can be seen more clearly at higher resolution. Moreover, it is more obvious on the longitudinal section. Mechanical properties of investigated steels after in-laboratory degradation were determined by tensile tests up to fracture at a deformation rate of 3 × 10–3 s–1 . The obtained values of the mechanical characteristics for the 17H1S, X60 and X70 steels are presented in Table 6. Evidently, the revealed reduction of plasticity and resistance to brittle fracture due to the proposed method of laboratory degradation of steels is associated with the development of dissipated microdamage, which is metallographically shown for the steel 17H1S steel as an example.

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H. Nykyforchyn

Fig. 4 SEM image in longitudinal (a, c) and transversal (b, d) directions of the 17H1S pipeline steel after in-laboratory degradation

Table 6 Mechanical properties of as-received pipe steels and after in-laboratory degradation Pipeline steel

Steel state

σUTS (MPa)

σY (MPa)

Elongation (%)

RA (%)

KCV (J/cm2 )

17H1S*

As received

564

463

28.8

73.7

348

Degraded

602

561

15.9

59.5

245

X60

As received

592

510

23.2

81.9

319

Degraded

588

547

22.1

77.7

185

X70

As received

615

521

22.3

73.4

277

Degraded

687

642

15.8

60.6

209

Note icat = 10

mA/cm2

for 17H1S steel

Susceptibility of the degraded pipe steels to SCC was also investigated. Inlaboratory damaged specimens were subjected to SCC tests by monotonic tension with the strain rate of 10–6 s−1 under open circuit conditions (at the corrosion potential) and room temperature in NS4 test solution saturated with CO2 . The results are given in Table 7. Comparison of the results obtained by testing 17H1S and X60 steels in the asreceived state and after accelerated degradation in air and by slow rate tension in NS4 solution showed that the strength and plasticity characteristics of both steels

In-Service Degradation of Pipeline Steels

25

Table 7 Results of SCC tests of investigated steels after in-laboratory degradation Pipeline steel

Steel state

σUTS (MPa)

σY (MPa)

Elongation (%)

RA (%)

17H1S

As-received

473

304

21.1

66.1

Degraded (icat = 10 mA/cm2 )

486

375

–

63.2

Degraded (icat = 20 mA/cm2 )

467

426

10.9

46.4

X60

As-received

565

489

21.9

77.6

Degraded

610

551

16.4

71.3

X70

As-received

615

521

22.3

73.4

Degraded

677

642

–

50.3

in the as-received state are insignificantly changed under the influence of the test environment. At the same time, the degraded steels revealed a high sensitivity to the environment (the essential increase of σY is caused by deformation hardening during the preliminary plastic deformation of specimens in accordance with the procedure of accelerated degradation and is not connected with the environment action). Moreover, environmental sensitivity of the 17H1S steel was higher in comparison with the X60 steel. In particular, plasticity of the 17H1S steel under the influence of the test solution decreased more than that for the X60 steel. Fractographic peculiarities of the specimens after SCC tests have been analysed in [33] relative to the 17H1S and X60 steels. A common fractographic feature at the micro scale, namely microdelamination, for the operated and in-laboratory degraded pipeline steels was observed, which indicated an important role of hydrogen in degradation. A significant decrease of plasticity at SCC testing was observed for both steels only after their degradation in laboratory conditions. This is attributed to cracking along the boundaries of ferrite and pearlite grains, formation of deep secondary intergranular cracks and delaminations between ferrite and cementite lamellae inside pearlite grains as well. Fatigue and corrosion fatigue crack growth testing of degraded pipeline steels were performed. The samples 10 × 6 × 220 mm in size made of the 17H1S, X60 and X70 steels in the as-received state were subjected to in-laboratory degradation for further fatigue crack growth testing. The beam bend specimens with a size of 10 × 6 × 160 mm were manufactured from the samples after their treatment for further fatigue and corrosion fatigue crack growth tests in NS4 solution by cantilever bending. It should be noted that standard CT specimens were not possible to cut from the degraded samples. Specimens were investigated under stress ratio R = 0.1, and the frequency for corrosion fatigue testing was reduced to f = 1 Hz. The effect of corrosion environment on fatigue behaviour of the artificially degraded steel was more pronounced for the X70 steel (Fig. 5). Similar acceleration of fatigue crack growth was also observed for the operated X70 steel (see Fig. 2) starting from K ~15 MPa·m1/2 . This area in the fatigue crack growth curve is a manifestation of steel susceptibility to SCC. At the upper part of the fatigue

26

H. Nykyforchyn

Fig. 5 Effect of corrosive environment (NS4 solution) on fatigue behaviour of the X70 steel in the in-laboratory degraded state

crack growth curve (K ≥ 30 MPa·m1/2 ), no essential difference was observed for artificially degraded steel comparing to corresponding tests in air.

6 Concluding Remarks Long-term operation in general has a negative effect on the mechanical properties of low-carbon pipeline steels with ferrite-pearlite structure. That allows claiming their operational degradation. The resistance to brittle fracture of steels is reduced most significantly; besides, its crack propagation component is the most sensitive for the estimation of steel operational degradation. Thus, crack growth facilitated by steel operation is a major risk for structural integrity of a pipe. Operation of pipeline steels also adversely affects their resistance to stress corrosion cracking in a simulated soil solution. Concerning fatigue crack growth, the negative effect of the environment is only found under higher K levels, reflecting the susceptibility of the steel to SCC under cyclic loading. Operational degradation of the mechanical properties of the steels is accelerated by their hydrogenation from the inner surface of the pipe, which indicates the hydrogenating ability of the transported hydrocarbons. This is confirmed by the worse properties of the metal of those sections of the pipe where the conditions for electrochemical interaction with water condensate were favourable, and also correlation between the characteristics of brittle fracture resistance and the concentration of

In-Service Degradation of Pipeline Steels

27

the residual hydrogen in the metal of the pipe wall. Role of hydrogen in the operational degradation of steels primarily consists in the development of dissipated microdamaging in the bulk of the pipe wall. There are two main stages of operational degradation of steel: deformation aging and dissipated damaging. The first stage is characterized, on the one hand, by an increase in strength, and on the other hand, by a decline in the characteristics of plasticity and resistance to brittle fracture. The second stage of degradation can be characterized by a number of mechanical effects. In particular, the opening of multiple cracks of dissipated damage can contribute to the elongation of a specimen during its tensile tests and lead to the incorrect estimation of the steel plasticity. Hydrogenation of the metal, facilitating its microdamaging, can enhance the manifestation of this effect. The accelerated method of in-laboratory degradation of pipeline steels is substantiated. It is based on the common method of deformation ageing of steels by plastic strain with subsequent heat treatment up to 250 °C. However, it additionally involves preliminary hydrogen charging. The proposed method is efficient for simulation of in-laboratory degradation of steels and operational changes in their mechanical properties and resistance to stress corrosion cracking. Acknowledgements This research has been supported by the NATO in the Science for Peace and Security Programme under the Project G5055.

References 1. Tsyrulnyk, O.T., Nykyforchyn, H.M., Zvirko, O.I., Petryna, D.Yu.: Embrittlement of the steel of an oil-trunk pipeline. Mater. Sci. 40(2), 302–304 (2004) 2. Maruschak, P., Bishchak, R., Konovalenko, I., Menou, A., Brezinová, J.: Effect of long term operation on degradation of material of main gas pipelines. Mater. Sci. Forum 782, 279–283 (2014) 3. Andreikiv, O.E., Hembara, O.V., Tsyrul’nyk, O.T., Nyrkova L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238 (2012) 4. Tsyrulnyk, O.T., Voloshyn, V.A., Petryna, D.Yu., Hredil, M.I., Zvirko, O.I.: Degradation of properties of the metal of welded joints in operating gas mains. Mater. Sci. 46(5), 628–632 (2011) 5. Krasovskii, A.Y., Lokhman, I.V., Orynyak, I.V.: Stress-corrosion failures of main pipelines. Strength Mater. 44(2), 129–143 (2012) 6. Krechkovs’ka, H.V., Tsyrul’nyk, O.T., Student, O.Z.: In-service degradation of mechanical characteristics of pipe steels in gas mains. Strength Mater. 51(3), 406–417 (2019) 7. Zvirko, O.I., Kret, N.V., Tsyrulnyk, O.T., Vengrynyuk, T.P.: Influence of textures of pipeline steels after operation on their brittle fracture resistance. Mater. Sci. 54(3), 400–405 (2018) 8. Hredil, M., Krechkovska, H., Student, O., Kurnat, I.: Fractographic features of long term operated gas pipeline steels fracture under impact loading. Proc. Struct. Integr. 21, 166–172 (2019) 9. Zvirko, O.I., Savula, S.F., Tsependa, V.M., Gabetta, G., Nykyforchyn, H.M.: Stress corrosion cracking of gas pipeline steels of different strength. Proc. Struct. Integr. 2, 509–516 (2016)

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10. Zvirko, O., Gabetta, G., Tsyrulnyk, O., Kret, N.: Assessment of in-service degradation of gas pipeline steel taking into account susceptibility to stress corrosion cracking. Proc. Struct. Integr. 16, 121–125 (2019) 11. Yang, Y., Wang, W., Song, M.D.: The measurement of mechanical properties of pipe steels in service through continuous ball indentation test. Proc. Eng. 130, 1742–1754 (2015) 12. Bolzon, G., Zvirko, O.: An indentation based investigation on the characteristics of artificially aged pipeline steels. Proc. Struct. Integr. 3, 172–175 (2017) 13. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Micro and macro mechanical analysis of gas pipeline steels. Proc. Struct. Integr. 5, 627–632 (2017) 14. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Mechanical analysis at different scales of gas pipelines. Eng. Fail. Anal. 90, 434–439 (2018) 15. Nykyforchyn, H., Zvirko, O., Tsyrulnyk, O.: Non-destructive diagnostics of hydrogen-induced degradation of pipelines steels by electrochemical method. In: Gdoutos, E.E. (ed.) Proceedings of 14th International Conference on Fracture ICF 2017, vol. 1, pp. 596–597. Rhodes, Greece (2017) 16. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O.: Electrochemical fracture analysis of in-service natural gas pipeline steels. Proc. Struct. Integr. 13, 1215–1220 (2018) 17. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O., Krechkovska, H.: Non-destructive evaluation of brittle fracture resistance of operated gas pipeline steel using electrochemical fracture surface analysis. Eng. Fail. Anal. 104, 617–625 (2019) 18. Zvirko, O., Nykyforchyn, H., Tsyrulnyk, O.: Evaluation of impact toughness of gas pipeline steels under operation using electrochemical method. Proc. Struct. Integr. 22, 299–304 (2019) 19. Nazarchuk, Z.T., Nykyforchyn, H.M.: Structural and corrosion fracture mechanics as components of the physicochemical mechanics of materials. Mater. Sci. 54(1), 7–21 (2018) 20. Nykyforchyn, H.M., Zvirko, O.I., Tsyrulnyk, O.T.: Hydrogen assisted macrodelamination in gas lateral pipe. Proc. Struct. Integr. 2, 501–508 (2016) 21. Zvirko, O.I., Mytsyk, A.B., Tsyrulnyk, O.T., Gabetta, G., Nykyforchyn, H.M.: Corrosion degradation of steel of an elbow of gas pipeline with large-scale delamination after long-term operation. Mater. Sci. 52(6), 861–865 (2017) 22. Nykyforchyn, H., Zvirko, O., Tsyrulnyk, O., Kret, N.: Analysis and mechanical properties characterization of operated gas main elbow with hydrogen assisted large-scale delamination. Eng. Fail. Anal. 82, 364–377 (2017) 23. Stasyuk, B.M., Kret, N.V., Zvirko, O.I., Shtoiko, I.P.: Analysis of the stressed state of a pipe of gas pipeline with hydrogen-induced macrodefect. Mater. Sci. 55(1), 124–129 (2019) 24. Tsyrul’nyk, O.T., Kret, N.V., Voloshyn, V.A., Zvirko, O.I.: A procedure of laboratory degradation of structural steels. Mater. Sci. 53(5), 674–683 (2018) 25. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O.: Laboratory method for simulating hydrogen assisted degradation of gas pipeline steels. Proc. Struct. Integr. 17, 568–575 (2019) 26. Nykyforchyn, H.M., Student, O.Z., Markov, A.D.: Abnormal behavior of high-temperature degradation of the weld metal of low-alloy steel welded joints. Mater. Sci. 43(1), 77–84 (2007) 27. Student, O.Z., Krechkovs’ka, H.V.: Anisotropy of the mechanical properties of degraded 15Kh1M1F steel after its operation in steam pipelines of thermal power plants. Mater. Sci. 47(5), 590–597 (2012) 28. Hredil, M.I.: Role of disseminated damages in operational degradation of steels of the main gas conduits. Metallofizika i Noveishie Tekhnologii 33(Spec. Iss.), 419–426 (2011) 29. Gabetta, G., Nykyforchyn, H.M., Lunarska, E., Zonta, P.P., Tsyrulnyk, O.T., Nikiforov, K., Hredil, M.I., Petryna, D.Yu., Vuherer, T.: In-service degradation of gas trunk pipeline X52 steel. Mater. Sci. 1, 104–119 (2008) 30. Gredil, M.I.: Operating degradation of gas-main pipeline steels. Metallofizika i Noveishie Tekhnologii 30(Special Issue), 397–406 (2009) 31. Nykyforchyn, H., Lunarska, E., Tsyrulnyk, O., Nikiforov, K., Gabetta, G.: Effect of the longterm service of the gas pipeline on the properties of the ferrite–pearlite steel. Mater. Corros. 9, 716–725 (2009)

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32. Hredil, M., Tsyrulnyk, O.: Inner corrosion as a factor of in-bulk steel degradation of transit gas pipelines. In: Proceedings of the 18th European Conference on Fracture (ECF-18), manuskript No. 483. Dresden, Germany (2010) 33. Nykyforchyn, H., Krechkovska, H., Student, O., Zvirko, O.: Feature of stress corrosion cracking of degraded gas pipeline steels. Proc. Struct. Integr. 16, 153–160 (2019)

Non-destructive Electrochemical Evaluation of Pipeline Degradation Olha Zvirko and Oleksandr Tsyrulnyk

Abstract Long-term operation of natural gas transmission pipelines leads not only to the appearance of macro defects but also to in-bulk damaging of pipeline steels at nano- and micro-scales. In-bulk steel degradation and a decrease in characteristics of brittle fracture resistance of pipeline steels under long-time operation increase significantly a failure risk. Therefore, deterioration of pipelines under operation calls for effective methods for current condition evaluation. The paper is aimed to the development of a prediction method of degradation of pipeline steel in operating conditions based on electrochemical correlation. The low-carbon ferrite-pearlite steels with different strength of gas transit pipelines after long-term operation were investigated. It was shown that mechanical and electrochemical properties of the pipeline steels were deteriorated due to long-term operation. It was found that one of the most sensitive parameters to in-bulk steel degradation among electrochemical properties was polarization resistance. An acceptable correlation between relative changes in polarization resistance and impact toughness of steels caused by long-term service was revealed. It was concluded that mechanical properties changes of pipeline steels caused by degradation under operation can be evaluated by measurements of changes in their electrochemical characteristics. Having initial properties of the steel, its current properties can be predicted. The method enables non-destructive in-service assessment of degradation degree of brittle fracture resistance of pipeline steels. The verification studies of prediction method of pipeline steel degradation were carried out on damaged and operated pipeline steels. Keywords Pipeline steel · Hydrogen degradation · Brittle fracture · Prediction method · Polarisation resistance · Electrochemical analysis

O. Zvirko (B) · O. Tsyrulnyk Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_3

31

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O. Zvirko and O. Tsyrulnyk

1 Introduction Natural gas transmission pipelines are important components of worldwide energy supply. Nowadays, a special attention is paid by scientists to the problem of ageing and in-service degradation of gas pipelines because many of them are near the end of their design life. Ageing of a gas transit pipeline is not the most important factor affecting the safety of that pipeline [1]. However, time-dependent degradation of pipeline steels can cause many problems. Thus, hydrogen embrittlement, in-bulk damaging of pipeline steels at nano- and micro-scales, hydrogen-induced and stress corrosion cracking, deterioration of mechanical and corrosion properties is often the results of in-service degradation [2–11]. This leads to a loss of the initial mechanical properties which were used as input data for engineering calculations at pipeline design stage and associated to a safe serviceability of the pipelines. The risk of failure increases significantly with decreasing brittle fracture resistance of pipeline steels under long-time operation. Since a pipeline’s fitness for service may degrade during operation, the pipeline should be periodically assessed and timely repaired. Pipelines are subject to periodic in-service inspection by non-destructive testing methods, which detect and size defects and damages. However, for the correct prediction of the residual lifetime of aging pipelines, considering serviceability, leakage and structural integrity, the current technical condition of the pipeline steel should be taken into account [12–14]. The environment in which a pipeline operates (soil and hydrocarbons) can cause hydrogen embrittlement and stress corrosion cracking phenomena, both of which may lead to brittle fracture due to degradation of pipeline steel [9, 15, 16]. Both mechanical and electrochemical characteristics of pipeline steels are significantly deteriorated as a result of long-term operation [2–12, 17, 18]. Deterioration of pipelines under operation calls for effective methods for actual condition evaluation. With the purpose of evaluation of in-service degradation of pipeline steel by destructive methods, the most sensitive mechanical characteristics are impact toughness, fracture toughness, resistance to stress corrosion cracking [4, 9]. Among nondestructive methods, special attention is given to the electrochemical characterization [19–23], since it was demonstrated that electrochemical characteristics of a metal are sensitive to change in its state caused by in-service degradation. Electrochemical tests can be performed on a pipeline without the need of extracting material specimens for laboratory testing. The present paper summarizes studies [20–23] aimed to develop and verify methods to predict the degradation of ferrite-pearlite pipeline steel in operating conditions, based on electrochemical correlation.

Non-destructive Electrochemical Evaluation of …

33

2 Experimental 2.1 Materials The work consisted in characterization of the pipeline steels with different strength. Three 17H1S (Ukrainian code, 0.17C–Mn–Si, strength grade API 5L X52), API 5L X52, API 5L X60 and API 5L X70 low-carbon pipeline steels in different states, as-received and after long-term operation (25–53 years), were studied. Pipe sections being investigated in the study were cut out from gas transmission pipelines after different time of operation: 17H1S—28–53 years, X52—30 years (marked X52(10) and X52(12) for wall thickness 10 and 12 mm, respectively), X60—25 years and X70—37 years. Samples from the top and bottom sections of the serviced pipes made of X52 steel were also investigated in order to distinguish the influence of possible corrosion due to condensed water, accumulating on the pipe bottom, on degradation of the pipeline steel. With the purpose of comparing the behaviour and properties of steels and evaluating their degradation degree, samples were also taken from reserved pipes (as received) made of steels with different strength grades (X52, X60 and X70).

2.2 Impact Testing Impact toughness KCV of the studied steels, characterising brittle fracture resistance, was determined using Charpy V-notch specimens. The standard specimens having cross section of 10 × 10 mm with sharp V-type notch of radius of about 0.25 mm were used for impact testing. The specimens were machined from pipes in the longitudinal and transversal directions of the pipe section. Notch was cut out from side of the internal pipe surface.

2.3 Electrochemical Investigations Electrochemical tests were carried out using a potentiodynamic method in order to study the electrochemical behaviour of steels and to determine their susceptibility to corrosion degradation during long-term operation. Investigations were performed on Bio-Logic SP-300 and IPC-Pro potentiostats, using a standard three-electrode electrochemical cell consisting of working electrode, Ag/AgCl (saturated KCl) reference electrode and auxiliary Pt electrode. The working electrodes were made from the studied steels in the form of bars with all polished surfaces. Insulating waterproof coating was applied on all surfaces of the working electrodes, except the selected area of about 0.5 cm2 for electrochemical studies and for current supply. Potentiodynamic polarisation curves were performed by sweeping potential from −1.1 V to corrosion

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O. Zvirko and O. Tsyrulnyk

Table 1 Chemical composition of NS4 test solution Components

KCl

NaHCO3

CaCl2 · 2H2 O

MgSO4 · 7H2 O

Concentration in mg/L

122

483

181

131

potential (E corr ) E corr + 0.6 V versus Ag/AgCl at a sweep rate of 1.0 mVs−1 under ambient temperature. The steels were tested in NS4 test solution simulating soil environment. Chemical composition of NS4 test solution is presented in Table 1. The solution containing (mg/L) 14,440 Na+ ; 25,400 Cl– ; 129 K+ ; 5.0 SO4 2– ; 2.5 Li+ ; 600 Ca 2+ ; 522 HCO3 – ; 518 Mg2+ ; 140 Ba2+ ; 5.0 NO3 – ; 389 Sr2+ ; 3.6 F– ; 0.25 Fe2+ ; 100 Br– ; 0.5 Mn2+ ; 21 I– ; 1.0 Al3+ ; 5.0 PO4 3– ; 52 NH4 + ; 18 SiO2 2 (alkalinity—455), simulating aqueous condensate in gas transit pipelines [15], was also used as the test medium. The test solutions were prepared from analytical grade reagents. The basic electrochemical characteristics of steels (corrosion potential E corr , corrosion current density icorr , the Tafel constants bc and ba of the cathodic and anodic reactions, respectively) were determined by the graph-analytic method. The polarisation resistance Rp was calculated using the Stern-Geary equation: E K , = Rp = i i corr

(1)

where K is the Stern-Geary coefficient: K =

ba · bc . 2.3 · (ba + bc )

(2)

3 Deterioration of Brittle Fracture Resistance of Pipeline Steels Under Operation Mechanical properties of pipeline steels deteriorate during long-term operation. Generally, strength properties of steels are insignificantly changed due to in-service degradation [3, 10, 12]. Nevertheless, characteristics of brittle fracture resistance of steels sharply decrease as a result of long-term operation [3, 7–9, 12]. Relative changes in impact toughness of X52 and X60 grade pipeline steels caused by longterm operation are illustrated in Fig. 1. It should be noted that the high strength X70 steel after operation was characterized by increase in impact toughness from 277 to 330 J/cm2 and from 237 to 250 J/cm2 in the longitudinal and transversal directions of the pipe, respectively. It can be associated with some difference in manufacturing process of different pipes, or with intensive in-bulk dissipated damage of the operated X70 steel, which causes increasing fracture energy, as it was demonstrated in [7, 8].

Non-destructive Electrochemical Evaluation of …

35

Fig. 1 Relative changes in impact toughness (KCVdeg /KCVin ) for the 17H1S, X52 and X60 pipeline steels caused by long-term operation

Table 2 Fracture toughness of the pipeline steels

Pipeline steel

Steel state

√ J0.2 (MPa m)

X52

As-received

412

X52

Operated 30 years

79

X52

Operated 30 years

127

17H1S

As-received

322

17H1S

Operated 29 years

175

17H1S

Operated 31 years

201

In-service degradation of ferrite-pearlite pipeline steels implies a number of features related to decreasing cohesion between the structure fibers and developing delamination and microcracks orientated along rolling direction [8]. Fracture of longitudinal specimens is significantly influenced by delamination, as it was reported for pipelines steels in a number of publications [24, 25]. Fracture toughness J0.2 (the value of J-integral corresponding to 0.2 mm crack growth) of steels after operation was also deteriorated (Table 2) [3, 23]. Thus, J0.2 was decreased of 1.6–1.8 times for the 17H1S steel, and of 3.2–5.2 times for the X52 steel due to long-term operation. It was shown for the X60 and X70 steel [13] that, despite of only minor changes in strength and plasticity characteristics due to long-term operation (21 years), resistance to brittle fracture was significantly decreased. Thus, fracture toughness K Ic √ √ decreased from 231 to 149 MPa m and from 294 to 231 MPa m for the X60 and X70 steel, respectively. Consequently, these characteristics of brittle fracture resistance (impact strength and fracture toughness) can be considered as mechanical parameters for evaluation of degradation degree of pipeline steels under operation. However, for high strength steels (API X70 and higher) usage of impact toughness can be limited due to possible increasing fracture energy caused by dissipated damaging and delamination.

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4 Susceptibility of Pipeline Steels to Corrosion Degradation Under Operation Considering susceptibility of pipeline steels to in-service corrosion degradation as reported in previous researches [17, 23], electrochemical behaviour of pipeline steel with different strength (17H1S, X60 and X70 steels) in the as-received state and after long-term operation was investigated. The polarisation curves for the studied steels in initial and post-operated states, determined in NS4 solution simulated soil environment, are presented in Fig. 2. The polarization parameters of the pipeline steels are given in Table 3.

Fig. 2 Polarisation curves for the 17H1S, X60 and X70 pipeline steels in the as-received a and operated, b states in NS4 test solution

Table 3 Electrochemical characteristics of the studied pipeline steels in NS4 solution Pipeline steel

Steel state

Corrosion potential E corr (V)

Corrosion current density icorr (µA/cm2 )

Tafel constant bc (V)

Tafel constant ba (V)

Polarisation resistance Rp , (k cm2 )

17H1S

As-received

−0.683

1.85

−0.090

0.062

8.63

17H1S

Operated 30 years

−0.687

4.20

−0.083

0.058

3.53

X60

As-received

−0.664

1.81

−0.090

0.063

8.90

X60

Operated 25 years

−0.696

3.86

−0.090

0.056

3.89

X70

As-received

−0.518

0.67

−0.089

0.061

23.49

X70

Operated 37 years

−0.642

2.24

−0.088

0.060

6.92

Non-destructive Electrochemical Evaluation of …

37

As it can be seen from Fig. 2, the pipeline steels in both studied states are characterized by active behaviour in NS4 aqueous solution; there is no active–passive transition in the investigated potential range, only active dissolution. Electrochemical behaviour of the 17H1S and X60 steels was identical in both studied steel states— as-received and operated, while that of the X70 steel differed from other investigated steels. Thus, intensity of anodic dissolution of X70 steel is lower than that of the 17H1S and X60 steels (Fig. 2). The diffusion of depolarizer dominated the corrosion process of steels in NS4 solution, as demonstrated by the presence of cathodic limiting diffusive current. Both 17H1S and X60 steels in as-received states were characterized by similar corrosion resistance, and the highest corrosion resistance was typical for high strength X70 pipeline steel (Table 3). Deterioration of electrochemical properties of the post-operated pipeline steels in NS4 test solution in comparison with the as-received steels was revealed. It is caused by in-service degradation under mutual action of corrosion, hydrogenation and working stresses during long-term operation of gas mains. Electrochemical activation of pipeline steels due to in-service degradation was shown as an increase of intensity of cathode and anode processes on the degraded steels. This leads to an increase in corrosion current density, a decrease in polarisation resistance and in shifting corrosion potential values towards more negative ones for the degraded steels compared with the steels in the as-received state (Table 3). Some features of electrochemical behaviour of the high strength X70 pipeline steel compared with other investigated steels were observed. On the one hand, the degraded X70 steel was characterized by higher corrosion resistance in NS4 solution defined by characteristics of corrosion current density and polarization resistance (see Table 3) than both 17H1S and X60 steels after operation. On the other hand, degree of corrosion degradation (decrease in corrosion resistance caused by operation) was the highest for the X70 steel. Thus, polarisation resistance Rp for the 17H1S and X60 steels decreased about 2.3–2.4 times after long-term operation of gas pipelines and at the same time that for the X70 steel—decreased about 3.4 times. This means that despite the highest degree of operational degradation, the X70 steel remained the most corrosion-resistant one between the studied steels. As it can be seen from the tests results, trends in changes in the electrochemical characteristics caused by in-service degradation were similar for all investigated materials. Considering different sensitivity of electrochemical properties of steels to service degradation [23], relative changes in them for the same degradation degree should be compared. It is obvious from the research data (Table 3) that relative changes in corrosion potential and Tafel constant values are insignificant. Nevertheless, changes in corrosion current density icorr and polarisation resistance Rp caused by long-term operation are noticeable. Accordingly, these characteristics are enough sensitive to pipeline steel degradation. They can be used as informative parameters of the steel state changes during long-term operation. The use of polarisation resistance for the evaluation of degradation of steels could be investigated, because of its determination is easy enough in the field.

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Fig. 3 Relative changes in polarisation resistance (Rp deg /Rp in ) for the 17H1S, X52, X60 and X70 pipeline steels caused by long-term operation, measured in NS4 solution and solution simulated aqueous condensate in gas pipelines

Relative changes in polarisation resistance (Rp deg /Rp in ) for the 17H1S, X52, X60 and X70 pipeline steels in the as-received (Rp in ) state and after different time of operation (Rp deg ), measured in NS4 solution and test solution simulated aqueous condensate in gas transit pipelines, are presented in Fig. 3. Degradation of brittle fracture resistance of the studied pipeline steels under operation (Fig. 1; Table 2) is accompanied by a decrease in polarisation resistance (Fig. 3). Deterioration of a number of electrochemical properties of the operated pipeline steels with different strength, especially corrosion current density and polarisation resistance, indicated their corrosion degradation, which was evidently caused by inservice degradation due to mutual effect of corrosion hydrogenating environments and working stresses during operation.

5 Degradation Prediction Method Based on Electrochemical Correlation In order to assess degradation degree of pipeline steel during operation, a method based on electrochemical correlation is proposed. Analyzing in-service degradation phenomenon of gas pipeline steel, it was revealed that both mechanical and electrochemical characteristics were deteriorated. Being brittle fracture resistance characteristic regulated by normative documents (DSTU EN ISO 3183:2017/API 5L, and others [26]), the possibility of nondestructive estimation of impact toughness of pipeline steels based on changes in electrochemical behaviour caused by long-term operation was analysed. A systematic deterioration of impact toughness and polarisation resistance parameters of the X52 and X60 pipeline steels caused by long-term operation was observed (Figs. 1 and 3). The correlation between changes in these parameters for the low-carbon ferrite-pearlite API 5L strength grade X52 pipeline steel is shown in Fig. 4. Using regression analysis, the dependence satisfies the following relation:

Non-destructive Electrochemical Evaluation of …

39

Fig. 4 Correlation between relative changes in impact toughness (KCVdeg /KCVin ) and polarisation resistance (Rp deg /Rp in ) for the low-carbon ferrite-pearlite API 5L strength grade X52 pipeline steels caused by in-service degradation, and prediction of the relation KCVdeg /KCVin

Rp deg KCVdeg = −0.308 + 1.309 · , KCVin Rp in

(3)

where KCVin and KCVdeg —impact toughness of the as-received and operated steel, respectively; Rp in and Rp deg —polarisation resistance of the as-received and operated steel, respectively. The dependence KCVdeg /KCVin —Rp deg /Rp in is the basis of non-destructive electrochemical method for prediction of in-service degradation degree of the low-carbon ferrite-pearlite API 5L strength grade X52 pipeline steels. An acceptable correlation revealed between relative changes in polarisation resistance Rp deg /Rp in and impact toughness KCVdeg /KCVin of API 5L strength grade X52 pipeline steels caused by their in-service degradation (Fig. 4) enables an evaluation of in-bulk material properties changes, namely impact toughness, by measurements of electrochemical characteristics changes. Having initial properties of the material (for example, impact toughness of the as-received pipeline steel according to certificate or impact toughness of the steel of the reserved pipe), its actual properties can be predicted. The prediction method of pipeline steel degradation was verified on damaged and operated pipeline steels.

6 Method for Degradation Evaluation Based on Electrochemical Fracture Surface Analysis A new method for evaluation of in-service degradation degree of long-term operated pipeline steels, based on electrochemical analysis of fracture surface, is developed [21, 22]. The background of the method is reported in detail in [22].

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It was assumed [21] that in-service embrittlement of ferrite-pearlite pipeline steels, which, consequently, caused brittle fracture and decreasing fracture energy, is associated with precipitation of carbide nanoparticles at grain boundaries and defects inside grains during long-term operation. This leads to intergranular cracking of pipeline steels under operation and transgranular cracking of post-operated pipeline steels at impact toughness tests. This mechanism of in-service degradation of pipeline steel implies enrichment of fracture surface by carbon compounds (obviously, carbidetype), and electrochemical characteristics are sensitive to electrochemical microheterogeneity of steel, including different content of carbon/carbides, as it was demonstrated in [21, 22]. Considering dependence of certain electrochemical characteristics, namely corrosion current density and polarization resistance, on surface area, which is difficult to estimate in a case of fracture surface, determination of open-circuit potential of fracture surface of steel is used in the method. A possibility of evaluation of brittle fracture resistance of steel based on changes of potential of fracture surface was analysed. Open-circuit potential of the polished steel surface and that of the fracture surface of specimens made of the ferrite-pearlite API 5L strength grade X52 pipeline steels in the different states (in the as-received one and after 28–30 years of operation) were determined in 0.3% NaCl solution and compared (Fig. 5). A significant difference between open-circuit potentials of the fracture surface (brittle fracture) and polished surface was observed for operated steels. It was explained by increasing content of carbon compounds on the fracture surface due to in-service degradation [22, 23]. Change in open-circuit potential of the fracture surface of the steel caused by operation was revealed to be enough sensitive to in-service degradation of operated pipeline steels. This parameter can be used as an informative parameter for evaluation of current condition of pipeline steel. The correlation between changes in potential of the fracture surface of ferritepearlite API 5L strength grade X52 pipeline steel E fr in /E fr deg and changes in impact toughness KCVdeg /KCVin caused by in-service degradation is shown in Fig. 6. Using regression analysis, the dependence satisfies the following relation: KCVdeg E fr in = 14.2 − 34.3 · + 21.1 · KCVin E fr deg Fig. 5 Values of potential E of the polished surface and E fr of the fracture surface of the specimens made of the ferrite-pearlite API 5L strength grade X52 pipeline steels in the as-received state and after 28–30 years of operation, measured in 0.3% NaCl solution



E fr in E fr deg

2 ,

(4)

Non-destructive Electrochemical Evaluation of …

41

Fig. 6 Correlation between relative changes in impact toughness (KCVdeg /KCVin ) and potential of the fracture surface (E fr in /E fr deg ) for the low-carbon ferrite-pearlite API 5L strength grade X52 pipeline steels caused by in-service degradation, and prediction of the relation KCVdeg /KCVin

where KCVin and KCVdeg —impact toughness of the specimen made of the asreceived and operated steel, respectively; E fr in and E fr deg —potential measured on the fracture surface of the specimen made of the as-received and operated steel, respectively. Consequently, an acceptable correlation revealed between changes in open-circuit potential of fracture surface and impact toughness of pipeline steels caused by longterm operation allows current brittle fracture resistance of operated metal to be estimated. The dependence KCVdeg /KCVin —E fr in /E fr deg is the basis of electrochemical method for estimation of in-service degradation of API 5L X52 strength grade pipeline steels [27]. The developed method, supplementing known methods of non-destructive evaluation, can be used during fracture analysis in order to increase accuracy and reliability of assessment of current mechanical properties of operated steel when there are any difficulties of cutting out samples from pipe for in laboratory testing [22, 23]. With the purpose of evaluating brittle fracture resistance degradation of pipeline steel under operation, electrochemical potential of the steel fracture surface should be determined. Change in impact toughness of operated steel can be determined based on an empirical correlation (Fig. 6), and then current impact toughness value can be predicted, if impact toughness value for as-received steel is known.

7 Non-destructive Evaluation of Pipeline Steel Considering Degradation Stage Based on numerous research results, two stages of in-service degradation of pipeline steels are recognized, as summarized in [3]: deformation ageing and dissipated damaging. These stages are different due to the difference in degradation degree of pipeline steels, since long-term service of pipelines causes changes in metal state, and,

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consequently, in mechanical behaviour of steels being operated under complicated operational conditions. Safe operating pipelines require monitoring actual state of pipeline steels in service using non-destructive testing. The recent trend is quantifying steel degradation by using non-destructive methods based on indentation tests [28–30]. These methods allow to predict, first of all, operational changes in strength characteristics. The method is reliable to assess the metal degradation degree at the stage of deformation aging, when there is an increase in hardness and strength characteristics and a decrease in plasticity and resistance to brittle fracture. However, the use of indentation method can be limited if degradation degree of a tested metal is high, when the second degradation stage associated with dissipated damaging is dominating. At this stage a decrease in plasticity and brittle fracture resistance characteristics can also be accompanied by a decrease in hardness and strength. When it is the case, the developed electrochemical method is proposed to be used additionally to evaluate the degradation degree of steels being operated at the stage of accumulation of dissipated damaging in a metal bulk. The main advantages of the non-destructive electrochemical method are that it enables quantitative evaluation of degradation degree of pipeline steels and prediction of brittle fracture resistance, namely impact toughness. The method is reliable to assess the metal degradation degree at any stage of degradation, including the stage of dissipated damaging.

8 Concluding Remarks Long-term operation of natural gas transmission pipelines leads to in-bulk damage, corrosion degradation and decreased brittle fracture resistance of pipeline steels, increasing the risk of failure. Mechanical and electrochemical properties of the lowcarbon ferrite-pearlite pipeline steels with different strength (API 5L X52, API 5L X60 and API 5L X70 strength grade) were deteriorated due to in-service degradation. Polarization resistance was one of the most sensitive parameters to in-bulk steel degradation among electrochemical properties. The method to predict in-service degradation of pipeline steel based on electrochemical correlation was proposed. The method was verified on ferrite-pearlite API 5L X52 grade pipeline steels. Correlation between relative changes in polarization resistance and impact toughness of steels caused by long-term service was revealed. Impact toughness changes of pipeline steels caused by degradation under operation can be evaluated by measurements of changes in polarisation resistance. Having initial properties of the material, its actual properties can be predicted. The method enables non-destructive in-service assessment of degradation of brittle fracture resistance of pipeline steels. The proposed method is based on electrochemical analysis of fracture surface. Correlation between changes in open-circuit potential of fracture surface and impact

Non-destructive Electrochemical Evaluation of …

43

toughness of API 5L X52 strength grade pipeline steels caused by long-term operation allows current brittle fracture resistance of operated metal to be estimated. The non-destructive electrochemical method enables quantitative evaluation of degradation degree of pipeline steels and prediction of brittle fracture resistance, namely impact toughness, at any stage of metal degradation, including the stage of dissipated damaging. Acknowledgements The research has been supported by the NATO in the Science for Peace and Security Programme under the Project G5055 “Development of Novel Methods for the Prevention of Pipeline Failures with Security Implications”.

References 1. Kiefner, J.F., Rosenfeld, M.J.: The role of pipeline age in pipeline safety. INGAA Foundation final report No. 2012.04. November 8, 2012, https://www.ingaa.org/file.aspx?id=19307. Accessed on 1 Mar 2020 2. Vodenicharov, S.: Degradation of the physical and mechanical properties of pipeline material depending on exploitation term. In: Pluvinage, G., Elwany, M.H. (eds.) NATO Science for Peace and Security Series C: Environmental Security “Safety, Reliability and Risks Associated with Water, Oil and Gas Pipelines,” pp. 299–315. Springer, Dordrecht (2008) 3. Nykyforchyn, H.M., Lunarska, E., Zonta, P.: Degradation of properties of long term exploited main oil and gas pipelines steels and role of environment in this process. In: Bolzon, G., Boukharouba, T., Gabetta, G., Elboujdaini, M., Mellas, M. (eds.), Integrity of Pipelines Transporting Hydrocarbons. NATO Science for Peace and Security Series C: Environmental Security, vol. 1, pp. 59–74. Springer, Dordrecht (2011) 4. Mil’man, Yu.V., Nykyforchyn, H.M., Hrinkevych, K.E., Tsyrul’nyk, O.T., Tkachenko, I.V., Voloshyn, V.A., Mordel, L.V.: Assessment of the in-service degradation of pipeline steel by destructive and nondestructive methods. Mater. Sci. 47(5), 583–589 (2012) 5. Maruschak, P.O., Danyliuk, I.M., Bishchak, R.T., Vuherer, T.: Low temperature impact toughness of the main gas pipeline steel after long-term degradation. Central Eur. J. Eng. 4(4), 408–415 (2014) 6. Meshkov, Y.Y., Shyyan, A.V., Zvirko, O.I.: Evaluation of the in-service degradation of steels of gas pipelines according to the criterion of mechanical stability. Mater. Sci. 50(6), 830–835 (2015) 7. Nykyforchyn, H., Zvirko, O., Tsyrulnyk, O., Kret, N.: Analysis and mechanical properties characterization of operated gas main elbow with hydrogen assisted large-scale delamination. Eng. Fail. Anal. 82, 364–377 (2017) 8. Zvirko, O.I., Kret, N.V., Tsyrulnyk, O.T., Vengrynyuk, T.P.: Influence of textures of pipeline steels after operation on their brittle fracture resistance. Mater. Sci. 54(3), 400–405 (2018) 9. Zvirko, O., Gabetta, G., Tsyrulnyk, O., Kret, N.: Assessment of in-service degradation of gas pipeline steel taking into account susceptibility to stress corrosion cracking. Proc. Struct. Integr. 16, 121–125 (2019) 10. Marushchak, P.O., Kret, N.V., Bishchak, R.T., Kurnat, I.M.: Influence of texture and hydrogenation on the mechanical properties and character of fracture of pipe steel. Mater. Sci. 55(3), 381–385 (2019) 11. Krechkovs’ka, H.V., Tsyrul’nyk, O.T., Student, O.Z.: In-service degradation of mechanical characteristics of pipe steels in gas mains. Strength Mater. 51(3), 406–417 (2019) 12. Dzioba, I.R., Tsyrul’nyk, O.T.: Analysis of the integrity of welded pipes of gas mains by the FITNET procedures. Mater. Sci. 45(6), 817–825 (2009)

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13. Andreikiv, O.E., Hembara, O.V., Tsyrul’nyk, O.T., Nyrkova L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238 (2012) 14. Andreikiv, O.Y., Dolins’ka, I.Y., Shtoiko, I.P., Raiter, O.K., Matviiv, Y.Y.: Evaluation of the residual service life of main pipelines with regard for the action of media and degradation of materials. Mater. Sci. 54(5), 638–646 (2019) 15. Tsyrul’nyk, O.T., Slobodyan, Z.V., Zvirko, O.I., Hredil, M.I., Nykyforchyn, H.M., Gabetta, D.: Influence of operation of Kh52 steel on corrosion processes in a model solution of gas condensate. Mater. Sci. 44(5), 619–629 (2008) 16. Voloshyn, V.A., Zvirko, O.I., Sydor, P.Y.: Influence of the compositions of neutral soil media on the corrosion cracking of pipe steel. Mater. Sci. 50(5), 671–675 (2015) 17. Zvirko, O.I.: Corrosion degradation of pipeline steels with different strength grades. J. Hydrocarbon Power Eng. 4(1), 38–42 (2017a) 18. Zvirko, O.I., Mytsyk, A.B., Tsyrulnyk, O.T., Gabetta, G., Nykyforchyn, H.M.: Corrosion degradation of steel of long-term operated gas pipeline elbow with large-scale delamination. Mater. Sci. 52(6), 861–865 (2017) 19. Zvirko, O.I.: Electrochemical methods for the evaluation of the degradation of structural steels intended for long-term operation. Mater. Sci. 52(4), 588–594 (2017b) 20. Nykyforchyn, H., Zvirko, O., Tsyrulnyk, O.: Non-destructive diagnostics of hydrogen-induced degradation of pipelines steels by electrochemical method. In: Gdoutos, E.E. (ed.) Proceedings of 14th International Conference on Fracture ICF 2017, vol. 1, pp. 596–597. Curran Associates Inc., Red Hook (2017) 21. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O.: Electrochemical fracture analysis of in-service natural gas pipeline steels. Proc. Struct. Integr. 13, 1215–1220 (2018) 22. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O., Krechkovska, H.: Non-destructive evaluation of brittle fracture resistance of operated gas pipeline steel using electrochemical fracture surface analysis. Eng. Fail. Anal. 104, 617–625 (2019) 23. Zvirko, O., Nykyforchyn, H., Tsyrulnyk, O.: Evaluation of impact toughness of gas pipeline steels under operation using electrochemical method. Proc. Struct. Integr. 22, 299–304 (2019) 24. Joo, M.S., Suh, D.W., Bhadeshia, H.K.D.H.: Mechanical anisotropy in steels for pipelines. ISIJ Int. 53, 1305–1314 (2013) 25. Yang, X.L., Xu, Y.B., Tan, X.D., Wu, D.: Influences of crystallography and delamination on anisotropy of Charpy impact toughness in API X100 pipeline steel. Mater. Sci. Eng. A 607(23), 53–62 (2014) 26. DSTU EN ISO 3183:2017 (ISO 3183:2012, IDT): Petroleum and natural gas industries. Steel pipe for pipeline transportation systems, Geneva/American Petroleum Institute (API), API 5L, 2013. Specifications for line pipe, 45th edition, Washington DC (2012) 27. Zvirko, O.I., Nykyforchyn, H.M., Tsyrulnyk, O.T., Krechkovska, H.V., Hredil, M.I.: Electrochemical method of operational degradation diagnostics of mechanical properties of structural steels. UA Patent 127309. Published 07/25/2018 (In Ukrainian) 28. Bolzon, G., Zvirko, O.: An indentation based investigation on the characteristics of artificially aged pipeline steels. Proc. Struct. Integr. 3, 172–175 (2017) 29. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Micro and macro mechanical analysis of gas pipeline steels. Proc. Struct. Integr. 5, 627–632 (2017) 30. Bolzon, G., Rivolta, B., Nykyforchyn, H., Zvirko, O.: Mechanical analysis at different scales of gas pipelines. Eng. Fail. Anal. 90, 434–439 (2018)

Structural and Fractographic Features of Gas Pipeline Steel Degradation Halyna Krechkovska, Myroslava Hredil, and Oleksandra Student

Abstract Structural and fractographic features of degradation are analyzed for pipe steels after their operation on main gas pipelines. The structural feature of steel degradation is damaging along the boundaries between pearlite and ferrite grains manifested by more intensive etching the boundaries with extraction of cementite particles from the matrix. The most obvious effect of degradation is revealed for the steel 17H1S, and the least one for the steel X70. It is concerned with steel texture peculiarities, namely, different sizes (thickness and length) of strips of pearlite, and with dispersion of its components (i.e. cementite lamellae) which control to a large extent hydrogen permeability in a pipe wall and its trapping at the ferrite–pearlite boundaries. Structural peculiarities of steel degradation revealed themselves clearer fractographically in a form of delaminations at the fracture surfaces of the operated steels. The hydrogen absorbed by metal during pipe operation and concentrated at the structural defects along the boundaries between interlayers of ferrite and pearlite grains led to the occurrence of these delaminations and their extension. Therefore, these delaminations are considered as the fractographic features of embrittlement for the operated steels. The relationship between mechanical properties of pipeline steels and metallographic and fractographic parameters is obtained. The critical state of degraded steels is substantiated by the change of the crucial element of embrittlement on the fracture surfaces from delaminations (in the subctitical state) to cleavage (in the overcritical one). Keywords Gas pipelines · Steel degradation · Structural and fractographic features · Delamination · Cleavage · Impact toughness

H. Krechkovska (B) · M. Hredil · O. Student Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_4

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1 Introduction An increase in distances of gas transmission implies the substantiation of the pipeline operating pressure over 9.8 MPa, which is impossible without increasing the pipe wall thickness. In particular, pipes of strength grade X70 having the wall thickness of 15.7–18.7 mm are replaced by pipes with a thickness of more than 21.6 mm, while for underwater pipelines the thickness could be up to 40 mm (taking into account the water pressure). However, choosing the pipe wall thickness, it is also necessary to take into account the degradation of pipe steels, caused by the thermodynamically nonequilibrium structural state of these steels in as received state and the tendency to reach the equilibrium state during long-term operation. Such transformations are usually associated with the diffusion of carbon and alloying elements in steels at distances comparable to the grain size. This process takes a prolonged time, especially under climatic temperatures. The consequences of such transformations have been convincingly proved in the case operation of heat-resistant steels under elevated temperature (up to 570 °C), where the diffusion coefficients of carbide-forming elements are significantly higher. Thus, the formation and coagulation of carbides along grain boundaries has been confirmed on low-alloy heat-resistant steels and their welded joints after more than 20 years of operation on the main steam pipelines of thermal power plant TPP [1, 2]. The decohesion of carbides from the matrix at the grain boundaries weakens the cohesion between adjacent grains and causes premature intergranular cracking due to creep. Thermal stresses occurring in the pipe wall due to shutdowns of TPP units intensify this process [3, 4]. The intensification of structural transformations in such steels is also confirmed by modeling the effects of shutdowns in laboratory conditions by thermal cycling of specimens in hydrogen [5]. Such structural changes in operated heat-resistant steels did not significantly affect their tensile strength and plasticity. However, their impact toughness, fracture toughness and threshold values of fatigue crack growth resistance are more sensitive to their degradation [6–12]. Considering low-alloy steels (in particular, steels used on main gas pipelines), it is noticeable that there is no undeniable evidence of carbide precipitation along grain boundaries even after their long-term operation (more than 30 years) at climatic temperatures. This is explained by the low mobility of carbide-forming elements under such conditions. However, some researchers suggested [13] that formation of very small particles of cementite at the grain boundaries of pipe steels is possible under their long-term operation (for decades) under climatic conditions. As a confirmation, some pictures were presented [14]. The mechanical testing of the operated steels showed a rather large data scattering and a slight deviation of the standard mechanical characteristics under tension from the regulated values for pipe steels [15, 16]. Like in the case of high-temperature operation, the sensitivity of impact toughness to degradation is also significantly higher than that the tensile characteristics [17, 18]. Thus, the aim of the present research is an evaluation of structural and fractographic features of pipe steel degradation after their long-term operation on the main

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gas pipelines, and estimation of the influence of the structural state on the mechanical properties of pipeline steels with different strength grade.

2 Materials and Methods Gas pipeline steels of the different strength (steel 17H1S as a prototype of API X52, and also steels X60 and X70) in as-received state and after their long-term operation (30, 25 and 37 years respectively) were studied. The mechanical characteristics of steels were determined under tensile tests in air with strain rate of 3.3 × 10–3 s−1 and in NS4 solution (composition, g/l: KCl 0.122; NaHCO3 0.483; CaCl2 0.093; MgSO4 0.131) with strain rate of 1.7 × 10–7 s−1 using smooth longitudinal specimens with a diameter of 5 mm, and the testing machine UME–10 T. The surface of the working part of the specimens was polished before the tests to eliminate the influence of stress concentrators from machining and thereby reduce the scatter of the obtained data. Impact tests were carried out using the IO-5003 installation. Charpy specimens with a V-shape stress concentrator were cut in a longitudinal direction (relative to the pipe generatrix) from spare pipes and from the pipes after operation. Concentrators in the specimens were cut along the pipe wall thickness. Thus, the fracture surface in the specimens was oriented perpendicularly to the pipe axis and located in their radial cross section ensuring the fracture path in the tangential direction. The chemical composition of the investigated steels was evaluated using of the spark optical atomic-emission spectrometer SPECTROMAX LMF 0.5. The metallography and fractography investigations were performed by optical (Neophot21) and scanning electron (EVO-40XVP) microscopes. Quantification of revealed fractography features of steel degradation was done using software elaborated in Karpenko Institute [19] for the computer analysis of halftone images of fracture surfaces by automatic recognition of the objects of research interest with following estimation of their geometrical parameters.

3 Results and Discussion The chemical composition of the investigated steels in the as-received state and after their long-term operation on the pipelines is presented in Table 1. The analyzed steels have typical composition for pipes of given purposes. Content of presented elements in steels X60 and X70 is almost the same in as-received state and after operation whereas the steel 17H1S in the as-received state has lower carbon content and somewhat higher amount of other elements (twice the silicon content and almost an order of magnitude higher sulfur and phosphorus content).

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Table 1 Chemical composition of the investigated steels, mass (%) Steel code

Metal state

X70

As-received After operation

X60

As-received

17H1S

As-received

After operation After operation

Service time (years)

C

Si

Mn

Cr

S

P

0

0.108

0.26

1.42

0.016

0.004

0.0005

37

0.116

0.34

1.62

0.022

0.003

0.0009

0

0.111

0.24

1.49

0.021

0.007

0.0037

25

0.118

0.41

1.75

0.044

0.004

0.0050

0

0.140

0.99

1.54

0.067

0.029

0.0080

30

0.176

0.49

1.28

0.028

0.004

0.0005

36

0.168

0.44

1.21

0.03

0.004

0.0004

3.1 Mechanical Properties Under Tensile Testing The characteristics of strength (ultimate strength σUTS and yield strength σYS ) and plasticity (elongation and RA) of all investigated steels in the as-received state differed insignificantly (Fig. 1). However, a clear tendency to raising the strength with a respective decrease of plasticity is traced in the following order: 17H1S → X60 → X70. The only exception is RA obtained for the steel X60. As depicted in Fig. 2, strength (σUTS and σYS ) of the tested steels is somewhat higher after operation, and plasticity (elongation and RA) for the steels 17H1S and X60 is lower, and in the case of the steel X70 even slightly higher, however these changes are comparable to data scattering. The maximum hardening effect was observed for the steel 17H1S (σ UTS value is increased by 11%) (Fig. 2c). This could be a result of a slightly higher carbon content (compared to the steel in the initial state, Table 1), which usually determines the strength of low alloy pipe steels. However, strength of the X60 steel is also higher after operation despite almost the same carbon content in the operated and non-operated variant of steel. Therefore,

Fig. 1 a Strength (I—σUTS , II—σYS ) and b plasticity (I—Elongation; II—RA) for the steels X70 (1), X60 (2) ta 17H1S (3) in the as-received state

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Fig. 2 Relative changes λ in strength (σUTS and σYS ), plasticity (elongation and RA) and impact toughness KCV of the tested steels X70 (a), X60 (b) and 17H1S (c, d), after their operation during 37 years (a), 25 (b), 30 (c) and 36 years (d)

the steel degradation can also be manifested by strengthening of steel. It is natural that plasticity of the steels hardened due to operation is decreased. In particular, for 17H1S steels operated for 30 years and 36 years, elongation values are decreased by 22% and 19% respectively, and reduction in area by 18% and 17% respectively. It could be noted as a peculiarity, that both the strengthening and the plasticity loss of the steel after longer operation are somewhat smaller than those of the steel with shorter service time. This was concerned with a slightly lower carbon content of longer operated steel (Table 1). With respect to X70 steel, a little hardening effect after operation practically did not worsen its plasticity characteristics (their change did not go beyond the data scattering and did not exceed 3%). Therefore, despite the maximum duration (37 years) of service of the X70 steel on the main gas pipeline, its plasticity has not practically changed. At the same time, the plasticity of 17H1S steel after 30 and 36 years of operation and X60 after 25 years is significantly decreased. It is evident that the degradation peculiarities of pipe steels reflected by a change of their mechanical characteristics should be taken into account in strength calculations of other operated sections of pipelines.

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3.2 Brittle Fracture Resistance of Pipeline Steels Impact toughness values for the steels X70, X60 and 17H1S in the as-received state are 2.77 MJ/m2 , 3.42 MJ/m2 and 2.63 MJ/m2 respectively, and this parameter is decreased significantly after long-term operation of these steels (Fig. 2). The minimum decrease in impact toughness (by 11%) was observed for the steel X70. In X60 steel, KCV is decreased by 23% relative to the corresponding value for the spare pipe. However, the changes for 17H1S were the most essential; namely, impact toughness of this steel is decreased by 49% and 56% after 30 and 36 years of service, respectively (Figs. 2c, d). It has been shown earlier [20] that after 51 years of operation, the reduction in KCV of this steel reached 87%. It was suggested that such a low resistance to brittle fracture of operated steels is a result of the accumulation of defects in the metal during so long period of operation.

3.3 Structural Peculiarities of Degradation for Pipeline Steels Structural features which could be responsible for such essential change in steel’s mechanical characteristics, were analyzed for the steel 17H1S as the brightest example [21]. Considering the structure of this steel in the as-received state and after 30-year operation, a pronounced texture consisted of the layers of ferrite and pearlitic grains was revealed in both cases. The texture was found in the axial (Fig. 3a, c) and in the radial (Fig. 3b, d) cross sections of the pipe. It was noted that perlite and ferrite grains generally retained their polygonal form. Grain size distribution was irregular, which was clearly visible in the radial cross section of a pipe. In general, the defining elements of the structure for both analyzed steel states were the following. Thinner strips of perlite (up to 12 μm) were interspersed with wider bands of ferrite (up to 31 μm). Perlite strips in the axial section of the steel pipe in the initial state were almost continuous with a length up to 2 mm (Fig. 3a). In addition, long (100– 200 μm) chains of thin (up to 1 μm) non-metallic inclusions (such as manganese sulfides) were observed in this plane. They are mostly located along the ferrite layers, somewhere crossing the ferrite grains. At the same time, in the radial cross section of the pipes, the continuity of the perlite strips was often interrupted by separate ferrite grains. Therefore, the length of continuous perlite strips in this pipe section did not exceed 150 μm (Fig. 3b). Two peculiarities of degradation of 17H1S steel at the microstructural level were identified (Fig. 3c, d). On the one hand, an insufficient clarity of some part of the grain boundaries separating adjacent bands of perlite and ferrite was observed. The loss of their clarity can be a consequence of their scattering. From the other hand, some grain boundaries became remarkably clear, which indicated their especial susceptibility to etching. Besides, the enhanced susceptibility to etching was more pronounced in the axial direction of the pipe (Fig. 3c), whereas in the radial direction the interphase boundaries between ferrite and pearlite were etched selectively and did not spread on

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Fig. 3 Microstructure of the steel 17H1S in the initial state (a, b) and after 30 years of operation on the main pipeline (c, d) in the axial (a, c) and radial (b, d) cross sections of the pipes at a distance of 3 mm from their external surface

the whole length of continuous strips (Fig. 3d). This nonuniformity in pearlite etching in the operated steel is concerned with a different stage of its damaging under a longterm influence of service factors, namely, operational loads, and steel hydrogenation which cannot be avoided. It has been experimentally shown that steels’ hydrogenation does take place in the main gas pipelines during their long-term operation [22]. Particularly, the hydrogen content in the pipe wall of emergency pipes on the sections of fractured gas pipelines reached 0.045–0.06 at.%, which significantly exceeded the average hydrogen content in pipes in the as-received state (0.015 at.%). Somewhat less amount of hydrogen (up to 0.032 at.%) was revealed in other emergency pipes operated for 20–34 years on gas mains, whereas the hydrogen content in spare pipes did not exceed 0.014 at.%, and in pipes of current production—0.013 at.% [23]. Meanwhile, the problem of hydrogen effect which absorbed inside the damages in operated steels located along their ferrite-pearlite texture is still controversial. It is known that hydrogen diffusion coefficient in the steel AISI 4130 with randomly oriented ferrite and pearlite grains is higher than that measured in the direction across the ferrite-pearlite texture [23]. This statement is in agreement with the research [24] where it was shown that the hydrogen diffusion coefficient is lower in the transversal direction relative to ferrite-pearlite texture than that along it. In the latter case, hydrogen can easily diffuse along the ferrite bands. Hydrogen permeability was also higher along the striped structure than across it. Studies of pure Fe–C alloys

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with ferrite-pearlite structure have shown that the boundaries between ferrite and pearlite or between adjacent pearlite grains are effective traps for hydrogen [25]. Boundaries between ferrite and cementite lamellae inside pearlite weakly absorb hydrogen; they serve as a barrier for hydrogen diffusion through pearlite colonies. However, these results contradict direct visualization of sites of hydrogen release from ferrite-pearlitic steels. It was obtained using the high sensitive “hydrogen microprint” method, which leaded to the conclusion that there was no preference for hydrogen diffusion just along ferrite grains [26]. Indeed, even in the cross section of the perlite grains, the hydrogen located within ferrite lamellae, which is consistent with the significantly lower diffusion coefficient of hydrogen in the cementite in comparison with the ferrite (1.84 × 10–11 and 7.1 × 10–10 m2 s−1 respectively) [27]. Above mentioned structural features (first of all damage along the bands of ferrite and pearlite) are most typical for the steel 17H1S, and to the least extent for the steel X70. This is in principle consistent with the results of mechanical tests according to which X70 steel (despite its longest operation time among the considered steels, 37 years) is the least susceptible to degradation by all characteristics. The thickness of the perlite strips revealed in the structure of this steel under a higher resolution (using SEM) was very small (from 1 to 5 μm, see Fig. 4c, d). Even at a high magnification, most often it was difficult to identify the individual lamellae in ferrite-cementite mixture inside the pearlite colonies in the structure of X70 steel. It was suggested that such grinding of perlite constituents minimized the hydrogen trapping inside the pipe wall and, accordingly, prevented damage accumulation along texture interlayers. In any case, the best mechanical properties of this steel, even after the longest operation time, can be logically associated with the shredding of both layers of perlite and its constituents.

3.4 Fractographic Features of Operational Degradation of Pipe Steels Signs of the steel degradation revealed under SCC tests. The described structural features of the operational degradation of gas pipeline steels were manifested clearer on the fracture surfaces of the specimens tested by SSRT in NS4 solution simulating soil environment [28]. In particular, at the fracture surfaces of the operated steel, delaminations appeared clearer than after the tests in air, both at macro and micro levels (Fig. 5). After testing in air, the delaminations are surrounded by a ductile relief consisted of dimples (Fig. 5a), whereas in the case of the testing in the environment, the delaminations became origins of brittle fracture in the form of transgranular cleavage (Fig. 5b). This trend maintained not only near the external surface of the specimen contacted with the corrosive environment, but also in the center of its cross section (Fig. 5c). In addition, intergranular fracture elements initiated from some delaminations were observed close to the lateral surfaces of the specimens. Their occurence was considered as a direct manifestation of the corrosive medium

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Fig. 4 Microstructure of X70 steel in the axial direction for the as received state (a, c) and after 37 years of operation (b, d)

action (Fig. 5d). Indeed, the solution penetrated during SSRT along the delaminations (similar as along capillaries) into the crack tip and ensured corrosion cracking along the grain boundaries. This allowed suggesting that delaminations along the boundaries between adjacent layers of ferrite and perlite were already present in the structure of the operated steel even before the tensile testing of specimens. These fractographic features were considered as a direct confirmation of the influence of hydrogen accumulated in pipes during their long term operation, on the weakening of cohesion between different grains (especially between adjacent layers of ferrite and perlite in the steel texture). It should be also noted that under the same testing conditions of non-operated steel, such fractographic evidence of steel degradation were not traced at all. Signs of degradation found after Charpy testing. Basing on the analysis of mechanical properties, a conclusion can be drawn that the impact toughness of all three steels is the most sensitive characteristic to the change in the metal state caused by their operation. Therefore, it seems evident to find out fractographical signs of steel degradation on the fracture surfaces of impact specimens. Fractographic analysis of all the tested steels in the initial state revealed the dominance of a typical

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Fig. 5 Facture surfaces of the operated 17H1S steel after SSRT in air (a) and NS4 solution (b–d)

ductile fracture relief from the practically equilibrium voids formed as a result of elongation of the partitions separating adjacent voids from each other up to their fracture (Fig. 6). Analyzing the fracture surfaces of the operated steels, it was noted that besides the typical ductile relief formed by microvoid coalescence, similar as in their initial state, some fragments were identified which were considered to be signs of steel embrittlement due to degradation. First of all, these were numerous and various in size delaminations with smooth unstructured relief, as a rule, with chains of small pores at their bottom (Fig. 6a–c). Delaminations were clearly visible at the background of ductile fracture relief. Moreover, the coalescence of the microvoids was observed preferentially in the areas of fracture surface which served as partitions between adjacent delaminations. In addition to delaminations, some rounded fragments of cleavage were found against the background of the ductile relief on fracture features of the steel 17H1S operated for 51 years [20]. Both mentioned fractographic elements of embrittlement were considered as features of operational degradation of pipe steels. Moreover, their appearance was a proof that the hydrogen absorbed by the metal during its operation and accumulated in defects along the interfaces between ferrite and pearlite layers of their texture, contributed to the development of delaminations, and also facilitated the nucleation of brittle transgranular cleavage in the critically degraded steel (Fig. 6d). Similar fractographic features of embrittlement have been found for other ferrite-pearlite pipe steels after their operation [29, 30].

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Fig. 6 Fracture surfaces of the Charpy specimens of the steels X70 (a), X60 (b) and 17H1S (c, d) after their operation during 37 years (a), 25 (b), 30 (c) and 51 years (d)

Using computational approaches to process and quantify fragments of fractographic images by the elaborated software [19], it was possible to determine the area of brittle fracture elements (delamination and cleavage) S cr on the unit area of fracture surfaces of impact specimens S. The ratio S cr /S = α was accepted as a fractographic indicator of the steels degradation. Relationship between mechanical and fractografic indicators of the technical state of operated steels. After analyzing the mechanical characteristics used for the assessment of the current state of the tested steels from the point of their sensitivity to operational degradation, it was established that the impact toughness is the most sensitive to operational changes in pipeline steels. For instance, the loss of brittle fracture resistance relative to the initial value (the ratio KCV op /KCV in ) of 17H1S steel after 51 years of operation exceeded 80%. At the same time, elongation, being the most sensitive parameter to the in-service changes of steel state under the tensile testing, decreased by as much as 25%. Taking this into account, a correlation was built between the ratio KCV op /KCV in for the analyzed steels and corresponding values of the introduced fractographic parameter α (Fig. 7). The obtained dependency allows

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Fig. 7 Ranking of the considered mechanical properties by their sensitivity to operational degradation (a) and correlative dependence between the loss in brittle fracture resistance KCV op /KCV in and the part of brittle fracture elements at the unit area of fracture surfaces of Charpy specimens S cr /S (b) for the steels 17H1S, X60 and X70 after their long term operation on gas mains

estimating the actual state of operated steels used, depending on their degradation stage. This approach has been earlier proposed for long term operated carbon steels from the profile metal rolling, for which the critical value of KCV op /KCV in was additionally substantiated [31]. According to this approach, the critical state for operated steels was reached when brittle transgranular cleavage began to appear on the fracture surfaces of impact specimens replacing delaminations. In this case the loss of brittle fracture resistance has reached a critical level KCV op /KCV in = 0.23. As a consequence, further operation of critically degraded steels will inevitably lead to the brittle fracture of structural members by cleavage, typical for a spontaneous fracture. Since the regularities of changing the standard mechanical properties due to operational degradation are similar for the analyzed low-alloy steels to those obtained on carbon steels, we suggested that the critical value of loss of brittle fracture resistance obtained for carbon steels can be used to estimate the current state of pipeline steels. It is possible to estimate in this way how close the current steel state is to the critical one. According to the obtained data, most of the analyzed steels are above the critical value KCV op /KCV in = 0.23 [31]. It is obvious that the steel X70 has the highest serviceability even after 37 years of operation. The loss of resistance to brittle fracture of X60 steel exceeded 20%. And the worst prospects for further service has 17H1S steel after 51 years of operation, for which KCV op /KCV in = 0.17. Basing on the above mentioned approach, it should be stated that this steel have already reached the critical limit. This was also confirmed by the fractographic studies, which revealed more than 20% of brittle fracture elements on the fracture surfaces of this steel. Their presence is a key indicator of especial susceptibility of structural elements made of this steel to uncontrolled fracture.

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4 Conclusions Structural degradation of the main gas pipeline steels was manifested by the tendency to selective etching of separate boundaries between adjacent ferrite and perlite layers, caused by the development of microdamages in the direction of the texture. Damaging at the interface boundaries is the result of different hydrogen permeability in ferrite and perlite. Hydrogen absorbed by steels during operation, accumulated along the boundaries of structurally dissimilar layers, weakened the cohesion between them and contributed to the formation of defects there. Structural features of the degradation were the clearest in 17H1S steel and the least pronounced in X70 steel. They were confirmed fractographically by distinct signs of the weakening of cohesion between ferrite and perlite bands on the fracture surfaces. Hydrogen, accumulated along the boundaries between ferritic and pearlite layers, promoted the occurrence of delaminations and cleavage fragments as an evidence of steel embrittlement due to operational degradation. The area of these fragments is proposed as a fractographic indicator in the assessment of the current state of operated pipeline steels. A correlative dependency between the loss of resistance to brittle fracture (as the most sensitive indicator of operational degradation) and the proposed fractographic indicator was built for the analyzed steels. Substantiation of the critical state of degraded steels was proposed. The change of the main brittle elements on the fracture surfaces from delaminations against the background of ductile relief with typical dimples to brittle transgranular cleavage was used as a criterion. Basing on the proposed approach to the assessment of the current state of operated steels, it was shown that X70 steel has the highest reserve of serviceability despite its 37-year operation. Whereas 17H1S steel operated for 51 years has reached the critical state, therefore, the pipe sections made of this steel can be easily ruptured under any overload during operation. Acknowledgements This research has been supported by the NATO in the Science for Peace and Security Programme under the Project G5055.

References 1. Romaniv, O.M., Nykyforchyn, H.M., Dzyuba, I.R., Student, O.Z., Lonyuk, B.P.: Effect of damage in service of 12Kh1MF steam-pipe steel on its crack resistance characteristics. Mater. Sci. 34(1), 110–114 (1998) 2. Nykyforchyn, H.M. Student, O.Z., Dzioba, I.R. Stepanyuk, S.M. Markov, A.D., Onyshchak, Y.D.: Degradation of welded joints of steam pipelines of thermal electric power plants in hydrogenating media. Mater. Sci. 40(6), 836–843 (2004) 3. Nykyforchyn, H.M., Student, O.Z., Krechkovs’ka, H.V., Markov, A.D.: Evaluation of the influence of shutdowns of a technological process on changes in the in-service state of the metal of main steam pipelines of thermal power plants. Mater. Sci. 46(2), 177–189 (2010)

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24. Lee, H.L., Chan, S.L.I.: Hydrogen embrittlement of AISI 4130 steel with an alternate ferrite/pearlite banded structure. Mater. Sci. Eng. A 142(2), 193–201 (1991) 25. Chan, S.L.I., Charles, J.A.: Effect of carbon content on hydrogen occlusivity and embrittlement of ferrite–pearlite steels. J. Mater. Sci. Technol. 2, 956–962 (1986) 26. Ichitani, K., Kanno, M.: Visualization of hydrogen diffusion in steels by high sensitivity hydrogen microprint technique. Sci. Technol. Adv. Mater. 4, 545–551 (2003) 27. Islam, M.M., Zou, C., Van Duin, A.C.T., Raman, S.: Interactions of hydrogen with the iron and iron carbide interfaces: a ReaxFF molecular dynamics study. Phys. Chem. Chem. Phys. 18(2), 761–771 (2016) 28. Nykyforchyn, H., Krechkovska, H., Student, O., Zvirko, O.: Feature of stress corrosion cracking of degraded gas pipeline steels. Proc. Struct. Integr. 16, 153–160 (2019) 29. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O., Krechkovska, H.: Non-destructive evaluation of brittle fracture resistance of operated gas pipeline steel using electrochemical fracture surface analysis. Eng. Fail. Anal. 104, 617–625 (2019) 30. Kharchenko, E.V., Student, O.Z., Chumalo, H.V.: Influence of the degradation of 17G1S steel on its properties after operation in the gas main. Mater. Sci. 53(2), 207–215 (2017) 31. Student, O.Z., Krechkovs’ka, H.V., Nykyforchyn, H.M., Kurnat, I.M.: Fractographic criterion of attainment of the critical technical state by carbon steels. Mater. Sci. 55(2), 160–167 (2019)

Determination of the Residual Lifetime of Gas Pipeline with Surface Crack Under Internal Pressure and Soil Corrosion Ivan Shtoyko, Jesus Toribio, Viktor Kharin, and Myroslava Hredil

Abstract The model describing the corrosion-mechanical fracture of the underground gas pipeline with semi-elliptical external surface crack is developed taking into account the intensification of crack growth in the pipe steel 17H1S by diffusible hydrogen. The model is grounded on the energy approach to fracture combined with the hydrogen accelerated soil corrosion cracking mechanism. The formula for the soil corrosion rate is derived as the sum of two components: the rate of regular soil corrosion due to contact of steel with the soil, and the term characterizing its acceleration by hydrogen. Corresponding mathematical model (differential equation with initial and final conditions) is built up to determine the residual lifetime of a pipe of gas pipeline subjected to hydrogenation from the transported gas, soil corrosion, long term sustained and transient loadings caused, respectively, by gas pressure in the pipe and by start/stop valve operations. As a result of model implementation, the pipe residual lifetimes are evaluated considering pipe hydrogenation from the inner surface, soil corrosion at the outer surface as well as transient loading. From the analysis of results, it is concluded that pipe wall hydrogenation, as well as transient loading, lead to significant acceleration of corrosion-mechanical crack growth in the pipe, and thus, reduce its residual lifetime. Keywords Gas pipeline · Semi-elliptical crack · Soil corrosion · Non-stationary loading · Residual lifetime

I. Shtoyko (B) · M. Hredil Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] J. Toribio · V. Kharin Fracture & Structural Integrity Research Group, University of Salamanca, Zamora, Spain © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_5

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1 Introduction Rupture inspections of long-term operating main gas pipelines show that the stress corrosion cracking (SCC) is one of the major causes of their integrity loss [1]. Cracks usually initiate at the pipe outer surface due to soil corrosion in places where protecting coatings are damaged [2, 3]. The soil environment is often considered not only corrosive, but also hydrogenating [1, 4, 5]. Besides, recent researches pointed out the hydrogenating capability of transported hydrocarbons [6–8], too. Therefore, the pipeline serviceability can also be reduced by the crack growth under hydrogenation, when the metal at the pipe inner surface absorbs hydrogen in the course of long-lasting operation. If hydrogen absorbed by metal at the pipe inner surface promotes the crack propagation, two cases could be considered: (i) the crack propagation from the pipe inner surface into the wall; (ii) the crack growth from the pipe outer surface, when hydrogen penetrates from the pipe inner surface through its wall towards the crack. It should be noted that fracture kinetics in these cases depends on the operational degradation of steel that reduces its corrosion resistance [6], as well as the brittle fracture resistance [9–12], and facilitates stress corrosion cracking [13–15] and corrosion fatigue [2, 3, 16]. An important aspect of the assessment of the structural integrity of pipelines consists in the modelling of corrosion crack growth in metal basing on fracture mechanics approaches considering the above mentioned factors, and prediction of the residual lifetime of pipes with crack-like defects. Indeed, it has been shown [17–19] for the case of SCC in the pipeline steel X52, that its 30-year operation significantly reduces the residual lifetime of pipes with surface semi-elliptical cracks.

2 Experimental Substantiation of the Importance of Hydrogen Effect on Metal in the Modelling of Fatigue Crack Growth in Pipeline Steels As it has been mentioned, pipeline fractures initiate mainly from the pipe outer surfaces due to aggressive action of the soil environment. However, the hydrogenation at the inner surface of the pipe from the transported hydrocarbons should also be taken into account. Hydrogen absorbed there by metal can diffuse towards the opposite surface, where the corrosion-induced crack arises, and alter the growth rate of this crack. To simulate this situation experimentally, a special technique to assess the influence of hydrogen on fatigue crack growth in the pipeline steel 17H1S, which is similar to X52 steel, was developed [20]. It is as follows. After the determination of the constant fatigue crack growth rate in a specimen according to the standard procedure, cyclic loading is interrupted and cathodic polarization at the current density of 5 mA/cm2 is applied during 24 h to the specimen in a corrosion chamber equipped with an auxiliary platinum electrode. The solution NS4, which is often used for simulation of soil environment, is taken as electrolyte. Its composition is as follows

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Fig. 1 Scheme of the fatigue testing and hydrogen charging: 1 specimen; 2 grips; 3 Pt wire; 4 electrochemical chamber; 5 power supply

(g/l): KCl—0.122, NaHCO3 —0.483, MgSO4 —0.131, CaCl2 —0.093. A moderate hydrogen charging level is chosen basing on the previous experience. This ensures sufficient hydrogenation of the steel, but does not induce new defects that could arise in the steel under intensive hydrogen uptake. After hydrogen charging, fatigue crack growth testing is continued to establish hydrogen effect on mechanical behaviour of the steel. The level of electrolyte in the chamber is 1 mm below the crack tip, which avoids direct contact of the crack with the hydrogen source (Fig. 1). Consequently, hydrogen can influence the crack growth only due to its diffusion towards the crack tip. The experiment simulates service conditions of gas pipelines, where hydrogen diffused through the pipe wall to the external surface affects the stress corrosion cracking initiated at the pipe external surface. It was found that hydrogen absorbed by metal under described testing conditions caused a leap of the crack growth rate V in the Paris region of the fatigue crack growth diagram evidencing detrimental effect of hydrogen on fatigue properties of the 17H1S steel (Fig. 2). The observed “plateau” on the crack growth diagram is typical for SCC [21] and indicates the realization of the static fracture mechanism under cyclic loading, namely, hydrogen-assisted cracking in the considered case. However, it does not imply the insignificance of cyclic loading in the fracture process, which at least should produce the crack sharpening, and increase the stress concentration at the crack tip. Fig. 2 Hydrogenation effect on fatigue crack growth rate V as the function of stress intensity factor range K in 17H1S steel in NS4 solution (red and blue points represent, respectively, the crack growth rates with and without steel hydrogenation)

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3 Estimation of the Residual Lifetime of the Pipe Subjected to Combined Action of Soil Corrosion and Hydrogenation Under Sustained Load The pipe subjected to soil corrosion and filled with hydrogen-containing environment is considered (Fig. 3). The semi-elliptical surface crack with initial semi axes a0 , b0 , where b0 is the ellipse semi axis in the direction of pipe wall thickness h, is located in a region subjected to corrosion, and this crack propagates through the pipe wall leading to the pipe depressurisation. The objective is to determine the pipe residual lifetime, i.e. the time t = t∗ when the decompression occurs, taking into account the effect of hydrogenation on corrosion-mechanical fracture. Corresponding mathematical model and the calculation results are as follows. The crack propagation under the combined action of loading and hydrogenating environment is considered as a continual alternation of two interrelated phases: the protracted periods of electrochemical interactions and the jump-like crack advances. Each electrochemical phase lasts until the time t∗ when the hydrogen concentration C H in the fracture zone attains the critical value dependent on the imposed stress level. At this instant t = t∗ , the crack advances instantaneously with an increment equal to the length of the zone where the hydrogen concentration exceeds the critical value. The crack growth rate VscH can be defined then as follows [22]: VscH ≈ Vsc + M(xμ)−1 γ D

∂C H , ∂h

(1)

where V cs is the experimentally determined rate of stress corrosion crack propagation under sustained load [23], M is the metal atomic mass, x is its oxidation level, μ is the metal density, D is the hydrogen diffusion coefficient in metal, γ is the coefficient that relates physical dimensions of the current density and the hydrogen flux, and C H = C H (h, t) is the hydrogen concentration distribution along the pipe wall thickness h in time t [22]. It is also assumed that the diagram of fatigue crack growth in the pipe steel under the action of environment has rather long plateau where the crack propagation rate keeps constant [23]. The pipe durability at the crack propagation stage, which depends on the initial crack depth b0 , can be determined then by the next ratio: t∗ = (h − b0 )/ Vsc . Fig. 3 Scheme of the pipe with external surface crack under the action of soil environment and gas pressure p

(2)

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The calculations for the pipe made of the 17H1S steel were performed using the following parameters: the pipe external diameter 2r = 1440 mm, the pipe wall thickness h = 18.7 mm, the gas pressure in the pipe p = 7 MPa, the steel Young modulus E = 200 GPa and its tensile yield strength σ 0 = 470 MPa. The hydrogen redistribution along the pipe thickness, which is produced by its diffusion from the pipe inner surface towards the outer one, was calculated depending on the hydrogen gas pressure pH that controls the hydrogen concentration C at √ the entry surface according to the Sieverts law C = K S p H [22], where K S is the hydrogen solubility in metal. Unstressed and stressed material conditions were considered taking into account the stress dependence of hydrogen solubility in metal. The hydrogen solubility in the unstressed material√was assumed the same as in α-iron at room temperature, which is K S =√0.41 ppm/ MPa [22], and for the deformed material, the value K S = 0.54 ppm/ MPa [24, 25] was taken. According to [22], the hydrogen diffusion coefficient was taken D H = 5.5 × 10−11 m2 /s. The diffusive hydrogen equation was determined by analogue to solution of the Heat equation. Thus, the diffusive hydrogen distribution in the pipe with boundary conditions (where hydrogen concentration is equal to zero on the external side and determined by analogue to Sieverts law on the internal one) was determined. Based on this data the obtained crack growth rate values result as follows: Vsc ≈ 2.6 × 10−8 mm/s, VscH ≈ 4.1 × 10−8 mm/s

(3)

Figure 4 displays the dependency of pipe residual lifetime t∗ on the initial crack size b0 under pipe hydrogenation and without it. It is deduced from Fig. 4 that the steel hydrogenation causes nearly twofold reduction of the pipe residual lifetime. Fig. 4 Dependence of the pipe residual lifetime on the initial crack size: (solid line—taking into account the effect of hydrogen; dotted line—without hydrogen)

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4 Calculation Model for the Assessment of Pipe Residual Lifetime Under Transient Loading Conditions Transient loading route associated with closing and opening of the pipeline valves in operation is presented in Fig. 5. In order to determine the pipe residual lifetime (namely, the period before depressurisation) under these conditions with account for the pipe hydrogenation from the inside environment, the model of the semi-elliptical surface crack propagation in the pipe (Fig. 3) is proposed. It is assumed that constant pressure p, which is maintained in the pipe, can be switched off for certain time intervals due to the closing and opening of valves, then t i (i = 1, …, n) are the durations that the pressure was kept “on” (Fig. 5). The task is to determine the residual lifetime of the pipe, i.e. the time t = t∗ required for the crack propagation through the pipe wall due to mechanical loads, the action of corrosive medium and possible hydrogenation of the pipe wall from the internal surface. To solve the problem, the mathematical model of the growth of arbitrary surface crack is developed. It is assumed that a crack grows from the initial dimension S 0 to the final one S * by small steps S c during time intervals t 1 . Hence, the crack growth rate V can by defined as follows: V = dS/dt ≈ S c /t1 .

(4)

The energy balance of the fracture process at each crack increment reads: A = W + ,

(5)

where A is the work of external forces, W is the strain energy of the body after the crack propagation by S c , Γ is the fracture energy which is a function of the crack area S, environment characteristics, and time t. The strain energy W can be represented as follows: W = Ws + W p(1) (S) + W p(2) (S), Fig. 5 Scheme of the pipe loading by gas internal pressure

(6)

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where W s is the elastic strain energy component, W p(1) (S) is the part of the plastic deformation work induced by the pressure p in the process zone near the crack contour that depends only on the crack area S, W p(2) (S) is the part of the plastic deformation work in the process zone caused by pressure changes (loading–unloading) that also depends only on S. The balance of the rates of energy components reads: dA/dt = dW/dt + d/dt.

(7)

Substituting expression (6) into relation (7) yields the next:    ∂  − A − Ws − W p(1) − W p(2) /∂ S · dS/dt − ∂/∂t = 0.

(8)

Thus, the determination of the pipe residual lifetime is reduced to the solution of the following differential equation subjected to corresponding constraints:    dS/dt = ∂/∂ S/∂  − A − Ws − W p(1) − W p(2) /∂ S, t = 0, S(0) = S0 ; t = t∗ , S(t∗ ) = S∗ ; S∗ = π b(t∗ )a(t∗ ), b(t∗ ) = h.

(9) (10)

According to the equivalent area method [26], the area of a crack of given configuration varies similarly to what is observed for semi-circular crack of the radius ρ having the same initial area. In this case, it is assumed that the crack propagation rate of semi-circular crack is approximately the same at all points of its contour. The mathematical model (9)–(10) takes then the following form: dρ/dt = ∂/∂t/[γC − γt − ∂ W p(2) /∂ρ], t = 0, ρ(0) =

 π −1 S0 ; t = t∗ , ρ(t∗ ) = h,

(11) (12)

where γ t = δ t σ0 is the plastic strain specific work in the process zone near the crack tip associated with the crack-tip opening displacement δ t under the load p, γ C = δ CC σ0 is the critical value of γ t associated with the critical crack-tip opening displacement δ CC at corrosion fracture. Using the results of the previous works [22, 27, 28], the unknown quantities Γ and W p(2) (ρ) can be determined as follows:  = ρ C σ0 δCC , ρ C = 0.16ρ −1 S C , ρ n    4 2 (2) W p (ρ) = 0.25(1 − R) dρ, α0 σ0 δ(ρ − ρi ) δt2 (ρ) − δscc 0

(13)

i=1

where α 0 is the experimentally determined characteristic of the material fatigue, δ scc is the lower threshold value of δ t for which the crack does not propagate under stress √ corrosion, R = δscc /δt is the load ratio in the cycle, δ(x) is the Dirac delta-function

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[29], ρ i is the contour radius of the stress-corrosion crack at the moment of the i-th loading–unloading, ρ C is the value of semi-circular crack radius changes during its single jump, which is determined by the method of equivalent areas. Taking into account the previous researches [6, 22, 26, 30, 31], the substitution of relations (13) into (11) renders the equation for the period of subcritical crack growth t = t ∗ in the pipe with n events of loading/unloading: [∂(δCC ρ C )/∂t]t=t1 dρ .  = n 2 dt δCC − δt − 0.25α0 (1 − R)4 i=1 δ(ρ − ρi ) δt2 (ρ) − δscc

(14)

To make the mathematical model closed, Eq. (14) is supplemented with the following initial and final conditions: t = 0, ρ(0) = ρ0 ; t = t∗ , ρ(t∗ ) = h.

(15)

In the absence of transient component of loading, Eq. (14) takes the form [∂(δCC l C )/∂t]t=t1 dl = . dt δCC − δt

(16)

The experimental results [7, 30, 31] indicate that for small and medium values of δ t , the growth rate V sc of a corrosion-mechanical crack under sustained load is constant, i.e., [∂(δCC l C )/∂t]t=t1 dl = Vsc . dt δCC − δt

(17)

From the last equation it follows: [∂(δCC l C )/∂t]t=t1 = Vsc (δCC − δt ).

(18)

Using relation (18), Eq. (14) can be rewritten in the next form: Vsc (δCC − δt ) dρ .  = n 2 dt δCC − δt − 0.25α0 (1 − R)4 i=1 δ(ρ − ρi ) δt2 (ρ) − δscc

(19)

This is accompanied by the initial and final conditions (15). To take into account the influence of pipe hydrogenation, V sc in Eq. (19) is substituted with V scH . Assuming that the crack is macroscopic, i.e., that there hold −1 −1 −1 2 2 = K I2 (ρ)K I−2 δt (ρ)δCC C and δscc = K scc (σ0 E) , δt (ρ) = K I (ρ)(σ0 E) , the integration of the obtained equation under conditions (15) reads:  t∗ =

h

ρ0

−1 VscH dρ −

n  2 −1 α0 (1 − R)4  4 4 K I (ρi ) − K scc K fC − K I2 (ρi ) , 8VscH Eσ 0 i=1

(20)

Determination of the Residual Lifetime of Gas Pipeline …

69

where K I is stress intensity factor (SIF), K IC and K f C are critical values of SIF under static and cyclic loading respectively, K scc is the threshold value of SIF at the fatigue crack growth curve which represents stress corrosion cracking mechanism [7]. It may be assumed that the the stress-corrosion crack propagates with equal increments ρ = n−1 (ρ − ρ 0 ) during the time intervals t = t i (i = 1,…, n). Using the mean value theorem [32] for large n, i.e., for ρ  (h − ρ 0 ), relation (20) transforms as follows: t∗ =

−1 VscH (h

α0 (1 − R)4 n − ρ0 ) − 8VscH Eσ 0 h − ρ0



h ρ0



 4 K I4 (ρ) − K scc  2  dρ. K fC − K I2 (ρ)

(21)

Now, at given values of V scH , σ 0 , α 0 , K IC , K scc , E, and n, the relation (21) specifies the residual lifetime of the pipe with surface crack operated under combined action of internal pressure, corrosive media, long-term hydrogenation, and subjected to n events of loading and unloading.

5 Calculation of the Residual Lifetime of the Gas Pipeline Under Transient Loading Two cases are considered, namely, the pipe made of 17H1S steel under hydrogenation from the internal surface and without hydrogenation. The geometric parameters and the loading conditions are as follows: r = 0.71 m, h = 0.0187 m, p = 9 MPa; and α ≈ 0.23. The corrosion-mechanical characteristics of the operated pipe steel taken from the previous work [23] are presented in Table 1. The stress intensity factor K I (its maximum value at the crack contour) in the case of semi-circular crack can be written in the form [26]: √   √  K I = 0.7σ π h f (ε), f (ε) = ε 1 + 0.32ε2 1.04 + 0.23ε2 − 0.11ε4 ,

(22)

where ε = ρh ; ε0 = ρh0 ;σ = pr . h After substitution of Eq. (22) into relation (21) taking into account values (3) and other characteristics of the steel, the expression for t∗ takes the following form: under pipe hydrogenation from natural gas t∗ = 14.29 · (1 − ε0 ) −

2.4 × 10−4 · n 1 − ε0



1 ε0

f 4 (ε)   dε, 1 − 0.33 f 2 (ε)

(23)

f 4 (ε)   dε. 1 − 0.33 f 2 (ε)

(24)

without hydrogenation t∗ = 22.80 · (1 − ε0 ) −

3.5 × 10−4 · n 1 − ε0



1 ε0

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If the pipe is subjected to m events of loading and unloading per year, i.e., n = m · t∗ ,

(25)

where t∗ is the time of operation in years, then the pipe residual lifetime can be determined by the following formula: in the case of pipe hydrogenation

t∗ = 14.29(1 − ε0 )2 1 − ε0 + 2.4 × 10−4 · m



1 ε0

f 4 (ε)   dε 1 − 0.33 f 2 (ε)

−1 (years), (26)

without hydrogenation

t∗ = 22.80(1 − ε0 )

2

1 − ε0 + 3.5 × 10

−4

 ·m

1

ε0

f 4 (ε)   dε 1 − 0.33 f 2 (ε)

−1 (years). (27)

Based on relations (26) and (27), Fig. 6 displays the calculated dependences of pipe residual lifetime t∗ on the dimensionless value ε0 of the initial crack size for both the sustained (curve 1) and transient (curves 2–4) regimes of operation at various event numbers m. It is evident from Fig. 6 that the hydrogenation of pipe leads to 1.53 times reduction of its residual lifetime under sustained loading, and to 2.04 times decrease under transient loading conditions combined with hydrogen influence.

Fig. 6 Dependence of the pipe residual lifetime t∗ on the dimensionless initial crack size ε0 in the sustained (curve 1) and transient (curves 2–4) modes of operation for different values of m (m = 0, 100, 200 and 365): a without hydrogenation, b with hydrogenation

Determination of the Residual Lifetime of Gas Pipeline … Table 1 Properties of the operated steel 17H1S [23] √ √ Conditions K SCC (MPa m) K fC (MPa m)

71

V SC (mm/year)

With hydrogenation

8.5

60

1.29

Without hydrogenation

6.0

93

0.82

6 Conclusions The model describing the corrosion-mechanical fracture of the underground gas pipeline with semi-elliptical external surface crack is developed taking into account the intensification of crack growth in the pipe steel 17H1S by diffusible hydrogen. Corresponding mathematical model (differential equation with initial and final conditions) is derived to determine the residual lifetime of a pipe of gas pipeline subjected to hydrogenation from the transported gas, soil corrosion, long term sustained and transient loadings caused by gas pressure in the pipe and by start/stop valve operations, respectively. Model implementation allows evaluating the pipe residual lifetimes considering pipe hydrogenation from the inner surface, soil corrosion at the outer surface and a possible transient loading. It is concluded that pipe wall hydrogenation results in acceleration of corrosion-mechanical crack growth in the pipe, reduction of its residual lifetime by 1.5 times under sustained loading, and 2 times under transient loading conditions with hydrogen impact. Acknowledgements This research has been supported by the NATO in the Science for Peace and Security Programme under the Project G5055.

References 1. Bolzon, G., Boukharouba, T., Gabetta, G., Elboujdaini, M., Mellas, M. (eds.): Integrity of pipelines transporting hydrocarbons: corrosion, mechanisms, control, and management. In: NATO Advanced Research Workshop on Corrosion Protection Of Pipelines Transporting Hydrocarbons, 322 p. Dordrecht (2010) 2. Krasovskii, A.Y, Lokhman, I.V., Orynyak, I.V.: Stress-corrosion failures of main pipelines. Strength Mater. 44(2), 129–143 (2012) 3. Andreikiv, O.E., Hembara, O.V., Tsyrul’nyk, O.T., Nyrkova L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238 (2012) 4. Voloshyn, V.A., Zvirko, O.I., Sydor, P.Y.: Influence of the compositions of neutral soil media on the corrosion cracking of pipe steel. Mater. Sci. 50(5), 671–675 (2015) 5. Ha, H., Gadala, I., Alfantazi, A.: Hydrogen evolution and absorption in an API X100 line pipe steel exposed to near-neutral ph solutions. Electrochim. Acta 204, 18–30 (2016) 6. Slobodyan, Z.V., Nykyforchyn, H.M., Petrushchak, O.I.: Corrosion resistance of pipe steel in oil-water media. Mater. Sci. 3, 424–429 (2002) 7. Tsyrul’nyk, O.T., Slobodyan, Z.V., Zvirko, O.I., Hredil, M.I., Nykyforchyn, H.M., Gabetta, G.: Influence of operation of Kh52 steel on corrosion processes in a model solution of gas condensate. Mater. Sci. 44(5), 619–629 (2008)

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8. Hredil, M., Tsyrulnyk, O.: Inner corrosion as a factor of in-bulk steel degradation of transit gas pipelines. In: 18th European Conference on Fracture (ECF-18), Dresden, Germany, manuskript #483 (2010) 9. Krasowsky, A.Y., Dolgiy, A.A., Torop, V.M.: Charpy testing to estimate pipeline steel degradation after 30 years of operation. In: Charpy Centenary Conference, vol. 1, pp. 489–495. Poitiers, France (2001) 10. Nykyforchyn, H., Lunarska, E., Tsyrulnyk, O., Nikiforov, K., Gabetta, G.: Effect of the longterm service of the gas pipeline on the properties of the ferrite–pearlite steel. Mater. Corros. 9, 716–725 (2009) 11. Meshkov, Y.Y., Shyyan, A.V., Zvirko, O.I.: Evaluation of the in-service degradation of steels of gas pipelines according to the criterion of mechanical stability. Mater. Sci. 50(6), 830–835 (2015) 12. Hutsaylyuk, V., Maruschak, P., Konovalenko, I., Panin, S., Bishchak, R., Chausov, M.: Mechanical properties of gas main steels after long-term operation and peculiarities of their fracture surface morphology. Materials 12(3), 491 (2019) 13. Syrotyuk, A.M., Dmytrakh, I.M.: Methods for the evaluation of fracture and strength of pipeline steels and structures under the action of working media. Part I. Influence of the corrosion factor. Mater. Sci. 50(3), 324–339 (2014) 14. Zvirko, O.I., Savula, S.F., Tsependa, V.M., Gabetta, G., Nykyforchyn, H.M.: Stress corrosion cracking of gas pipeline steels of different strength. Proc. Struct. Integr. 2, 509–516 (2016) 15. Zvirko, O., Gabetta, G., Tsyrulnyk, O., Kret, N.: Assessment of in-service degradation of gas pipeline steel taking into account susceptibility to stress corrosion cracking. Proc. Struct. Integr. 16, 121–125 (2019) 16. Dmytrakh, I.M., Leshchak, R.L., Syrotyuk, A.M.: Influence of sodium nitrite concentration in aqueous corrosion solution on fatigue crack growth in carbon pipeline steel. Int. J. Fatigue 128, 105192 (2019) 17. Andreikiv, O.Y., Dolins’ka, I.Y., Shtoiko, I.P., Raiter, O.K., Matviiv, Y.Y.: Evaluation of the residual service life of main pipelines with regard for the action of media and degradation of materials. Mater. Sci. 54, 638–646 (2019) 18. Shtoyko, I.P.: Mathematical model for determination of residual resource of gas pipeline under actions of permanent pressure, ground corrosion and degradation of its material. In: Samoilenko, A.M., Kushnir, R.M. (eds.), Modern Problems of Mechanics and Mathematics, vol. 1, pp. 142–143 (2018) 19. Shtoyko, I., Toribio, J., Kharin, V., Hredil, M.: Prediction of the residual lifetime of gas pipelines considering the effect of soil corrosion and material degradation. Proc. Struct. Integr. 16, 148– 152 (2019) 20. Chepil, O.Y., Shtoyko, I.P.: Distribution of hydrogen concentration in a compact specimen under the conditions of electrolitic hydrogenation. Mater. Sci. 55(3), 392–395 (2019) 21. Nazarchuk, Z.T., Nykyforchyn, H.M.: Structural and corrosion fracture mechanics as components of the physicochemical mechanics of materials. Mater. Sci. 54(1), 7–21 (2018) 22. Hembara, O.V., Andreikiv, O.Y.: Effect of hydrogenation of the walls of oil-and-gas pipelines on their soil corrosion and service life. Mater. Sci. 47(5), 598–607 (2012) 23. Voloshyn, V.A.: Fatigue crack propagation resistance of the operated welded joint of 17H1C pipe steel. Physicochem. Mech. Mater. 1, 112–119 (2020) 24. Capelle, J., Dmytrakh, I., Pluvinage, G.: Comparative assessment of electrochemical hydrogen absorption by pipeline steels with different strength. Corros. Sci. 52, 1554–1559 (2010) 25. Capelle, J., Gilgert, J., Dmytrakh, I., Pluvinage, G.: The effect of hydrogen concentration on fracture of pipeline steels in presence of a notch. Eng. Fract. Mech. 78, 364–373 (2011) 26. Andreikiv, O.Y., Sas, N.B.: Subcritical growth of a plane crack in a three-dimensional body under the conditions of high-temperature creep. Mater. Sci. 44(2), 163–174 (2018) 27. Andreikiv O.Y., Dolins’ka, I.Y., Kukhar, V.Z., Shtoiko, I.P.: Influence of hydrogen on the residual service life of a gas pipeline in the maneuvering mode of operation. Mater. Sci. 51, 500–508 (2016)

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28. Andreikiv, O.Y., Dolins‘ka, I.Y., Yavorska, N.V.: Growth of creep cracks in structural elements under long-term loading. Mater. Sci. 48(3), 266–273 (2012) 29. Hatami, M.: Weighted residual methods: principles, modifications and applications. 384 p., Academic Press (2018) 30. Elboujdaini, M.: Initiation of environmentally assisted cracking in line pipe steel. In: 16th European on Fracture (ECF16) “Fracture of Nano and Engineering Materials and Structures”, pp. 1007–1008. Dordrecht, Springer (2006) 31. Handbook of Fatigue Crack Propagation in Metallic Structures (Ed. Carpinteri, A.), vol. 1, 952 p., Elsevier (1994) 32. Heydari, M., Avazzadeh, Z., Navabpour, H., Loghmani, G.B.: Numerical solution of Fredholm integral equations of the second kind by using integral mean value theorem II. High dimensional problems. Appl. Math. Model. 37(1–2), 432–442 (2013)

Open Issues

A Tentative Summary of Corrosion Issues in Pipelines Transporting Hydrocarbons Giovanna Gabetta

Abstract As it is widely known, pipelines can be a safe and environmentally/economically sound means to transport multiphase fluid of different nature; if not well monitored, however, they can pose a serious threat to health and environment. Operational and monitoring methods are improving, but new challenges are also present, mainly due to the quality of transported fluids, especially in the case of hydrocarbons. To quote a few, crude oil often contains H2 S; new pipelines transporting and injecting supercritical fluids are built; new corrosion problems can occur due to the—only partially known—damage mechanisms caused by biofuels, and to external aggressive environments as for instance deep sea water. After more then 40 years of work in the field of corrosion, often in projects specifically related to pipelines, in the present paper the author will try to make a summary of the principal damage mechanisms, the present knowledge and the open threats for the future, from the partial point of view of a former employee of the Oil&Gas industry and at present consultant in that sector. Keywords Corrosion · Pipeline steel · Damage mechanisms · Knowledge management

1 Introduction Corrosion problems in pipelines transporting hydrocarbons are quite well known and damage mechanisms can be in many cases managed, so that it is possible to say that pipelines are a safe mean to transport multiphase fluids. It is foreseen however that multiphase transport will have a major impact on offshore development of Oil&Gas industry during the future years. As a consequence, the situation is now challenging under many aspects. In the past, the multiphase well stream was preprocessed through separation on platforms or even subsea, close to the wells. Drastic reduction in G. Gabetta (B) Oil&Gas Sector, Milano, Italy e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_6

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costs nowadays can be achieved when unprocessed, multiphase well streams are transported over longer distances in carbon steel pipelines [1]. For long-distance and large-diameter pipelines, cost can become prohibitively high if corrosion-resistant alloys instead of carbon steel are used. Better understanding and control of carbon steel corrosion is mandatory, having a large economic impact. Internal corrosion is one of the main causes of pipelines damage, particularly in presence of water. Acid gases, such as CO2 , H2 S, and/or sulphur in oil industry’s production fluids can be responsible for general and localized corrosion. Corrosion can be responsible of hydrogen evolution. Hydrogen Embrittlement mechanisms are the cause of bulk deterioration of the steel [2]. In production wells, water amount tends to increase with exploitation time. In new fields, produced fluids can contain a larger amount of acid gases. As a consequence, corrosion problems can be enhanced and different mechanisms, not yet accounted for, can be active. They must be considered during both the design phase and the life management of pipelines. Moreover, there is a need of managing knowledge. Organizations and companies worldwide are currently facing: (a) increasing quantity of available information on materials; (b) increasing complexity of the problems to be solved, and (c) increasing lack of communication between people and/or institutions. When trying to cope with such difficulties, I became interested in Knowledge Management. I learned that there is a need to build bridges between contemporary science, engineering and business. The huge amount of available information can not be simply stored in a single human brain, and Communication Technology (ICT) tools can be of great help only if well managed. They shall be implemented to help supporting team work and networks, using available experience and expertise and, hopefully, international cooperation. We are facing big challenges, and maybe it is time to do things differently and to consolidate different disciplines of engineering with applications that can give us more reliable predictions [3]. Knowledge Management (KM) involves a cultural change to stimulate a better use of all resources. Progress will be slow and difficult if we do not learn how to afford this complex situation.

2 Damage Issues of Pipelines Corrosion is one of the principal causes of degradation and failure of pipelines. Damage mechanisms can be observed externally and internally. Externally, a pipeline can be in contact with the ground (buried pipelines), or can be immersed in sea water. In both cases, external corrosion is prevented by the use of coating (passive protection) and/or by cathodic protection (active protection). In the ground, in a closed

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Fig. 1 Stress Corrosion Spectrum following suggestions by Parkins [4]

sea or in deep water, the occurrence of anaerobic condition with the proliferation of bacteria can trigger Microbiologically Induced Corrosion (MIC). Underground pipeline steels are mainly low alloy steels. These steels are susceptible to Stress Corrosion Cracking in peculiar situations. Such damage mechanisms have been studied and discussed since long time, not only for pipeline materials. A very important statement about Stress Corrosion Cracking was made by Redvers Parkins as early as 1963 [4], and is summarized in Fig. 1. At that time, the issue of Intergranular SCC was understood and overcome with the application of temperature control. However, Transgranular SCC can also by observed in pipelines, both externally and/or internally, depending on: • the environment in contact with the steel (internally or externally) • the steel properties (presence of inclusions, hardness, service time). Hydrogen embrittlement due to cathodic reaction at the crack tip and subsequent diffusion was identified as the active Transgranular Cracking mechanisms. In this case, the importance of stress situation (and the presence of time-dependent loading) shall be also kept in mind [5, 6]. While for long transport pipelines the gas is normally dry and internal corrosion is not an issue, for flowlines and inter-field lines transporting untreated fluids, internal corrosion plays a crucial role for structural integrity. This is a growing and challenging problem for Oil&Gas industry, since the age of plants and components is worldwide increasing, and new frontiers of Offshore Engineering are ultra-deep waters, where remote treatment is performed on floating processing units. In order to protect the environment, it is necessary to prevent internal corrosion that is a well known cause of failure and leakages. Internal corrosion can be due to different mechanisms. Standards and models are available to help in material selection, but further work is needed to fully understand the corrosion process and its evolution in time, since it is very complex and depends on a range of variables: hydrocarbon characteristics, process fluid-dynamics and pipeline configuration [7]. Steel properties and in-bulk degradation of the pipe material is also an important challenge. This leads to the loss of the initial mechanical properties, causing problems

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that impact in economy and efficiency. Recent studies have shown that an important factor of main pipelines serviceability loss under their long-term resistance service is due to hydrogen embrittlement which is a consequence of corrosion processes [8]. Material selection for sour service pipelines is the subject of international guidelines, e.g. the standards issued by Nace International [9] and EFC [10]. Commonly, standards pose limitations to carbon steel line pipe for sour service, which regard lower bound for ‘cleanness’ and surface hardness as well, further a satisfactory performance in specific (very aggressive, low pH) test conditions. Unfortunately, these standards have shown a few weak points that already impacted the safety performance in recent projects, namely: • In the definition of sour service, since more severe environments are nowadays common. The role of fluid composition needs to be better assessed and understood. Data on material susceptibility are more reliable if tests are performed in closeto-service environments [11]. • Mechanisms of crack initiation and crack propagation can be different. Hydrogen Embrittlement can play a different role in these two phases. Stress state and stress variations are very important in HE. The relationship between corrosion resistance and crack susceptibility can affect the linear application of recommended practices [12].

2.1 Internal Corrosion Challenges Internal corrosion due to the presence of CO2 in the transported fluid is the most diffused corrosion mechanism in pipelines transporting hydrocarbons. The study of this corrosion form started in 1945 due to the peculiar problems encountered in the exploitation of fields located in Louisiana and Texas. Towards an appropriate materials selection, Corrosion Rate (CR) shall be evaluated as a function of transported fluids properties and of the resistance of candidate steel. Predictive models are available to allow evaluating CR from the main physicochemical parameters of the fluid. The majority of such models is obtained by comparison of experimental data and field observations. A few more complex models are based on equations describing the physico-chemical behaviour of metal. A good model shall be able of complying with two fundamental requests: 1. To provide a first indication on the applicability of carbon steel; 2. To evaluate CR for Carbon Steel, so that an adequate corrosion allowance value can be established. However, when models are compared with field cases, results are often fairly conservative and CR estimate often do not match with field measurements. While it is reasonably easy to understand a corrosion event “retrospectively” with failure analysis methods, a large degree of uncertainty is associated with the attempt of quantifying a prediction for the future evolution of damage. Further study is necessary

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to implement models and methodologies. CO2 corrosion is still to be considered an open issue since models markedly reflects the philosophies used in their development [13]. Most models are unsuitable for situations with appreciable H2 S contamination, which is of growing importance in the recent new discoveries. When dealing with H2 S rich fluids, ad hoc models are needed. Hydrogen sulphide is a weak acid, causing a small decrease in pH of a water solution, and corroding steels and alloys in neutral solutions, with a generally low uniform corrosion rate. Hydrogen sulphide plays an important role in the stability of corrosion products film, increasing or decreasing its corrosion resistance by interaction with other components, such as CO2 . Wet gas mixtures containing hydrogen sulphide attack aggressively iron and mild steels. Sulphur forms stable sulphides with many transition metals. H2 S dissociation on transition metal surfaces is an easy process and, as consequence, sulphur deposits and sulphide compound formation on metal surfaces is favoured [11]. Three regimes of mild steel corrosion can be identified in CO2 /H2 S environments, as shown in Fig. 2. Characteristic of the mixed regime is the formation of scales of iron carbonate and iron sulphide. The application of a sweet corrosion model for the mixed regime appears justified, though it may be conservative. Testing of the candidate material in the service environment is strongly recommended [11]. Cases of MIC and under deposit corrosion have some similarities because bacteria colonies may form a deposit or shell under which corrosion and pitting proceeds even while the surrounding metal is unaffected. MIC and under deposit pits commonly are localised and non-uniform owing to the particular location of deposits or bacteria colonies on the steel. Under deposit pitting is a common failure mode in locations where solids can accumulate. The deposits trap corrodents against the metal surface but allow in enough water to create a locally severe aqueous environment beneath the deposit, which is vastly different from the general environment. Acidic sludge, salts, and sulphur compounds create some of most aggressive environments for under deposit pitting. Bacteria and other microbiological organisms can also be present Fig. 2 Effect of CO2 versus H2 S partial pressure on corrosion [11]

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under deposit and cause severe localised pitting. Sulphate Reducing Bacteria (SRB) are typically found in crude oil and treatment plants. Microbiologically-Induced Corrosion can cause rapid failures of carbon steels, low-alloy steels, and stainless steels. Only a few models are available to describe and predict MIC, they shall be better developed and compared with service data [14]. The transport of biofuels also presents corrosion problems due to their different chemical composition compared to classic diesel fuel. Carbon steel may experience not expected mechanisms, of both general and localized corrosion (as for instance stress corrosion cracking) that shall be accounted for [15]. Corrosion models can be coupled with hydraulic analysis performed with the help of flow dynamics codes. Flow dynamics can help in assessing different risk levels in different region of a long pipeline. Flow regimes and the potential water wetting at the pipeline wall can be estimated using one-dimensional code. Computational Fluid Dynamics (CFD) is also a powerful tool in some critical pipeline sections. The methodology is just a first attempt to couple corrosion and fluid dynamics analysis and further applications are foreseen to allow completing the procedure [16].

2.2 External Corrosion Challenges Transgranular Stress Corrosion Cracking (TGSCC) can be observed in buried pipelines where the metal is in contact with diluted solution under disbonded coating. It seems already known that such cracking involves hydrogen evolution and permeation at the crack tip, as previously observed in nuclear pressure vessel steels and other low alloy steels under variable loading. This cracking mechanism is influenced by loading conditions (crack tip strain rate) and by the chemistry of the external environment. With reference to pipeline steels, the fracture surface observed in serviced pipes has been reproduced in laboratory. An example is shown in Fig. 3.

Fig. 3 Comparison of a fracture surface in field (left) with the fracture surface in a laboratory specimen (right) [6]

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Using a comparison with literature data describing the behaviour of landslides, the hypothesis was proposed that the crack grows only during short times, followed by long intervals where only generalized corrosion is active. The observation is supported by actual fracture surface features. Similar mechanisms are active sub-sea if the water contains H2 S (typical source of hydrogen in aqueous solution), [17] as for instance it was observed for the Blue Stream pipeline in the Black Sea. Pipelines posed in anoxic water must be designed and monitored with extra care. Test in environment simulating service conditions are once again recommended [11].

2.3 Bulk Material Degradation Problems Electrochemical and corrosion tests of low-carbon steel after long term operation show degradation of the corrosion resistance. It was also shown that the degradation of corrosion resistance correlated with the degradation of mechanical properties [18]. Degradation depends on the steel quality, presence of defects such as laminations, service conditions and length of service. The main degradation mechanism is Hydrogen Embrittlement (HE). Cracking processes might occur when pipeline steel absorbs Hydrogen. In presence of manufacturing defects in the bulk steel, internal cracks and/or blisters can be observed. Blisters are formed when atomic Hydrogen, resulting from corrosion reactions between the carried fluid and the steel, diffuses into the metal and accumulates as gaseous Hydrogen at planar defects, such as preexisting cracks or nonmetallic inclusions. The high pressure of gaseous Hydrogen inside the trapping sites causes separation of the metal-defect interface, forming a cavity filled with high pressure gaseous Hydrogen. Hydrogen Embrittlement however can act in many different modes, degrading bulk materials properties and enhancing the probability of damage. Research in this field is very active and recommended.

3 Inspection Tools Internal corrosion is a crucial issue for the safe operation of oil&gas pipelines. Despite the large number of models proposed in literature, the corrosion process is very complex and its evolution is very difficult to predict. Defects can be detected using Non Destructive Test procedures. Intelligent pig is a widely used tool to measure pipeline wall thickness and the lack of metal along the pipeline length. Each pig report can provide a number of data indicating the position of defects, as shown in Fig. 4. Research is needed to develop further knowledge in the evolution of internal damage starting from the evidence of an intelligent pig. Artificial Neural Network (ANN) was for instance proposed to interpolate thickness measurements.

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Fig. 4 Example of results of Internal Inspection in a subsea pipeline [19]

Pipeline geometrical characteristics and fluid dynamics variables are the input data, and the future challenge is to provide a correlation of geometry and process data with damage evolution, (i.e. defect growth in number and/or in dimension) in each section of the examined pipeline [20]. The goal of the research should be: • To predict corrosion level better than using provisional models. • To decrease costs due to better pig utilization. • To support the management of asset integrity of non piggable sealines, comparing the results of ILI with with external inspection and extending the assessment to pipelines having similar characteristics • To provide a ranking of pipelines corrosion risk, that will help scheduling internal line inspections (ILI).

4 Knowledge Dissemination Pipeline integrity is a growing and challenging problem for Oil Companies since the length of pipelines transporting hydrocarbons is increasing worldwide, and the responsibility and awareness about environmental protection is increasing too. Corrosion is one of the most active and dangerous damage mechanisms, while fracture mechanics helps to verify and predict pipeline stability. Knowledge in both disciplines was increasing at a fast pace in the second half of past century, but the progress in some way slowed down more recently, following the idea that everything is known and the necessity for further research is lower [21].

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At the same time, new tools are now available to communicate and to share knowledge; they are increasingly used but their potential is not fully understood especially by older people. Social networks and the collection of information via the web are often simply used to help connecting people, but not as a full exchange of knowledge. We are all aware of the difficulty in selecting what can be useful out of a huge amount of findings obtained by a search engine in the web; of the feeling of impotence when we are working and we get further and further interruptions by e-mail and phone calls. Neural science specialists are sometimes wondering if the human mind is going through a deep change, from reading capabilities to digital information use [22]. With a simpler goal in mind, corrosion engineers in Oil Companies are facing some peculiar problems, as for instance: • The amount of papers published annually in the topic of pipeline corrosion is huge. • In many cases, on the other hand, users need to understand the problem as quick as possible, to give fast answers. When comparing information on failure cases with models and codes, it seems that they are quite reliable to explain what happened, retrospectively after having a problem. However, when looking for prediction, users must often choose between a very conservative approach, good enough for a preliminary material selection at the design phase, and not reliable numbers when trying to extend the life span of existing facilities. A large number of older experts is now facing retirement; in the span of a few years, these people will be replaced by a much younger workforce, often without the time for a gradual change necessary to transfer knowledge. As a consequence, easy problems already known can be quite simply solved; but much more complex problems are emerging and their solution—or their simple management—is probably far from the reach of a single human brain; there is a need of cooperation, but the capability of human people to cooperate is still far too little, we have a habit for competition, usually enhanced by historical reason. In summary, we tend to propose old solutions for new problems, and we do not use at their best the new available tools. It is worth some effort to think about these problems and to try an application of this philosophy to engineering problems such as pipeline management. Sometimes the amount of time required to select what is useful can be of the same order of magnitude that the time necessary to solve a problem, but changing the available information in applicable knowledge is important in the longer term. KM is a resource that can be very useful and recommended.

5 Concluding Remarks Following a previous paper presented at the Nato Advanced Research Workshop CBP.MD.ARW 983731, the present paper is an attempt to summarize some of the

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problems and challenges that are still open in the safety of pipelines transporting hydrocarbons. Engineers are mainly interested in procedures to avoid and/or manage the damage. In the case of internal corrosion and/or cracking in pipelines transporting sour hydrocarbons, international standards rely on steel metallurgy (composition, microstructure) and hardness, with the aim at selecting not susceptible materials. Field observations at the opposite show that, due to the large variation of fluid compositions and process variables, the concept itself of Stress Corrosion Susceptibility is probably too simple. A better understanding and a quantitative approach to different aspects of Hydrogen Embrittlement are required to assess damage evolution. Knowledge Management can be a useful tool to manage the huge amount of data; an example is the use of ILI results, which can be approached with ICT tools to help in life prediction of such important industrial components.

References 1. De Masi, G., Vichi, R., Gentile, M., Bruschi, R, Gabetta, G.: A Neural Network Predictive Model of Pipeline Internal Corrosion Profile, in: IEEE SIMS, (Systems Informatics, Modelling and Simulation), Sheffield, UK (2014) 2. Lynch, S.P.: Mechanisms and kinetics of environmentally assisted cracking: current status, issues, and suggestions for further work. Metall. Mater. Trans. A 44, 1209–1229 (2013) 3. Gabetta, G., Gori, G.: The use of knowledge management to improve pipeline safety. In: Bolzon, G., Boukharouba, T., Gabetta , G., Elboujdaini, M., Mellas, M. (eds.) Integrity of Pipelines Transporting Hydrocarbons. NATO Science for Peace and Security Series C: Environmental Security, Vol 1. Springer, Dordrecht (2011) 4. Parkins R.N.: Mechanisms of stress corrosion cracking, Chap. 8.2. In: Sheir L.L., (ed.) Corrosion, pp. 8–27, Newness-Butterworths, London (1963) 5. Gabetta, G., Bregani, F.: Some consideration on EAC mechanisms during crack propagation under monotonic loading. In: Turnbull, A. (ed.) Hydrogen Transport and Cracking in Metals, pp. 103–112. HMSO, London (1995) 6. Gabetta, G., Di Liberto, S., Bennardo, A., Mancini, N.: Strain rate induced stress corrosion cracking in buried pipelines. Br. Corros. J. 36(1), 24–28 (2001) 7. Gabetta, G.: Models for CO2 corrosion in pipelines transporting hydrocarbons, Plenary lecture. In: International Conference on Corrosion Mitigation and Surface Protection Technologies, 30th Annual Conference, Seagull Hotel, Hurghada, Egypt (2012) 8. Nykyforchyn, H.M., Lunarska, E., Gabetta, G., Zonta, P.: Degradation of properties of long term exploited main oil and gas pipelines steels and role of environment in this process. In: Bolzon, G., Boukharouba, T., Gabetta, G., Elboujdaini, M., Mellas, M. (eds.) Integrity of Pipelines Transporting Hydrocarbons. NATO Science for Peace and Security Series C: Environmental Security, vol. 1. Springer, Dordrecht (2011) 9. International Standard ANSI/NACE MR0175/ISO 15156, Petroleum and natural gas industries—Materials for use in H2S-containing Environments in oil and gas production—Part 1: General principles for selection of cracking-resistant materials, NACE International, Houston, Texas, USA (2015) 10. European Federation of Corrosion Publications: Number 17: A Working Party Report on Corrosion Resistant Alloys for Oil and Gas Production: Guidance on General Requirements and Test Methods for H2S Service. The Institute of Materials, London (1996) 11. Gabetta, G., Correra, S., Sgorlon, S., and Bestetti, M.: Test conditions for pipeline materials selection with high pressure sour gas. Int. J. Corros. 3402692 (2018)

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12. Gabetta, G.: Some thoughts on the competition between corrosion and cracking, (Keynote Lecture). In 32nd Spanish Conference on Fracture and Structural Integrity, ESIS TC-10 Workshop on EAC & HE, Zamora (ES) (2015) 13. Nesic, S., Wang, S., Fang, H., Sun, W., and Lee, J. K.-L.: A new updated model of CO2/H2S corrosion in multiphase flow. In: Proceedings of the NACE Corrosion/2008, NACE International, Houston, Texas, USA (2008) 14. Videla, H.A., Herrera, L.K.: Understanding microbial inhibition of corrosion. A comprehensive overview. Int. Biodeterioration Biodegradation J.; In: Sylvestre, M., Urzl, C. (Eds.), 14th International Biodeterioration and Biodegradation Symposium, vol. 63, no. 7, pp. 811–958 (2009) 15. Kane, R.D., & Papavinasam, S.: Corrosion and SCC issues in fuel ethanol and biodiesel, NACE international. In: NACE CORROSION 2009, Paper 9528 (2009) 16. Gabetta, G., Margarone, M.: Corrosion and flow models predictions compared using case histories. In: NACE CORROSION 2007, paper 07522 (2007) 17. Bruschi, R., Gentile, M., Torselletti, E.: Sour Service Challenges, SPE-188300-MS, Abu Dhabi International Petroleum Exhibition & Conference, UAE (2017) 18. Nykyforchyn, H., Lunarska, E., Tsyrulnyk, O.T., Nikiforov, K., Gennaro, M.,E., Gabetta, G.: Environmentally assisted “in-bulk” steel degradation of long term service gas trunkline. Eng. Failure Anal. 17, 624–632 (2010) 19. Gabetta, G., Pagliari, F., Rezgui, N.: Hydrogen Embrittlement in pipelines transporting sour hydrocarbons, Special symposium Recent advances on Hydrogen Embrittlement Understanding and Future research Framework (HE Special Symposium), ECF 22, Belgrade, (2018) 20. Gabetta, G., Conti, M., Basile, M., Podenzani, M., Bennardo, A.: Mathematical models to investigate internal corrosion in pipelines. In: 2nd NACE Conference and Expo Genoa 2018, From Industry to the Industry (2018) 21. Gabetta, G.: Aspects of knowledge management in corrosion modelling. In: 25th Conference of the Egyptian Corrosion Society-ECS’2006, Ain El Soukhna, Red Sea, Egypt (2006) 22. Wolf, M.: Proust and the Squid. The Story and Science of the Reading Brain, Harper Perennial, New York (2008)

Risk-Based Inspection and Integrity Management of Pipeline Systems Stefano P. Trasatti

Abstract Over the last decade, there has been a substantial increase in construction projects of pipelines for the transportation of several varied and dissimilar fluids, such as oil and natural gas, fuels and chemicals, as well as water to drink or for irrigation. The need to transport fluids over considerable distances calls for carbon steel as construction material as it guarantees the required tensile strength and toughness properties. Also, pipelines can be laid in very diverse environmental conditions and terrains, thus exposing steel to different risks of damage. Since any deterioration of line pipes can lead to leaks or ruptures, that requires the development of an adequate system for control and monitoring of the structural integrity of the pipeline. Existing inspection and maintenance practices commonly applied by most pipeline operators are formulated mainly on the basis of experience. Such procedures are no longer sufficient and quantitatively risk-based methodologies are required. Analytical tools have therefore been developed for several years with the aim, on one hand, of reducing the economic impact of failures and, on the other hand, of limiting the impact that failures may have on environment, health and safety as much as possible. The present article, by evaluating the rationale behind commercially available riskbased procedures and through a critical analysis of the open literature on the subject, intends to highlight limitations and possibilities to improve a procedure of this type. Keywords Risk based inspection · Pipeline integrity management · Threats · Corrosion modes

1 Introduction The demand for transportation of commodities is increasing very rapidly and pipelines represent a unique mode to move huge amount of commodities over large distances at relatively low operating costs. S. P. Trasatti (B) Department of Environmental Science and Policy, Università degli Studi di Milano, Milano, Italy e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_7

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Pipelines are ideal for unidirectional flow of goods and can be laid on a wide variety of terrains without much difficulty. Further, pipeline transportation has complete automation of loading and unloading operations and can be considered environmental friendly. The use of pipelines to transport single phase fluids like water, oil and natural gas is a well-known technology, also for transporting other fluids such as slurry, sewage, etc. With this in mind, it is not surprising that the pipeline transportation market is expected to grow at a very high pace in the next years. Oil and gas transmission pipelines are mainly installed underground with the consequence that many factors can affect their structural integrity, including corrosion, interference from the third party, material defects, malfunction, and natural hazard. Besides, increasing number of aging pipelines in operation has significantly augmented the number of serious accidents, thus leading authorities and industry itself to reflect on how to keep equipment safe over time. The first action was the development of calculation codes like ASME B31G criterion [1] that provides the most basic and widespread method in assessing the remaining strength of corroded pipelines. Later, DNV [2] published recommended practices for assessing corroded pipelines under combined internal pressure and longitudinal compressive stress. More recent studies [3–7] indicated that the predictions are known to be conservative [8], resulting in pipelines being removed from service too early and costly and unnecessary repair or replacement of the affected region imposed. Accordingly, the need to monitor over time the integrity of equipment during operation have arisen. This was at the beginning faced with the definition of inspection methods and control frequencies that provided for checks on a regular basis with established times equal for all types of equipment. However, industry felt soon the need to adopt preventive and predictive management tools since it was mandatory, in addition to reducing risk of accidents and pollution, to optimize costs and reduce production loss, at the same time keeping the life of each component to the maximum. Studies were started, especially in the oil and gas industry, on the various damage mechanisms that could affect equipment depending on the design and service conditions [9]. This led to acquired knowledge that has allowed to establish corrosion rates and in turn to calculate the residual life of each component with greater precision: inspections and maintenance procedures could therefore be carried out before unforeseen events occurred. Accordingly, the random characteristics of the governing parameters in real pipelines have motivated several authors to develop probabilistic approaches to assess the probability of failure of pipelines with and without corrosion damages. All this has represented the rationale behind the so-called risk management approach, that is to say the process of identifying risk, assessing risk, and taking steps to reduce risk to an acceptable level. In 1994 the American Petroleum Institute (API) started to develop a Risk-Based Inspection (RBI) methodology and the related publication became a recommended practice (API RP 581, Risk-Based Inspection Technology in 2008, reviewed in 2016.

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The present article, by evaluating the rationale behind commercially available risk-based procedures and through a critical analysis of the open literature on the subject, intends to highlight limitations and possibilities to improve a procedure of this type.

2 Pipeline Integrity Management There are different kinds of threats to pipeline integrity, such as metal loss, cracking, third party damage (dents and gouges), design imperfections, joints, etc. One or a combination of these failure mechanisms could eventually lead to leak or rupture and consequently to potential huge human, financial, and environmental loss. Study on different defect prediction models is the foundation of effective integrity management. The last step, risk-based management, will determine proper inspection intervals, and maintenance and repair actions. The management models will also influence the first step and the second step by possibly changing the inspection actions and defect status. The aim of an integrity program is to achieve accurate defect prediction and balance the reliability and costs in an effective way. Integrity is the top priority for pipeline operators to ensure reliable and safe operations of pipelines, to increase productivity, reduce cost, prevent damage to the environment, support future projects, etc. It is essential to find effective ways to monitor, evaluate and assure the integrity of the pipeline, and reduce the risk of leaks and rupture. For pipelines, it is mandatory to ensure safety, security of supply and compliance with relevant codes and legislation. Procedures and practices are implemented to protect, manage and maintain the integrity of pipeline systems. A pipeline integrity program generally consists of three major steps: (i)

Defect detection and identification, to obtain defect information through inspection, monitoring, testing and analysis techniques. (ii) Defect growth prediction, to predict defect growth based on damage prediction models and the collected data. (iii) Risk-based management, to recommend optimal inspection, maintenance and repair policies and activities. Pipeline companies can gather defect information through walking along the pipelines by technical personnel, hydrostatic testing, in-line inspection (ILI), nondestructive evaluation (NDE), etc. ILI tools are currently the most widely used inspection technology for detecting and inspecting various types of pipeline defects.

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3 Pipeline Degradation Mechanisms Pipeline facilities can be subject to several degradation mechanisms depending on process fluids, operating conditions and environmental factors. Among the major causes of accidents in liquid and natural gas pipelines there are internal and external corrosion defects. As a pipeline ages, it can be affected by a range of corrosion mechanisms, which may lead to a lowering of its structural integrity and in turn to eventual failure. Clearly, regular inspections of pipelines with state-of-the-art tools and procedures can reduce the risk of any undue accident caused by a lack of unawareness of the integrity of the line. Metal loss is a major integrity threat to oil and gas pipelines. Serious metal loss can lead to pipeline rupture or collapse. Pipeline metal loss is mainly caused by corrosion and erosion, and is strongly dependent on the surrounding environment. Methods for assessing pipelines with corrosion defects have been extensively studied, and popular code-based deterministic methods in the published literature include among the others ASME B31G, modified B31G, RSTRENG, and DNV-RPF101 [10–12]. Equations used in these methods are similar, the main differences being in the defect shape factor and bulging factor. These methods provide the prediction for corroded pipelines by determining the burst pressure using relevant equations. Monte Carlo method, first-order reliability method (FORM), and the first order Taylor series expansion of the limit state functions are the main methods that can be combined with deterministic methods for computing the probability of failure for a corrosion defect. In this way, corrosion propagation model is generated and remaining useful life is predicted. Calculating the corrosion growth rates is an essential part of corroded pipeline integrity management. Corrosion rate can be estimated either through the physicsbased corrosion models or using ILI data.

4 Risk Based Management The common definition of risk is the multiplication of probability and consequence. Thus, to perform risk-based management, operators are called to analyze the causes of risk, to estimate failure probabilities and to perform consequence analysis. For pipeline integrity management, probabilities typically refer to probabilities of pipeline failure due to certain defect growth. The consequences are related to the costs incurred by activities like inspection and maintenance, loss of productivity, damage to the environment and community, etc. There are some preliminary activities to conduct. First threats and consequence need to be identified to calculate risk: the selection of a proper risk assessment model is critical to determine the structural integrity. Second, pipeline segments and existing threats must be prioritized. In this way, the riskiest pipeline segments and threats will

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be inspected and repaired prior to others. Third, suitable mitigation and preventative activities for each threat have to be selected. Finally, cost-effective and appropriate re-inspection and re-assessment interval should be determined. This re-assessment interval must ensure the safe operation of pipelines and the reliability of pipelines should be beyond the predetermined safety threshold.

5 Risk Based Inspection Despite American Petroleum Institute and Det Norke Veritas developed RBI methodology since 1990, RBI is still a developing technology. Various Risk Based Inspection (RBI) methodologies are available in the marketplace, including API 581, each having its own merits and weaknesses [11, 13]. In current industrial practice, the main objective of risk-based studies is to estimate pipeline´s present risk, define the target reliability of each pipeline segment and to determine the pressure containment capacity of the pipeline at the time it was last inspected. This approach can be used to determine and predict factors such as the remaining life capacity of the design or the remaining life to current Maximum Allowable Operating Pressure. However, it is difficult to accurately predict the inspection planning time, including the risk level during operating time. RBI is a method for using risk as a basis for prioritising and managing the effort of an inspection program to rationally allocate inspection resources. The term of “inspection” is understood as a systematic procedure used to assess equipment technical conditions. It is usually performed on a fixed periodical basis. In an operating plant or installation, a relatively large percentage of risk is associated with a small percentage of the equipment items. Typically, about 80% of risk of equipment’s failure is associated with only 20% of equipment. RBI allows shifting inspection and maintenance resources to provide a higher level of coverage on the high-risk items and an appropriate effort on lower risk equipment. The RBI method defines the risk of operating equipment as the combination of two separate terms: the likelihood of an undetected failure and the consequence of such a failure. The assessment of failure consequences follows these steps: • scenarios definition in which failure (i.e.: leak) progresses into undesirable events • estimation of the physical effect of each scenario • adverse effect on people, equipment, environment, productivity as a result of the outcome. The likelihood of failure assessment takes into consideration such criteria as: • the damage mechanisms applicable to the analysed item; • the inspection history of the item; • the effectiveness of the previous inspection.

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The detailed method to assess consequence and likelihood depends directly upon the facility type. Furthermore, the level of detail of the method is fitted to the future use of the result, the available data for the analysis, the need of accuracy of the result: a range of probability/consequences or a formal probability/consequences. The Risk Based Inspection approach helps to determine inspection and corrosion monitoring scope from understanding of corrosion threats, extent, locations and optimized inspection cycle for static equipment based on susceptibility to failure, the health, safety, environmental and economic risks of its operation and remnant life of the equipment. It is applicable to static equipment such as process piping, pressure vessels, heat exchangers, above ground storage tanks and pressure relief devices, boilers and heaters. It takes into account only degradation mechanisms related to the operation of an installation (corrosion, fatigue, etc.).

6 Risk Analysis The risk in RBI is defined as the likelihood of failure (POF) times the consequence of failure (COF), so the essential element of RBI methodology is an assessment of the POF and the COF, i.e. hazardous, environmental and production loss. The equation for risk calculation is showed as following: Risk(t) = Pf (t) × COF

(1)

where the POF (Pf (t)) is a function of time, and increases as the damage in the component due to thinning or other damage mechanisms accumulate with time. The implementation of RBI starts with a clear objective and scope of equipment to be assessed within agreed boundaries in the facility. Depending on the nature of the process and the detail of the study, a risk analysis may include thousands of different scenarios. The risk analysis would evaluate both the likelihood and the consequence of the set of events in each scenario. The RBI programme is not a full risk analysis, but a hybrid technique between risk analysis and mechanical integrity. In its elemental form, a risk analysis is comprised of six tasks: (i) (ii) (iii) (iv) (v) (vi)

Identification of accident scenarios involving failure of the equipment; Identification of potential deterioration mechanisms and modes of failure; Assessment of the probability of failure from each mechanism/mode; Assessment of the consequences resulting from equipment failure; Determination of the risk from equipment failure; Risk ranking and categorization.

There are various related but different approaches to RBI analysis. Basically, there are three analytical levels: qualitative, semiquantitative and detailed quantitative.

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In a Qualitative analysis the LOF is evaluated from the influencing factors, such as amount of equipment, possible damaged mechanisms, effectiveness of inspection, current equipment conditions, and the nature of the process and equipment design. The risk level of each equipment can be identified by the likelihood category and the consequence category. The risk results can be used to locate areas of potential concern and to decide which portions of the process unit require the most inspection attention or other methods of risk reduction. It can also be executed to determine whether a full quantitative study is justified. In addition to the qualitative RBI method, the semiquantitative method takes account of the inspection results, such as corrosion rate, historical records, and maintenance information, and so on. Under certain circumstance, the method can alleviate the discrepancies in risk assessment induced by a person with subjective judgments. According to the potential losses, the quantitative method could determine risk levels. The LOF is the generic failure frequency (GFF) for the specific type of equipment, which is based on a compilation of available equipment failure histories from various industries, and multiplied by an equipment modification factor and management system evaluation factor. The COF can be assessed with the losses, i.e. hazard, environment, impact on business interruption and maintenance expense, etc. Therefore, the calculated quantitative risk calculation can directly assist the inspector to evaluate the risk exposures.

7 Risk Based Approaches Talking about the risk assessment as part of an RBI study, basically three approaches are possible: • Qualitative • Semiquantitative • Quantitative. Since the late 1980s, numerous quantitative, semiquantitative, and qualitative models have been developed to aid plant engineers with the prioritization of components inspections.

7.1 Qualitative Approaches Qualitative risk index approaches assign subjective scores to the different factors that are thought to influence the probability and consequences of failure. These scores are then combined using simple formulas to give an index representing the level of risk. Risk index approaches provide a ranking of the different process components based on the perceived level of risk estimated. The ranking obtained by using these methods is highly subjective. In addition, these approaches do not provide any indication of

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whether the risk associated with a component is unacceptable and consequently no guidance is provided regarding whether any risk reduction action is necessary.

7.2 Semi-quantitative Approaches In addition to the qualitative RBI method, the semiquantitative method takes account of the inspection results, such as corrosion rate, historical records, and maintenance information, and so on. Under certain circumstance, the method can alleviate the discrepancies in risk assessment induced by a person with subjective judgments. These approaches provide a tool to ascertain that the estimated risk of failure satisfies a predetermined acceptance criterion. Depending on the level of risk for each mode and pattern of failure, the required analysis, inspection, maintenance, and repair tasks are selected. For example, a review of historical failure databases indicates that the major failure modes in a pipeline are internal corrosion and external impact. Thus, the main efforts (in terms of design, structural modeling, inspections, etc.) should be focused on these failure modes.

7.3 Quantitative Approaches These approaches determine the level of risk based on direct estimates of the probability and/or consequences of failure. Current quantitative risk assessment approaches focus on a single aspect of the consequence associated with failure. Published studies deal with either loss of life risk or economic risk. Integration of environmental damage, life safety, and economic risks has not been addressed adequately. Another limitation of quantitative risk assessment approaches is that they typically base the failure probability estimates on historical failure rates. Publicly available databases do not usually allow subdivision of the failure data according to the attributes of a specific process component and where adequate subdivision is possible, the amount of data associated with a particular attribute set is very limited because of the rarity of the failures. Failure probabilities estimated from public data are, therefore, not sufficiently specific to represent a given failure in a specific process component.

8 Conclusions An Oil and Gas Facility has integrity when it is operated and maintained so that the combination of the likelihood of failure and the consequence of failure makes the risk to people, to the environment, and to the company as low as reasonably practical.

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The primary objective of Asset Integrity Management (AIM) is to maintain the asset in a fit-for-service condition while extending its remaining life in the most reliable, safe, and cost effective manner. In addition to regulatory and company requirements, operators of facilities and related pipelines have the following business needs: maximizing production, reducing lost income due to unplanned shutdowns, optimizing inspection and maintenance costs, maximizing asset value, maintaining an auditable system. Asset integrity is managed at each stage of the asset lifecycle, including project design, asset operation and decommissioning. Inspections, auditing/assurance and overall quality processes are just some of the means to execute an effective integrity management program. Nowadays, AIM programs are deployed to meet API-580, API-581 requirements. To successfully implement an asset integrity management system in a dynamic operating environment, it is essential that all stakeholders have a consistent and a unified understanding of what the essentials of asset integrity are and how they can be applied in their day-to-day operations, yet this is often cited as among the most significant challenges in achieving an integrity culture within an organization.

References 1. ASME B31G: Manual for determining the remaining strength of corroded pipelines. A supplement to ANSI/ASME B31G Code for Pressure Piping (1991) 2. DNV: Corroded pipelines recommended practice. Det Norske Veritas, RP-F101 (1999) 3. Loureiro, J.F., Netto, T.A., Estefen. S.F.: On the effect of corrosion defects in the burst pressure of pipelines. In: Proceedings of the 20th International Conference on Offshore Mechanics and Arctic Engineering, Rio de Janeiro, Brazil (2001) 4. Benjamin, A.C., Freire, J.L.F., Vieira, R.D., Castro, J.T.P.: Burst tests on pipelines with nonuniform depth corrosion defects. In: Proceedings of the 21st International Conference on Offshore Mechanics and Arctic Engineering, Oslo, Norway (2002) 5. Cronin, D.S., Pick, R.J.: Prediction of the failure pressure for complex corrosion defects. Int. J. Press. Vessels Pip. 79, 279–287 (2002) 6. Choi, J.B., Goo, B.K., Kim, J.C., Kim, Y.J., Kim, W.S.: Development of limit load solutions for corroded gas pipelines. Int. J. Press. Vessels Pip. 80, 121–128 (2003) 7. Netto, T.A., Ferraz, U.S., Estefen, S.F.: The effect of corrosion defects on the burst pressure of pipelines. J. Constr. Steel Res. 61, 1185–1204 (2005) 8. Belachew, C.T., Ismail, M.C., Saravanan, K.: Capacity assessment of corroded pipelines using available codes. In: Proceedings of the NACE East Asian and Pacific Regional Conference and Exposition, Kuala Lampur (2009) 9. Winston Revie, R.: Oil and Gas Pipelienes—Integrity and Safety Handbook, 2nd edn. John Wiley & Son Inc., New York (2015) 10. Fu, B.: Advanced engineering methods for assessing the remaining strength of corroded pipelines, ageing pipelines, optimising the management and operation: low pressure—high pressure. In: IMechE Conference Transactions 1999–8 (C571), Institution of Mechanical Engineers, Newcastle upon Tyne, UK (1999) 11. Bjørnøy, O.H., Marley, M.: Assessment of corroded pipelines/past, present and future. In: Eleventh International Conference on Offshore and Polar Engineering (ISOPE 2001). Stavanger, USA (2001)

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12. Stephens, D.R., Francini, R.B.: A review and evaluation of remaining strength criteria for corrosion defects in transmission pipelines. In: Proceedings of ETCE/OMAE 2000 Joint Conference on Energy for the New Millennium, New Orleans, LA, USA (2000) 13. Bai, Y., Bai, Q.: Subsea Pipelines Integrity and Risk Management, 1st edn. Elsevier, MA, USA (2014)

A Model of a System for Gas Transmission Pipeline Integrity Monitoring Vasyl Chekurin, Roman Kushnir, Yuriy Ponomarev, Myroslav Prytula, and Olga Khymko

Abstract The model of the software system for monitoring the integrity of the linear part of a gas main pipeline is considered. The pipeline is considered to be a linear structure formed by series-connected compressor stations and sections of the linear part. The structure model of a section consists of sequentially connected line and nodal elements. The nodal elements represent the technological objects of the linear part, which create small pressure drops between their inputs and outputs. Mathematical models of gas motion through such elements contain ordinary timedependent differential equations. Gas flow through the line elements is described by partial differential equations, which depend on the spatial coordinate and time. According to this model, the integrity monitoring system of the linear part consists of the integrity monitoring systems of all objects represented by both linear and nodal elements. An object integrity control systems include sensors of informative parameters, logging systems, monitoring database, mathematical models and object integrity checking algorithms, data exchange subsystem and information security subsystem. Keywords Integrity monitoring · Leakage detection · Flow parameters monitoring · Transient flow simulation · Acoustic emission

V. Chekurin (B) · R. Kushnir National Academy of Sciences of Ukraine, Pidstryhach Institute for Applied Problems of Mechanics and Mathematics, Lviv, Ukraine e-mail: [email protected] Y. Ponomarev · M. Prytula Joint-Stock Company “Ukrtransgas”, Research and Development Institute for Gas Transportation, Kharkiv, Ukraine O. Khymko Lviv Polytechnic National University, Lviv, Ukraine © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_8

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1 Introduction Gas main pipelines (GM) are effective means for transporting natural gas over long distances. The high efficiency of GM is achieved by the use of large diameter pipes and the maintenance of high gas pressure by means of compressor stations (CS). In such circumstances, the uncontrolled depressurization can have negative effects threatening to both humans and the environment. Therefore, the technological facilities of GM, in particular such as CSs gas distribution stations, transitions through natural and artificial obstacles, are classified as objects of high hazard [1]. The reliability of GM’s technological facilities will inevitably decrease over long operation periods. A considerable part of the Ukrainian GM has already exhausted projected terms of operation. Maintenance and scheduled repairs maintain the reliability of the GM facilities within certain limits. However, there are threats of disruption the integrity of the GM’s technological facilities and the associated risks of environmental and human hazards as well as of material losses. Continuous integrity monitoring reduces the likelihood of an uncontrolled violation of pipelines integrity. This is consistent with regulatory documents of Ukraine [2, 3] and current approaches to managing the integrity of pipeline transportation systems [4]. The model of the software system for integrity monitoring of the linear part (LP) of GM, and corresponding mathematical models, methods and algorithms are considered in the paper.

2 The Model of the System for the Linear Part Integrity Monitoring GM is a set of two components—LP and compressor stations. CSs divide GM into separate sections 120–150 km long. Therefore, we will consider GM as a structure of series-connected compressor stations CSλ and sections Sλ , λ = 1, 2, . . . , N (N is the number of the section): GM = [CS1 , S1 ; CS2 , S2 ; · · · ; CSN , SN ; CSN+1 ],

(1)

LP includes the line valve stations, takeoff nodes, transitions through natural and artificial obstacles, etc. The line valves are installed in the LP’s sections every 25–30 km, on both sides of the transitions through obstacles, at takeoff nodes. On this basis, we will consider any section Sλ as a linear structure formed by successively connected nodal (NE) and line (LE) elements:   Sλ = N E λ,1 , L E λ,1 ; N E λ,2 , L E λ2 ; . . . ; N E λ,Nλ , L E λ,Nλ ; N E λ,Nλ +1

(2)

Here N E λ,k , k = 1, 2, . . . , Nλ + 1 and L E λ,k , k = 1, 2, . . . , Nλ stand for node and line element correspondingly, Nλ is number of the linear elements in the section.

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The line elements are segments whose length is much greater the pipe diameter. The mathematical model of gas flow through them contains partial differential equations depending on the spatial coordinate and time. Such objects have high hydraulic resistance and create considerable pressure drops between their ends in operation. Mathematical models of gas motion through nodal elements contain ordinary time-dependent differential equations. Their hydraulic resistances are low, so they do not create considerable pressure drops between their inlets and outlets. We also include to the nodal elements the segments, in which corrosion defects were detected with the in-line inspection or other non-destructive methods of diagnostics. According to the model (1), the system for integrity monitoring (GMIM) links in its structure the systems for integrity monitoring of all compressor stations CSλ , λ = 1, 2, . . . , N +1 and all LP sections Sλ , λ = 1, 2, . . . , N (Fig. 1). Here the denotations are used: CC is the control computer, CSIM is the system for a compressor station integrity monitoring, LPIM is the system for LP section integrity monitoring, PIDB is the main pipeline integrity database, CS is the communication subsystem, IS stands for the information security subsystem. PIDB collects the data about integrity status of all compressor stations and sections of the GM. It also stores information about GMIM information security. Next, we will focus on the system for integrity monitoring of the LP’s objects. The system for integrity monitoring of the LP’s section includes object integrity monitoring systems (OIM) for all section’s technological facilities both represented by line and nodal elements. Figure 2 shows the structure of OIM. It includes the control computer (CC), the system for informative parameters monitoring (IPM), object integrity checking algorithms (OICA), the object database (ODB), communication (CS) and information security (IS) subsystem. System IPM contains the sensor devices (SD), the data logging (DL), and object operative database GMIM

CC

PIDB

LPIM

CSIM

CS

IS

Fig. 1 The structure of the system for main pipeline integrity monitoring

OIM

CC

IPM

SD

OICA DL

ODB

MMP

CS

ODW

OODB Fig. 2 The structure of the system for integrity monitoring of a LP’s object

IS

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(OODB). The object database (ODB) includes a database of mathematical models parameters (MMP) and an object data warehouse (ODW). In ODW, the monitored flow parameters are accumulated with references to the time moments of their receipt. The hardware of the IPM systems, as well as needed components of the communication and information security subsystems can be located on the sites of corresponding NE (in particular on the areas of line valves stations). Other components of the OIM system can be located remotely. Communication between OOBD and the remote OIM system’s components, as well as between the OIM systems and GMIM system can be carried out using native SCADA channels or special connections, such as GSM or satellite channels. Various methods are used to monitor the integrity of the LP’s objects. The corresponding OICA are implemented in the form of software modules and are executed during the operation of the OIM as appropriate application processes (OICP). The IPM system collects data with prescribed frequency and places them into OODB. Here, they are preprocessed and then stored in ODW with binding to the moments of their logging. The stored data are utilized by OICP, which works iteratively, determining the integrity of an object in the current checking period. The integrity status of the object for each checking period is transmitted through communication channels to the GMIM system, which summarizes the information received from the OIM of all objects and determines, on this basis, the integrity status of the GM as a whole.

3 Method for Integrity Monitoring of the Line Elements For line elements, it is proposed to use a method based on monitoring gas flow parameters at inlets and outlets and numerical modeling the flow in real time. Its implementation is based on direct boundary value problems formulated within the model of gas dynamics in a long pipeline. Similar approach knowing real time transient modeling (RTTM) is used for leakage detection and locating in gas pipelines [5].

3.1 Mathematical Model of Gas Dynamics in the Line Elements The line element of LP is a pipeline of constant diameter Dpipe and length L. The mathematical model of gas dynamics contains three partial differential equations. In the absence of leakages, these equations in dimensionless variables have the form ∂ρ ∂j = −Ma · − Ma · ρlM ∂τ ∂ξ

(3)

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  ∂ ∂j dγ Zt = −Ma · − Ma · β|v| j − Ma · lM j p − Ma · ρ Vj + ∂τ ∂ξ Ma 2 dξ   ∂ Z t α ∂v dγ ∂ρu ∂θ = λT − ju − p + Ma · α j + Ma · αβ|v| jv ∂τ ∂ξ ∂ξ Ma ∂ξ dξ ¯ env − θ). − Ma · uρlM + h(θ

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(4)

(5)

Here ρ = D/Dt , j = J/Jt , θ = T /Tt , p = P/Pt , v = V /Vt , u = U/Ut stand for dimensionless flow parameters correspondingly: density, flow density, temperature, pressure, flow velocity, and density of internal energy; D, J, θ, P, V and U are corresponding dimensional parameters; Dt , J t , θt , Pt , V t are typical values of corresponding dimensional flow parameters. Parameters ρ, j, θ, v and u are functions of the dimensionless coordinate ξ = x/L and time variable τ = t/tt ; tt is the typical time period, defined as tt = L/Ct , where Ct stands for typical gas sound velocity, which is determined from the thermal state equation. Dimensionless function γ = γ(ξ) in (4) defines the profile of the pipeline axis in the vertical plane: γ = H (Lξ)/Ht , where Ht = Vt2 /g, g is gravitational acceleration. Parameter β ≡ λ · L/(2Dpipe ) is reduced coefficient of the pipeline hydraulic resistance, where λ is the coefficients of hydraulic resistance, which determines the force of viscous friction in the gas caused by flow velocity gradients in radial directions. In GM, operation modes at which the flow is turbulent are generally used. Under these conditions, coefficient λ depends on the average height of the irregularities of the inner surface of the pipe (roughness) divided by Dpipe , as well as on the Reynolds number Re of the flow [6]. Parameter λT in (5) is the dimensionless thermal conductivity: λT = /t , where t = L Dt Ut Ct /Tt is the typical value of the thermal conductivity coefficient  = (D, T ). The symbol Z t = Z (Dt , Tt ) in (4) and (5) denotes the typical value of the compressibility factor Z = Z (D, T ) that is a constituent of the thermal state equation. Symbol θenv in (5) denotes the dimensionless environment temperature θenv ≡ Tenv /Tt , h is the dimensionless coefficient of convective heat exchange between the gas in the pipe and the environment through the pipeline wall; coefficient α in (5) is defined as α ≡ 2Ut /Vt2 . Three Eqs. (3)–(5) contain six unknown functions: ρ(ξ, τ), p(ξ, τ), j(ξ, τ), v(ξ, τ), u(ξ, τ) and θ(ξ, τ). To make the model closed we complement them by thermal and caloric state equations as well as by the relation. j(ξ, τ) = ρ(ξ, τ) · v(ξ, τ).

(6)

The thermal equation of state establishes a relation between the thermodynamic parameters P, D and T . There are various forms of analytical representation of this equation [7]. We will use one that is based on the correction of the ideal gas model, according to which P = Rg T D (Rg ≡ R/μg , R is the universal gas constant, μg is the molar mass of the gas), through introducing the corrective dimensionless coefficient Z, called compressibility factor. It is considered as a function of the parameters of state density D (or pressure P) and temperature T: Z = Z (D, T ), which

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is established using empirical data. The thermal equation of state in dimensionless variables will look like this p = zθρ.

(7)

Here z = Z /Z t is the normalized compressibility factor being a function z = z(ρ, θ). The caloric equation of state establishes dependence of the specific internal energy U on density D and temperature T: U = U (D, T ). It can be derived by thermodynamic methods with the use of empirical data that determine heat capacity C V = C V (D, T ). The known thermodynamic relation [7] expressing the differential of internal energy U can be used for that. In dimensionless form it can be written as   θ2 ∂z dρ, (8) du = c V dθ + b ρ ∂θ ρ where cV = cV (ρ, θ) is dimensionless heat capacity of the gas, CtV is the typical value of the gas specific heat capacity. Relationship (8) can be treated as the caloric equation of state in differential form. If parameters cV and z are known as functions of ρ and θ, one can integrate the full differential in (8) and obtain the caloric equation in integral form: u = u(ρ, θ). There are known mathematical models for the equations of state such as AGA-8 DC-92 [8], GERG-2004 and GERG-2008 [9], that allow calculating the thermodynamic properties of natural gases with high accuracies. Utilizing relation (6), thermal (7) an caloric (8) equations of state, one can exclude from Eqs. (3)–(5) the functions p(ξ, τ), V (ξ, τ) and u(ξ, τ) and obtain the closed system of governing equations with respect to the key functions ρ(ξ, τ), j(ξ, τ) and θ(ξ, τ). Let denote this system as PDE_Sys.

3.2 The Boundary-Value Problems Mathematical model PDE_Sys can be used to study gas flow by numerical solving boundary value problems. To formulate such problem, the system PDE_Sys must be supplemented by appropriate initial and boundary conditions. The initial conditions (IC) determine the distribution of dimensionless gas density ρ, mass flow j, and temperature θ along the pipeline in the initial time moment: IC: ρ|τ=0 = ρ0 (ξ), j|τ=0 = j0 (ξ), θ|τ=0 = θ0 (ξ), ξ ∈ (0, 1), where ρ0 (ξ), j0 (ξ), θ0 (ξ) are prescribed functions.

(9)

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Further, we will consider the next three sets of boundary conditions (BCI , BCII and BCIII ) that define values of the key functions at the element inlet ξ = 0 and outlet ξ = 1 BCI : ρ|ξ=0 = ρin (τ), ρ|ξ=1 = ρout (τ), θ|ξ=0 = θin (τ), θ|ξ=1 = θout (τ)

(10)

BCII : ρ|ξ=0 = ρin (τ), j|ξ=1 = j out (τ), θ|ξ=0 = θin (τ), θ|ξ=1 = θout (τ)

(11)

BCIII : j|ξ=0 = j in (τ), ρ|ξ=1 = ρout (τ), θ|ξ=0 = θin (τ), θ|ξ=1 = θout (τ)

(12)

Here ρin (τ), ρout (τ), j in (τ), j out (τ), θin (τ), θout (τ) are given functions. In accordance with this, we will consider three boundary-value problems for the system PDE_Sys with initial conditions (9) and boundary conditions (10)–(11): BVPI = {PDEI , IC, BCI }, BVPII = {PDEII , IC, BCI }, BVPI = {PDEI , IC, BCI } (13)

3.3 Method for Numerical Solving the Problems The problems (13) can be solved numerically using the finite difference method. Approximating the differential operators in the right-hand sides of the Eqs. (3)– (5) by the finite differences and taking into account a set of boundary conditions BC ,  = I, II, III one can reduce the problem BVP to the corresponding initial-value problems IVP for non-linear system of 3N − 4 ordinary differential equations dependent of time variable τ: BVP → IVP . Here N is the number of each problem IVP is of the regular grid nodes ξi ∈ [0, 1]. The solution  the set ρ(i) (τ), j (i) (τ), θ(i) (τ), ∀i = 1, 2, . . . , N containing the functions of time presenting the key functions ρ(ξ, τ) of corresponding problem BVP in the grid nodes: ρ(i) (τ) = ρ(ξi , τ), j (i) (τ) = j(ξi , τ), θ(i) (τ) = θ(ξi , τ). The problems IVP can be effectively solved by applying Runge–Kutta methods. In particular, the algorithm RKF-45 is widely used [10, 11]. It provides a forth-fifth precision degree and is present in mathematical libraries of many programming systems, such as C++, Fortran 90, Matlab, GNU Octave, Python, SciLab and so on. Such approach was applied, in particular, in paper [12] to study the transient processes that occur in long gas pipelines when the flow is controlled by boundary conditions BC ,  = I, II, III. Results of numerical experiments conducted in this paper approved the high effectiveness of the approach and its serviceability for realtime simulation of the gas dynamics problems in gas main pipelines.

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3.4 Schemes for Informative Parameters Collection The algorithm monitoring the integrity of the line elements, considered here, is based on the functions of the boundary conditions BC ,  = I, II, III determined from the data of monitoring of the flow parameters at the inlets and outlets of each line elements. Gas pressure P, temperature T and flow velocity V are measured at checkpoints with some frequency. In this way, we obtain the three time series in in in , Temp , Vemp of these parameters on the inlet and other that represent the values Pemp out out out three ones Pemp , Temp , Vemp that represent them at the outlet of the line elements. Parameters P and T can be monitored with the use of the regular pipeline measuring devices. To monitor gas velocity one can use ultrasonic sensors. To provide automatic data monitoring, sensor readings should be periodically collected by DL, and then accumulated in the operative database OODB, which is organized according to the principles of OLTP (Online Transaction Processing) systems [13]. Here, they are being preprocessed and then transmitted to ODW (a component of ODB) with references to the time moments of their logging. Using the data accumulated in ODW, one can obtain time dependent values of in in in out informative parameters at the inlet Pemp (t), Temp (t), Vemp (t), and outlet Pemp (t), out out (i) (i) T (t), Vemp (t), t ∈  of each line element L E λ,k for each period  =  emp t1(i) , t2(i) up to current moment t. Basing on this data, a computational process, implementing the algorithm of integrity checking of the element (OICA), calcuin in lates the corresponding dimensionless functions at the inlet pemp (τ) = Pemp (tt τ)/Pt , in in in in out out θemp (τ) = Temp (tt τ)/Tt , Vemp (τ) = Vemp (tt τ)/Vt and outlet pemp (τ) = Pemp (tt τ)/Pt , out out out θout emp (τ) = Temp (tt τ)/Tt , vemp (τ) = Vemp (tt τ)/Vt of each element L E λ,k . Further, the process, using thermal equations of state (7) and relation (6), calculates the in out out ¯ (i) dimensionless functions ρin emp (τ), jemp (τ) and ρemp (τ), jemp (τ),τ ∈  , where (i) (i) ¯ =  /tt . Obtained dimensionless functions:  in in out out out ¯ (i) ρin emp (τ), jemp (τ), θemp (τ), ρemp (τ), jemp (τ), θemp (τ), τ ∈ 

(14)

are used by the algorithm to check the integrity of the element L E λ,k during the period (i) . The result of this algorithm is stored in the ODW repository as a logical variable I S L Eλ,k , whose values are linked up to the intervals (i) .

3.5 Algorithm for Integrity Monitoring of the Line Elements Let us denote as DS = I, II, III the solutions of corresponding boundary-value problems BVP . The object DS can be treated as an operator reflecting, specific for , a set of four out of six boundary functions (14) into the set of three functions (ρ(ξ, τ), j(ξ, τ), θ(ξ, τ)). For instance, at  = I, we have

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 DS

I in out out ρin emp (τ), θemp (τ), ρemp (τ), θemp (τ) −→ (ρ(ξ, τ), j(ξ, τ), θ(ξ, τ)) We can consider the image DS (ξ, τ) of the operator DS as a vector-function ¯ (i) . The components of this vector defined in the segment ξ ∈ [0, 1] for period τ ∈  are the three functions DS (ξ, τ) = (ρ(ξ, τ), j(ξ, τ), θ(ξ, τ))T of the BVP solution. Using the upper index for the components, one can write this as ρ(ξ, τ) = DS1 (ξ, τ), j(ξ, τ) = DS2 (ξ, τ), θ(ξ, τ) = DS3 (ξ, τ). Only four out of six empirical functions (14) are used in any BVP . Since the solutions DS (ξ, τ) were obtained in the assumption of the integrity of the line element, this allows checking its integrity comparing the obtained solution of BVP to the two empirical boundary functions from the set (14) that were not used in BC . in out Consider the problem BVPI . The boundary data ρin emp (τ), θemp (τ), ρemp (τ), and out out θout emp (τ) are used in the problem BVPI , but jemp (τ) and jemp (τ) are not. Hence we out out can compare the solution DSI (ξ, τ) to the functions jemp (τ) and jemp (τ). This can be made, in particular, in quadratic norm L 2 with the use of the functional: ⎛ ⎜ 1 IF(i) I = ⎝ ¯ (i) 2

(i)

τ2 

in jemp (τ) − DSI2 (0, τ)

2

⎞1/ 2 2  ⎟ out dτ⎠ + jemp (τ) − DSI2 (1, τ)

τ(i) 1

(15) that determines deviation of the solution from the empirical functions. in in out Two pairs of empirical functions jemp (τ), ρout emp (τ) and ρemp (τ), jemp (τ) are not used in the problem BVPII and BVPIII correspondingly, so, we can compare their solutions DSII (ξ, τ) and DSIII (ξ, τ) to these pairs respectively: ⎛ ⎜ 1 IF(i) II = ⎝ ¯ (i) 2

(i)

τ2 

in jemp (τ) − DSI2 (0, τ)

2

⎞1/2

2  ⎟ 1 dτ⎠ + ρout emp (τ) − DSI (1, τ)

τ(i) 1

(16) ⎛ ⎜ 1 IF(i) III = ⎝ ¯ (i) 2

⎞1/2 (i) τ2 

2

2  ⎟ 1 out ρin dτ⎠ + jemp (τ) − DSI2 (1, τ) emp (τ) − DSI (0, τ) τ(i) 1

(17) Let ¯ I F > 0 be a total mean square inaccuracy of solutions DS (ξ, τ),  = I, II, III. Parameters I F includes the measurement inaccuracy of empirical functions (14) used as boundary data in the problem BVP , and the calculation inaccuracy has been arisen during solving the problem. Then, if the values of the functionals L E λ,k do not exceed I F , one can assert that the assumption made about the integrity

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of line element L E λ,k is true. Proceeding from this, we formulate the criterion: line element L E λ,k can be considered as undamaged during the time period (i) if the condition is satisfied. 

(i) (i) , IF , IF (18) max IF(i) I II III ≤ I F where IF(i)  ,  = I, II, III are determined by the formulas (15)–(17). Criterion (18) enables to monitor the integrity of the line elements exploiting the data of flow parameters values monitoring in the control points and the numerical solutions of the boundary-value problems BVP . A computational process OICP (Object Integrity Checking Process), executing the algorithm OICA, monitors the integrity of a line element in real-time. It works cyclically, checking on each iteration the integrity of the element at a next interval (i) . in/out in/out in/out Each iteration includes the steps: (1) selecting the data Pemp (t), Temp (t), Vemp (t) (i) (i) (i) from the warehouse ODW for period  , such, that t2 ∈  corresponds to the last record in ODW at the current moment; (2) calculation the dimensionless functions in/out in/out ¯ (i) ρin/out emp (τ), jemp (τ), θemp (τ), τ ∈  ; (3) solving the problems BVP  = I, II, III; (4) calculation the values of the functionals IF(i)  ; (5) checking integrity criterion (18); (6) if the criterion condition is satisfied, then logical value TRUE is assigned to a variable IS (Integrity Status), in another case the variable get value FALSE; (7) the current value of the variable IS is stored in the warehouse ODW with link to time period (i) . After that, the process is going back to step 1. The process runs until it is interrupted by one of scheduled events. Depending on the duration of the periods (i) and the execution time of a single OICP iteration, neighboring intervals (i) can overlap. Due to this, the reliability of the monitoring will be risen. To monitor the integrity of line elements in section Sλ , λ = 1, 2, . . . , N , a computational processes O I C PL Eλ,k , checking the integrity of elements L E λ,k , k = 1, 2, . . . , Nλ , are running parallel. They form the computational process Nλ O I C PL Eλ,k for integrity monitoring of line elements of the section OICPSLλE = k=1 N LE Sλ . Collection OICPGM = λ=1 OICPSLλE forms the process for integrity monitoring of line elements in the gas main pipeline GM.

4 Method for Monitoring the Integrity of the Nodal Elements The majority of leaks in MPs occur in the piping equipment such as valves and other shut up and control fittings, i.e. – in objects that we categorize as the nodal elements. Usually, the intensity of such leaks is rather small and they create slight perturbations of flow parameters, which are often insufficient to detect leaks using

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the method considered in the previous section. To control the integrity of the nodal elements, we propose to use acoustic emission waves. The leakage of gas through a small opening in the wall runs under significant pressure difference. Therefore, the flow through the hole is turbulent. As a result, a wave process, called acoustic emission, springs up. The waves, propagating from the place of depressurization, can be detected by acoustic emission sensors (AES). This can be used to detect the leakage in the element to register its integrity violation. The method for leaks detection using AE sensors installed on the surface of an object is described, in particular, in document ASTM International [14]. Article [15] presents the results of a practical application of the AE method for the detection of leaks in underground pipeline sections, transitions through rivers, dams, railway tracks, and highways. It has been established by these studies that for continuous monitoring of the pipeline the AE sensors should be installed at distances of 100– 200 m. This means that the AE method can be used to monitor the integrity of pipeline objects of the corresponding length.

4.1 Schemes for AE Data Logging Let consider schemes for collecting data for AE integrity monitoring of nodal elements, such as valve stations, transitions through natural and artificial obstacles, pipe segments, containing corrosion defects, which have been detected by in-line pipeline inspections, etc. Considering ways for data collection for the AE method, we will distinguish two kinds of the nodal elements: objects, which have parts that protrude above the ground, and fully buried objects. Figure 3 shows a schema of AES installation on a buried line valve with the bypass piping arrangement and blow-off pipe, which protrude above the ground. Disposition of the AES enables detecting leakages from the buried line valve, connections of the inlet and outlet pipelines to crane housing as well as from three overground valves. Similar schemes can be used to collect data from partly buried tube pieces, as for instance, those containing corrosion defects reducing the pipe strength. Figure 4 shows schemes for data collection from a buried tube. This can be a transition through an obstacle or a piece of pipe with defects. By the scheme (a) the AES is mounted directly on the outer surface of the buried tube. The scheme (b) shows the case, when waves of acoustic emission are transmitted outwards by the waveguides. One end of each waveguide is established on the outer surface of the buried tube. Another one is protruding above the ground. AESs are mounted on their surfaces. The sensor outputs are fed to the inputs of the multi-channel acoustic emission logger. Here, the signals are processed, digitalized and then transmitted to ODW.

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AES

Fig. 3 Chart of AES mounting on overground part of a valve node

to DL

to DL Dual-channel AE signal processor

AES

Waveguides

Damaged pipeline section a)

Dual-channel AE signal processor

AES

Damaged pipeline section b)

Fig. 4 Chart for AE data logging from a damaged pipeline section with AES mounted: a on the pipeline surface, b on the waveguides

4.2 Algorithm for Leakage Detection The leak detection method is based on the analysis of the output signals of AES and detection of informative signs caused by acoustic emission. In the bodies of monitoring objects, elastic waves of various origins exist. Besides the acoustic emission waves, here can spread vibrations evoked by the operation of the compressors, noise caused by gas flowing in the pipeline, oscillation caused by random fluctuations of gas pressure and temperature, etc. Hence, the AES output signals will contain various components. However, these components distinguish by their amplitude and frequency characteristics. According to the literature data [14,

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16], the spectrum of AES lies in the frequency range of 30–100 kHz. Moreover, if the AES is mounted close enough to the source of the acoustic emission, then the AE constituent in the output signal will have the highest amplitude. Based on this, a method for selection of the acoustic emission component in the AES output signals is proposed. According to the method, the sensors are installed at distances of up to 200 m from the place of possible depressurization, and their output signals u S (t) are logged in the frequency range 30–100 kHz. To detect the leak and determine the moment of depressurization, successive segments u (i) S (t), t ∈ (i) , i = 1, 2, . . . of the output signals u AE S (t) are analyzed. The segments are being selected from the output signal by the sliding window on successive time intervals (i) = t1(i) , t2(i) of a fixed aperture  = t2(i) − t1(i) . The value of  is defined empirically with the use of computational and physical experiments. Further, the mean square value of output signal for each interval (i) is calculated:

U¯ S(i)

    = 

(i)

t2

1 t2(i)

−

t1(i)

 2 u (i) (t) dt

(19)

t1(i)

In the absence of leakage, the output of the AES signal is low, so the condition (i) ¯ is satisfied U¯ AE S ≤ U0 , and at the moment of depressurization the signal level will (i) ¯ increase, so we will have U¯ AE S > U0 . Here U 0 is the upper edge for mean square values of AES signal in the absence of leakage. It can be determined empirically based on the data of AES output signal measuring during the operation of the object in the absence of leaks. The moment of depressurization is determined by finding two consecutive inter(i−1) ¯ ¯ (i) ¯ vals (i−1) and (i) , on which the condition U¯ AE S ≤ U0 and U AE S > U0 are correspondingly satisfied. Intervals may be chosen overlapped each other. It can increase the robustness of the method and precision of depressurization moment determining. According to this, the algorithm for a nodal element integrity monitoring includes (i) (i) (i) the steps: (1) selecting from ODW a segment u (i) AE S (t), t ∈  , in which t2 ∈  corresponds to the last (for current time) record in the database; (2) calculating by (i) (i) ¯ (i) formula (19) mean-square value U¯ AE S of the segment U AE S on interval  ; (3) (i) (i) comparing U¯ AE S to prescribed value U 0 : if the condition U¯ AE S ≤ U¯ 0 is satisfied, then logical value TRUE is assigned to variable IS, in another case value FALSE is assigned to IS; (4) writing variable IS to the database ODW with binding to interval (i) ; (5) comparing values of variable IS for two consequence intervals (i−1) and (i) : if I S (i−1) = T RU E and I S (i) = F AL S E, then depressurization of the nodal element under monitoring has occurred on interval (i) \(i−1) .

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4.3 Algorithm for Determining the Depressurization Site After the leakage has been detected its location can be determined. This is important, in particular, in the case when a piece of a buried pipe, containing several defects distributed along its length, is monitored (see Fig. 4). As an example, we consider here an algorithm based on cross-correlation of the signals of two AES [17]. After depressurization, both sensors, located at opposite ends of the monitoring element, generate continuous signals u 1 (t) and u 2 (t). We determine the (i) cross-correlation function ρ(i) 12 of the signals calculated for the time interval  , as (i)

ρ(i) 12 (τ) =

t2

1 t2(i)

−

t1(i)

(i) u (i) 1 (t + τ)u 2 (t)dt

(20)

t1(i)

 Supposing that the value τ(i) = arg supτ ρ(i) 12 (τ) of the cross-correlation function’s argument, which corresponds its maximal value, determines the difference of acoustic wave traveling times of the distances x L and L − x L (see Fig. 5), we obtain xL =

L − cτ(i) 2

(21)

The algorithm for determination of the depressurization site on a buried pipeline with the use of two AES, mounted at the opposite ends of the monitored section of length L, starts after the leakage has been detected. It executes in real time and includes the next steps: (1) synchronous logging the signals of the sensors on successive time intervals (i) , digitizate them and accumulate in the database OWB with binding to (i) (i) from interval (i) ; (2) retrieval the functions u (i) 1 (t) and u 2 (t) for next interval  (i) OWB and calculation cross-correlation

 function ρ12 by formula (20); (3) calculation

(i) (i) time delay τ(i) = arg supτ ρ(i) 12 (τ) between signals u 1 (t) and u 2 (t); (4) calculate the location of the depressurization site by formula (21). Comparing values x L obtained in such a way for several time intervals . . . , (i−2) , (i−1) , (i) , one can reduce errors in x L determination, caused by the noise and random fluctuations, and improve the precision of leakage location.

Fig. 5 To determination of the depressurization site

AES1

AES2

xL

L

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5 Conclusion An approach to integrity monitoring of the linear part of a gas main pipeline has been proposed. For that, a section of a gas main pipeline between two compressor stations is considered as the structure of sequentially connected line and nodal elements. The line elements are long pipes, in which gas flow is described by the nonlinear system of partial differentials equations depending on the spatial coordinate and time variable. The nodal elements are considered as systems of lumped parameters, in which gas dynamics is described by the nonlinear system of ordinary differential equations depending on the time variable. Different methods are considered to monitor the integrity of the line and nodal elements. Numerical modeling non-stationary gas flows in the line elements in realtime and empirical data obtained by measuring flow parameters at their inlets and outlets are proposed to use in common to monitor these elements’ integrity. Signals of several acoustic emission sensors, mounted on the surfaces of the nodal elements, are proposed to monitor the integrity of these elements. Corresponding schemes for data collection and algorithms of their processing are developed to check the integrity of the elements of both types. The developed approach can be used to create the system of integrity monitoring the linear part of the gas main pipeline as a substantial constituent of its integrity management system.

References 1. State committee of Ukraine on industrial safety, labor protection and mining supervision “Safety guidelines for main gas pipelines operation”, https://zakon.rada.gov.ua/laws/show/ z0292-10#o37, last accessed 2020/03/08 (in Ukrainian). 2. Law of Ukraine “On high-risk facilities”, https://zakon.rada.gov.ua/laws/show/2245-14, last accessed 2020/03/08 (in Ukrainian). 3. Cabinet of Ministers of Ukraine “On identification and declaration of safety of objects of increased danger”, https://zakon.rada.gov.ua/laws/show/956-2002-p, last accessed 2020/03/08 [in Ukrainian]. 4. Mora, R.G., Hopkins, P., Cote, E.I., Shie, T.: Pipeline Integrity Management Systems: A Practical Approach. ASME Press, US (2016) 5. Geiger, G.: State-of-the-art in leak detection and localization, https://www.researchgate.net/ publication/290631637_State-of-the-art_in_leak_detection_and_localization, last accessed 2020/03/08. 6. Gerhart, P., Gerhart, A., Hochstein, J.: Munson, Young and Okiishi’s Fundamentals of Fluid Mechanics, 8th edn. Willey, E-Book (2018) 7. Anderson, G.: Thermodynamics of Natural Systems, 2nd edn. Cambridge University Press, New York (2005). 8. Farzaneh-Gord, M., Khamforoush, A., Hashemi, S., Namin, H.: Computing thermal properties of natural gas by utilizing AGA8 equation of state. Int. J. Chem. Eng. Appl. 1(1), 20–24 (2010) 9. Kunz, O., Wagner, W.: The GERG-2008 wide-range equation of state for natural gases and other mixtures: An expansion of GERG-2004. J. Chem. Eng. Data 57, 3032–3091 (2012) 10. Hairer, E., Norsett, S.,Wanner, G.: Solving Ordinary Differential Equations I Nonstiff Problems, 2nd edn. Springer (1987).

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11. Hairer, E., Norsett, S.,Wanner, G.: Solving Ordinary Differential Equations II Stiff and Differential-Algebraic Problems, 2nd edn. Springer (2002). 12. Chekurin, V., Khymko, O.: Numerical modeling transient processes in a long gas pipeline. Math. Model. Comput. 6(2), 220–238 (2019) 13. Bog, A.: Benchmarking Transaction and Analytical Processing Systems: the Creation of a Mixed Workload Benchmark and its Application. Springer, Heidelberg (2014) 14. ASTM E1211/E1211M—17 Standard Practice for Leak Detection and Location Using SurfaceMounted Acoustic Emission Sensors, https://www.astm.org/Standards/E1211.htm. 15. Kourousis, D., Bollas, K., Anastasopoulos, A.: Acoustic Emission Leak Detection of Buried Oil Pipelines, River and Road Crossings, https://www.ndt.net/article/ecndt2010/rep orts/ 1_07_01.pdf, last accessed 2020/03/08. 16. Brunner, A., Barbezat, M.: Acoustic emission leak testing of pipes for pressurized gas using active fiber composite elements as sensors. J. Acoust. Emission 25, 42–50 (2007) 17. Knapp, C.H., Carter, G.C.: The generalized correlation method for estimation of time delay. J. Sound Vib. 24, 320–327 (1976)

The VERNE System for Underwater Test of Pipeline Integrity G. Nardoni, D. Nardoni, and M. Bentoglio

Abstract The problem of corrosion evaluation of subsea pipes after many years under water is a real problem for many companies operating in the oil and gas business. The European Union research action in the frame of the new research program Horizon 2020 has developed a project to monitor deep subsea tube with guided wave manipulated by a Remote Operating Vehicle (ROV). The paper summarizes the main points of the program, the experimental tests, the sensitivity of the system. The target is also to prepare a white paper document to present to ISO for a norm draft, as a specific EU request. The project is at its final stage after the satisfactory tests in the laboratories of I&T NARDONI INSTITUTE in Brescia and at Dacon in Oslo. The final test is scheduled on end of February in OSLOFJORD. VERNE has been presented in the most important exhibition as OTC 2019 Houston, OMC Ravenna, AIPND BIENNALE NDT CONFERENCE Milano 2019 EGYSP 2020 Cairo. Oil&Gas companies have expressed great interest for VERNE being an alternative to intelligent PIG Inspection, only possible from the inside of the pipe, while not all pipelines are inspected for different reason from the inside. Keywords Oil&gas · NDT inspection · Guided waves · Ultrasonic · H2020 European project

1 Introduction The VERNE system is at the moment the first prototype of ultrasonic technique to test the corrosion of underwater pipelines from the sea side. The peculiarity of this technique is that the examination can be made from the seaside, placing the 96 piezoelectric transducers on the outside surface of the pipe. Three immediate advantages arise applying this technique: G. Nardoni (B) · D. Nardoni · M. Bentoglio I&T Nardoni Institute Srl, Brescia, Italy e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_9

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Fig. 1 The physical principle of the ultrasonic guided waves

• The full section of the pipe can be examined for corrosion evaluation or transversal serious damage in the pipe or in the welding in one shot. • Inspection of the pipelines can be performed in any moment without interruption of the oil or gas transmission. • There are pipelines were the intelligent pigs can not be applied from the inside of the pipe due to different factors consequently VERNE system can do.

2 Ultrasonic Technique The applied technique for the VERNE system is the guided waves technique. This technique uses a type of ultrasonic waves called guided waves (GW) which are ultrasonic waves with wavelength comparable with the thickness of the plate in which these are generated. This is the only technique where the reflection can be either due to the change in the velocity in the corroded area, because the reduction in thickness of the wall, or due to the change of the material density in the interface of the discontinuity (Figs. 1 and 2).

3 The Clamp The clamp (Fig. 3) is the heart of the VERNE system. Its project starts with a brainstorming among the engineers of the research team of the EU VERNE Project. Many factors have to be considered good contact of the transducers to the pipe, the centring, the weight, the corrosion problem, the isolation of the electrical parts, the software, the more conductivity of the salt water, the entanglement of the VERNE system with the ROV (Remote Operation Vehicles) and many other factors. From the drawing to the first test for more than one year of intensive work on real samples from 12 m up to 50 m length. In Figs. 3 and 4 the presentation of the clamp in its final configuration.

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Fig. 2 The modes of vibration of the pipe when crossed by guided waves

Fig. 3 The clamp in the close position; the yellow ring covering is floating material to reduce the weight of the clamp on the ROV arm

4 Engineering Request on Critical Corrosion Level Many meetings, with the engineering responsible of the maintenance of pipelines (Saipem, Eni, BP, Chevron and more), have been conducted during the presentation of the system at the main oil and gas conferences and exhibitions.

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Fig. 4 The full system clamp-ROV in operating position

The request as detection probability was for a minimum value of reduction area of 20%; based on this value sample from 12 m up to 50 m have been realized. Reduction areas of 2.5, 5, 10, 15 and 20% have been tested.

4.1 The First Test Results Below the first laboratory test results are presented. In Figs. 5 and 6 the results of test conducted on 12 m pipe in laboratory are presented. In Fig. 7 the sketch of the 18 m tube with the different reduction areas is presented. Figure 8 the results of test performed on the 18 m tube are presented. All the five reduction areas from 2.5% up to 20% have been detected with different amplitude at different distance. On pipe of 50 m (see Fig. 9), the reduction area of 20% located at 46 m have been clearly detected (see Fig. 10). These tests have been performed onshore with pipe empty and only with the clamp fully immersed in sweet and salt water.

5 Test in Open Sea In a Fiord of Norway test of pipes up to 12 m long have been carried out (Figs. 11 and 12). The scope of the inspection was to verify the influence of full immersed tube on signals. The test demonstrates the full immersion has not significant attenuation of the signal.

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Fig. 5 First test in Dacon Laboratory (Norway) on different value of reduction area 2.5%—5%— 20%—10%

Fig. 6 Only limited indications have been detected with flexural mode. Torsional mode is the most important one in guide waves with the highest POD

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Fig. 7 Drawing of a pipe 18 m long inspected by the VERNE system

Fig. 8 Diagram of indications with clamp located at the extremity of pipe. Result: 5, 10, 15 and 20%. Reduction area is clearly detected; only reduction area of 2.5% is twice the noise

5.1 Operation of the Clamp from the ROV A fully mechanical simulation of all the functions from ROV have been performed: open the clamp, centering the clamp, close the pump, open the pump have been correctly performed in a special tank.

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Fig. 9 Drawing of the 50 m pipe with indicated in red the redaction area. The clamp relative to the diagram of Fig. 9 has been positioned at the end of the pipe

Fig. 10 Diagram of the pipe of Fig. 8, very clear the signal of the welds the average reduction area for each weld is 20% due to the welding cup. The reduction area of 20% at 46 m is indicated in yellow

6 Surface Preparations of Pipes to Inspect The VERNE system is today ready to start its real application on the outstanding pipelines. The pipe surface shall be free of sand and any other heterogeneity that can avoid a good contact of the transducers to the surface on the pipe.

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Fig. 11 The different phases of transportation of the 12 m pipes in Oslofjord. In the left picture it is possible to see the clamp locked on the tube extremity

Fig. 12 Setup of the clamp for the its positioning on the pipe

7 Personnel Qualification for the Examination Two different types of personnel qualification are requested to perform the test: one person for the evaluation of the ultrasonic test according ISO EN 9712 ultrasonic guided waves and a second person qualified to guide the ROV system.

8 Draft for a “Recommended Practice” Most important for the application of VERNE system is to prepare a recommendation for ultrasonic guided wave inspection of underwater pipelines as a basis for a future standard approved by ISO or EN institution. The Authorities involved for this topics have been contacted. RINA, the Italian Shipping Register, has received all the final documentation of the test performed with VERNE. RINA is ready to perform a validation test on the outstanding sample of 18 and 50 m. Based on these results RINA will release an “approval in principles” of the procedure applied. This document represented the first action to present ISO for the starting of the standard.

Detection and Assessment of Defects in Gas Pipelines Vasyl Kostiv, Roman Banakhevych, and Hryhoriy Nykyforchyn

Abstract A case study of the Urengoy–Pomary–Uzhgorod main pipeline inspection in the section between Illintsi and Bar compressor stations is described, and the causes for initiation of longitudinal cracks on the pipe outer surface are discussed. Importance of timely and correct reaction to diagnostic results is shown. Experience of the Joint Stock Company “Ukrtransgaz” in taking measures on optimization of the processes of main gas pipeline repair is shown. It consists in establishing precise terms both for assessment of in-line inspection results and for making repair plans, determination of criteria of defect selection for repair and formation of a common approach to the process, in particular, to technical documentation. The recommendations for the repair, replacement and strengthening of dangerous sections of main gas pipelines are developed basing on the data obtained during the diagnostics and the results of calculations. Regular monitoring of these sections makes it possible to assess adequately their current technical state and allows establishing the expediency of further operation and recommendations for the elimination of detected defects. The system of pipeline integrity control has been introduced into operation by Ukrtransgaz. It is based on currently available geographic information system of certification and technical monitoring of the main gas pipelines and also on the analytical hardware and software system that is constantly being developed and improved. Keywords Gas pipeline · In-line inspection · Nondestructive testing · System of gas pipeline integrity control

V. Kostiv Gas Transmission System Operator of Ukraine LLC, Ivano-Frankivsk, Ukraine R. Banakhevych JSC Ukrtransgaz, BMPD Lvivtransgaz, Lviv, Ukraine H. Nykyforchyn (B) Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_10

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1 Introduction Most of Ukraine’s main gas pipelines (MGP) operate over a fixed lifetime. The evaluation of their current technical state [1–4] and the substantiation of their further safe operation [5, 6] is of strategic and economic importance. To ensure reliable operation of MGP and according to annual diagnostic programs, Ukrtransgaz periodically monitors the technical state of gas pipelines, and since 1996—in-line inspection of MGP. The main task of such inspection is estimation of the actual technical state of the gas pipeline as well as equipment installed in it with the subsequent repair of the identified defects in the gas pipeline to ensure reliable operation of the facility for at least five years. Untimely diagnostic and repair works could lead to more frequent occurrence of failures and emergencies with unpredictable consequences [7]. For the period 1996–2019, more than 16 thousand km of corrosion inspection and 7.2 thousand km of inspection were carried out to identify longitudinal defects of gas mains. It should be noted that to date, the in-pipe inspection of all MGP equipped with intelligent pigs receiving/launching chambers has been carried out. Over this period, more than 31 thousand accidentally dangerous defects were identified and eliminated and a significant number of emergencies were prevented on the linear part of the main pipelines of the gas transmission system of Ukrtransgaz [8]. The in-pipe inspection allowed identifying defects occurred during the pipe production, so-called “manufacturing faults” (slag inclusions, delaminations of pipe metal, etc.); defects formed during pipeline construction (lacks of penetration, pores, dents, cracks, displacements of pipe edges, etc.) due to improper work organization and insufficient qualification of operators; operational defects caused by imperfection of the insulation coating and errors in the maintenance of cathodic protection, high corrosion activity of the environment, etc. [9].

2 Urengoy–Pomary–Uzhgorod Gas Transit Pipeline Inspection An interesting case occurred in 2008 on the Urengoy–Pomary–Uzhgorod DN 1400 gas pipeline operating under internal gas pressure of 7.4 MPa. According to the results of an intelligent pig pass in August 2007 to identify longitudinal defects in the section between Illintsi and Bar compressor stations at 3871.81 km of the Urengoy– Pomary–Uzhgorod gas pipeline (20,259.8 m from the launch chamber, according to ROSEN), a defect was detected there identified as metal loss – a factory anomaly on a longitudinal weld with a depth of 11% of the pipe wall thickness, 454 mm long, 14 mm wide. Figure 1 contains a fragment of the defect passport according to the technical report of the company Rosen [10], which performed the in-line inspection of the gas pipelines of Ukrtransgaz in 2007. During the inspection of this defect by the diagnostic laboratory of BMPD Cherkasytransgaz of Ukrtransgaz using the Einstein-2 ultrasonic flaw detector,

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Fig. 1 The fragment of the defect’s passport from the technical report provided by Rosen [10]

cracking of the pipe metal with a length of 3000 mm and a depth of 1.5 mm was found very close to the pipe weld, as shown in Figs. 2 and 3. This indicates especial susceptibility of welded joint area to operational degradation [11]. Fig. 2 Crack along the welded joint

Fig. 3 Other cracks in the vicinity of the pipe weld

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For a detailed examination of a dangerous section of the main gas pipeline, experts from third-party organizations were involved in order to determine the cause of the formation of longitudinal cracks on the outer surface of the pipe. It has been found that the underground section of the Urengoy–Pomary–Uzhgorod gas pipeline lies in marshland with a groundwater watershed at the level of the lower generatrix of the pipeline. To prevent pipeline surfacing, concrete UBOP-type weights were used, which were mounted on both sides of the pipeline.

2.1 Methods a Subsection Sample The following investigations were performed in the vicinity of the longitudinal weld of the DN 1400 pipe with surface cracks: • visual and optical inspection of the damaged site; • non-destructive ultrasonic testing in order to detect the penetration depth of the crack into the pipe metal; • non-destructive capillary inspection for more detailed identification of sections with cracks appearing on the pipeline surface. Additionally, the following examinations were performed: • electrometric tests of the electrochemical cathodic protection (ECP) of the gas pipeline for determination of the protective and polarization potential; • quality control of the insulation coating; • assessment of the stress state of the metal of the gas pipe in this section; • failure analysis of cracking on the outer surface of the pipeline.

2.2 Inspection Results Visual and optical inspection of the outer surface of the pipe in the vicinity of the longitudinal weld revealed: • a white coating on the metal surface in the lower section of the gas pipeline, under a layer of insulation and primer; • after removing the white coating, on one side of the longitudinal welded joint, stepped layering of the metal pipe surface (made by a metal device) which is located along the entire length of the pipe at a distance of 7 mm from the welded joint. The metal height difference is up to 0.6 mm, and longitudinal marks of 0.5 m are present on the other side of the welded joint; • a crack with a total length up to 3000 mm (in the area of stepped surface layering), which is located along the welded joint and has an intermittent nature and the seepage on the pipe metal; • no corrosion pits or other manifestations of corrosion process.

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Fig. 4 General view of the surface in the process of capillary control

Ultrasonic testing shoved that the crack in the vicinity of the longitudinal welded joint of the pipe in some places has a depth of up to 5 mm. The crack propagates parallel to the longitudinal weld, it is intermittent, directed perpendicularly to the outer surface, with a total length of up to 3000 mm. Capillary inspection of this section in turn revealed (Fig. 4) a number of surface cracks with branched ends with a total length of up to 3000 mm located on the surface of the pipe metal at a distance of 7–15 mm from the longitudinal weld. These cracks tend to merge in the direction along the generatrix of the gas pipeline. Electrometric measurements of the ECP parameters established that the protective polarization potential of the gas pipeline is –1.25 V, that exceeds the requirements of regulatory documents [12] by 0.15 V, and can contribute to delamination of the protective coating. It shoud be noted that overprotection of a pipepine leads also to hydrogen induced cracking [13, 14]. When measuring the potential of the stationary electrode (a metal plate made of steel similar to pipeline steel) in the soil at a distance of 2.5 m from the gas pipeline and 0.05–0.10 m from its wall, a difference of stationary potentials is found between these two points (0.1 V), that thereby indicates the differences in electrolytic solution composition in the soil, namely, the presence of an alkaline medium near the wall of the gas pipeline. Besides, pH of the media (soil and groundwater in the hole) was determined, and the following was found: • soil and groundwater have a neutral reaction (pH 7); • the soil between the gas pipeline and the concrete weight has an alkaline reaction (pH 8.0–8.5); • the medium near the surface of the concrete weight is also alkaline (pH 8.5); • the X-ray inspection of the pipe metal confirmed the results of previous studies and control, which is clearly demonstrated in Fig. 5.

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Fig. 5 Radiographic image of the damaged place

3 Discussion White coating (carbonate film) on the surface of the gas pipeline under the insulation layer indicates the presence of a carbonate-containing medium near the gas pipeline, it is formed as a result of the long-term effect of concrete weights on the soil environment. This is evidenced by the results of electrometric measurements and pH determination of the soil in the areas around the pipe. The formed carbonate film has protective properties against soil corrosion, as evidenced by the non-corroded metal surface. Hovewer during operation, the metal of the gas pipeline is subjected to service stresses, which contribute to the cracking of the carbonate film in the longitudinal direction and the formation of crack-like local anode zones, which in their turn are the origins of stress corrosion cracking [15, 16]. The occurrence of a stepwise layering on the pipe surface and longitudinal lines in the vicinity of the longitudinal weld is explained by improper location of the pipe billet in the mandrel stand during the expansion at the manufacturer. During the operation of the gas pipeline, a local stepwise layering of the pipe surface becomes a concentrator of mechanical stresses of the metal at the annular intersection of the pipe, the designations of which can go beyond the elastic zone of the metal, which is confirmed by stress state studies. These factors determine possible causes of cracking on the outer surface of the pipeline. A more detailed information about the crack initiation can be obtained after the destructive testing. As a result of the performed inspection, the potentially hazardous section of the Urengoy–Pomary–Uzhgorod pipeline located at 3871.81 km was repaired by replacing the defective part using materials that meet the requirements [17]. Taking into accound the inspection results, the following measures have been developed for further safe operation of gas main pipelines: • continuous monitoring of the pipe state at locations of concrete weights in gas pipeline sections of DN 1400 pipes (beam crossings, water accumulation, marshland, etc.); • regular inspection aimed at surface crack detection, replacement of damaged pipes with new ones in accordance with the requirements [17] in places where the combined action of several unfavorable factors are detected; • re-insulation of the gas pipeline sections with identified surface cracks in accordance with the requirements [12];

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• replacement of the concrete weights with similar ones made of another material, or anchors; • taking into account cases of mismatch of defects detected by in-pipe inspections to their real dimension, a special attention should be paid to identification and priority examination of defects located at longitudinal seams of “hot” pipeline sections (within 30 km from the compressor station).

4 Development of Documentation on Pipeline Safety It should be noted that after the case discussed above, a significant work was carried out by Ukrtransgaz in several areas aimed at preventing similar incidents in the future. This work is performed to improve the overall quality of in-line inspection (more stringent requirements, the formation of a working group made of representatives of Ukrtransgaz and the company executing the in-line inspection, etc., expanding the scope of investigations involving other diagnostic methods, more precise analysis of inspection results). Thus, the experts of Ukrtransgaz (including the branch of the Scientific and Technical Center “Tekhdiagaz”), taking into account the experience of other countries [18–20], have developed the Regulation [21] aimed at optimizing the repair process of gas pipelines by clearly setting deadlines for the analysis of the results of technical diagnostics as well as for arrangement of repair schedule; defining criteria for selecting defects for repair, establishing a unified approach to the process. The purpose the Regulation [21] is to provide engineers with instruments to analyze the results of the in-line inspection. It defines the criteria for choosing defects for repair, classifying them according to their priority for additional examination and/or repair, which are given in Table. All present defect parameters for repair are determined based on (i) the analysis of existing regulatory documents; (ii) operating experience (repair, additional flaw detection control, accidents). It should be noted that a number of defect selection parameters for inspection/repair are quite conservative, however in some cases the cost of mistake is too high, in particular at export gas pipelines of Ukraine, so this is a justifiable measure. It is well known that capabilities of in-line inspection tools regarding the detection of stress corrosion cracking are limited. The experience of accidents as well as additional flaw detection control confirmed the discrepancy in the parameters of real defects and those indicated in the in-pipe inspection report. In order to prevent the possibility of ignoring such defects, a specific criterion has been introduced (No. 5 in Table 1).

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Table 1 Criteria for choosing defects for repair detected by the in-line inspection No.

Description

Parameters

1

2

3

1

Anomalies categorized according to [22] as

«Critical» or «Considerable»

2

Anomalies for which the repair ≥0.95 coefficient ERF

3

Anomalies for which the nominal coefficient according to [23]

≤1.05

4

Geometry defect (anomaly of the internal diameter Din —a dent)

Depth ≥ 3.5% of Din

5

External or internal metal loss, or their combination (corrosion, manufacturing defect, construction defect)

Depth ≥50% Longitudinally oriented with a depth of ≥10% near a longitudinal weld (±200 mm) with a length to width ratio (L/W) ≥ 30 and a width of ≤2 h (h is a pipe wall thickness) Transversely oriented with a depth of ≥10% near an annular weld (±200 mm) with a width to length ratio (W/L) ≥ 30 and a length of ≤2 h

6

Annular weld anomaly

Depth ≥50%; or circumferential length ≥ 1/3 > Din

7

Anomaly of a longitudinal weld The length along the weld axis √ ≥2 Din h

8

Corrugations

Wave height > h

9

Crack in a pipe body or in a weld

All defects

10

Delamination at an angle in the All defects near-weld area, delamination with surface egress, delamination with protuberance

11

Defects to be repaired and All defects located in potentially hazardous [24] areas of gas mains

Primary Repair Defects

Defects to be repaired (previous inspection) 12

Anomalies categorized according to [22] as

«Moderate» (continued)

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Table 1 (continued) No.

Description

Parameters

13

Geometry defect (anomaly of the inner diameter) adjacent to a weld (100 mm) or located on it

All defects

14

External or internal metal loss, or their combination (corrosion, manufacturing defect, construction defect)

Depth ≥30% The number of defects with a depth of ≥20% in one section > 0 The number of defects with a depth of ≥10% along a longitudinal weld (±200 mm) in one section >5 Longitudinal defects with a depth of ≥10%, a width of ≤2 h and L/W ≥10 Transversal defects with a depth of ≥10% along an annular weld (±100 mm) with W/L ≥ 10 and a length of ≤2 h; defects with a depth of ≥10% near a longitudinal weld (±200 mm) in sections within 30 km from a compressor station

15

Delamination in the near-weld area (100 mm)

All defects

16

Annular weld anomaly

The total length of a circle ≥1/6 > D in , meta loss with a depth ≥ to 30%

17

Anomaly of a longitudinal (spiral) weld

One defect along the weld axis of >10 mm

18

Corrugations

Wave height > 0.5 h

19

Line Scratch, Scuff

Depth ≥10%

20

Inadmissible structural elements and connecting parts that do not meet the requirements of regulatory documents

All defects

21

Anomaly of an annular weld—planar discontinuity

Depth ≥30%

22

Anomaly of a longitudinal (spiral) weld

Depth ≥30%

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5 Essence of Pipeline Integrity Management System Nowadays, two methodologies are implemented in Ukraine to ensure reliable operation of pipelines: (1) regulatory, in which the periodicity, volumes and means of diagnostic control and repair methods are clearly defined by the standards. However, it is connected mainly to the operation time of MGP but not to their current technical state. This approach contradicts common engineering sense, when further actions (repair, diagnostics) should depend on the actual pipe state, monitoring data, statistics of damage, etc., and not on the regulations; (2) universal, or so-called pipeline integrity management system—where the solutions are interconnected and agreed on the basis of a detailed analysis (including risk-analysis). The described criteria (sequence of inspection/repair) of defect evaluation are an integral part of a comprehensive assessment of the technical state of the pipeline. Recommendations are made on the volume of overhaul or selective repair based on the results of the assessment, namely: • • • •

diagnostic examinations of pipeline metal; mechanical testing [3, 25, 26]; comprehensive reseach of corrosion protection of gas pipeline facilities; analysis of terrain peculiarities, etc.

In general, the described procedure can be characterized as a component of the pipeline integrity management system [27].

6 Concluding Remarks The activities of any enterprise in the end should ensure profit, so resources should be used as efficiently as possible. One of the ways to optimize costs is to introduce an effective and flexible system where the expenses on diagnostic, repair, emergency and recovery measures are interconnected and agreed on the basis of a detailed analysis (including risk-analysis). The pipeline integrity management system implemented by Ukrtransgaz is based on the existing geographical information system for certification and technical monitoring of gas pipelines, as well as on the analytical hardware and software system that is constantly being developed and improved.

References 1. Meshkov, Y.Y., Shyyan, A.V., Zvirko, O.I.: Evaluation of the in-service degradation of steels of gas pipelines according to the criterion of mechanical stability. Mater. Sci. 50(6), 830–835 (2015)

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2. Gredil, M.I.: Operating degradation of gas-main pipeline steels. Metallofizika i Noveishie Tekhnologii 30, 397–406 (2008) 3. Krechkovs’ka, H.V., Tsyrul’nyk, O.T., Student, O.Z.: In-service degradation of mechanical characteristics of pipe steels in gas mains. Strength Mater. 51(3), 406–417 (2019) 4. Maruschak, P., Bishchak, R., Konovalenko, I., Menou, A., Brezinová, J.: Effect of long term operation on degradation of material of main gas pipelines. Mater. Sci. Forum 782, 279–283 (2014) 5. Andreikiv, O.E., Hembara, O.V., Tsyrul’nyk, O.T., Nyrkova L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238 (2012) 6. Kryzhanivs’kyi, E.I., Hrabovs’kyi, R.S., Mandryk, O.M.: Estimation of the serviceability of oil and gas pipelines after long-term operation according to the parameters of their defectiveness. Mater. Sci. 49(1), 117–123 (2013) 7. Witek, M.: Validation of in-line inspection data quality and impact on steel pipeline diagnostic intervals. J. Nat. Gas Sci. Eng. 56, 121–133 (2018) 8. Banakhevych, Yu.V., Banakhevych, R.Yu.: Experience of identification of the defects revealed by the intra-tube diagnostics in JSC “UKRTRANSGAZ”. Tech. Diagnos. Non-Destructive Test. 2, 40–46 (2013) (in Ukrainian) 9. Standard of Organization SOU 49.5-30019801-135:2016: Gas mains. In-tube diagnostics of the linear part. Kyiv, PJSC “Ukrtransgas”, 130 p. (2016) (in Ukrainian) 10. Final Pipeline Survey Report: Examination for metal loss, examination for longitudinal anomalies and determination of the spatial position of XYZ. Gas pipeline 48 GM “Urengoy–Pomary– Uzhgorod” CS “Ilintsy”—CS “Bar”, ROSEN, Oldenzaal, 423 p. (2008) 11. Tsyrul’nyk, O.T., Kryzhanivs’kyi, E.I., Petryna, D.Y., Taraevs’kyi O.S., Hredil’ M.I.: Susceptibility of a welded joint of 17G1S steel in a gas main to hydrogen embrittlement. Mater. Sci. 40(6), 844–849 (2004) 12. DSTU 4219–2003: Steel main pipelines. General requirements for corrosion protection. State Consumer Standard of Ukraine, Kyiv, 72 p. (2003) (in Ukrainian) 13. Stasyuk, B.M., Kret, N.V., Zvirko, O.I., Shtoiko, I.P.: Analysis of the stressed state of a pipe of gas pipeline with hydrogen-induced macrodefect. Mater. Sci. 55(1), 124–129 (2019) 14. Hredil, M.I.: Role of disseminated damages in operational degradation of steels of the main gas conduits. Metallofizika i Noveishie Tekhnologii 33, 419–426 (2011) 15. Zvirko, O., Gabetta, G., Tsyrulnyk, O., Kret, N.: Assessment of in-service degradation of gas pipeline steel taking into account susceptibility to stress corrosion cracking. Procedia Struct. Integr. 16, 121–125 (2019) 16. Nykyforchyn, H., Krechkovska, H., Student, O., Zvirko, O.: Feature of stress corrosion cracking of degraded gas pipeline steels. Procedia Struct. Integr. 16, 153–160 (2019) 17. SNiP 2.05.06-85: Main pipelines. Gosstroy of USSR, Moscow, 52 p. (1985) (in Russian) 18. CAN/CSA-Z662-03: Oil and Gas Pipeline Systems. Toronto: CSA Group, 865 p (2015) 19. Pipeline Defect Assessment Manual, 2nd ed. Penspen, Richmond, 473 p (2016) 20. British Gas Engineering Standard BGC/PS/P11: Procedures for Inspection and Repair of Damaged Steel Pipelines (Designed to Operate at Pressure above 7 bar). Windsor: British Gas, 873 p (2016) 21. Regulation on the analysis of the results of the in-pipe inspection of GMs of “Ukrtransgaz” and the organization of repair works to eliminate them. “Ukrtransgaz”, Kyiv, 28 p (2009) (in Ukrainian) 22. DSTU-N B V.2.3-21:2008. Main pipelines. Installation. Determination of the remaining strength of trunk pipelines with defects. SE “Ukrakhbudinform”, Kyiv, 68 p. (2008) (in Ukrainian) 23. Technique for assessment the technical state of the long term operated pipeline and its residual lifetime. JSC Ukrtransgaz, Kyiv, 23 p (2009) (in Ukrainian) 24. NPAOP 60.3-1.01–10. Rules for safe operation of main gas pipelines. Derzhhirpromnagliad, Kyiv, 141 p (2010) (in Ukrainian)

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25. Hredil, M., Krechkovska, H., Student, O., Kurnat, I.: Fractographic features of long term operated gas pipeline steels fracture under impact loading. Procedia Struct. Integr. 21, 166–172 (2019) 26. Banakhevych, Yu.V., Banakhevych, R.Yu., Dragilev, A.V., Kychma, A.O.: Static strength evaluation of pipelines sections with crack-like defects in the weld zone. J. Hydrocarbon Power Eng. 1(2), 96–102 (2014) 27. Banakhevych, Yu.V., Banakhevych, R.Yu.: Defects identification of the main gas pipelines. J. Hydrocarbon Power Eng. 6(1), 22–29 (2019)

Hydrogen Embrittlement and Microdamage of 316L Steel Affecting the Structural Integrity, Durability and Safety of Pipelines Jesús Toribio and Javier Ayaso

Abstract This paper evaluates, by quantitative fractography and image analysis techniques, the hydrogen embrittlement and microdamage in notched samples of 316L steel, the described phenomenon affecting the structural integrity, durability and safety of the pipelines made with such a material. After the hydrogen embrittlement tests, it is seen that microdamage created by hydrogen is concentrated in an external circumferential ring with the same center as the cross sectional area of the notched samples. The microscopical appearance of this embrittled zone or damaged area is very rough and irregular at the micro-scale, with evidence of secondary cracking, in contrast with the smooth surface (at the micro-scale) created by microvoid coalescence (dimpled fracture) in the inner core which is not embrittled by hydrogen and fails by mechanical reasons. In addition, differences are observed in the matter of the appearance of the hydrogen-assisted microdamage area as a function of the notch geometry and of the embrittlement time. Keywords Hydrogen embrittlement · Hydrogen-assisted micro-damage · Notched samples · Embrittled zone · Secondary cracking · Micro-fracture maps

1 Introduction The annealed type 316L austenitic stainless steel is a material used in pipelines and vessels as it has good fracture toughness and corrosion resistance [1]. However, further research is needed on hydrogen assisted failure of this steel, since hydrogen can be present of the material as a consequence of environmentally assisted cracking and cathodic reactions, and it is known that hydrogen is a strong promoter of materials degradation and loss of structural integrity. J. Toribio (B) · J. Ayaso Fracture and Structural Integrity Research Group (FSIRG), University of Salamanca, Zamora, Spain e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_11

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Although the 316L steel has big ductility and fracture resistance in air environment, its fracture resistance and notch susceptibility suffer a marked reduction in a hydrogen environment [2, 3], even higher in the sensitized 316L steel than in the annealed type [4, 5]. In the latter the hydrogen-induced damage is concentrated at the final loading stages before the final fracture [6]. The microscopic topographies confirm the previous reasoning, since the fracture is intergranular (IG) in the sensitized steel and micro-void coalescence (MVC) in the annealed one [5, 7]. This paper presents a quantitative fractographic analysis of the micromechanical damage produced in 316L steel by mechanical reasons (plasticity) and environmental origins (hydrogen embrittlement). The paper goes further from previous work on notched samples [8–11] and cracked specimens [12] of 316L austenitic stainless steel.

2 Experimental Program The analysis is based on previous experimental results of fracture tests on notched samples of solution-annealed 316L austenitic stainless steel tested in air and hydrogen environment at room temperature (18 °C) [8, 9]. Two notched geometries A and C with different notch radius were used, as depicted in Fig. 1. The dimensions were: Geometry A: R/D = 0.03 C/D = 0.10 Geometry C: R/D = 0.36 C/D = 0.10 where R is the notch radius, C the notch depth and D the specimen diameter (6 mm). Two specimens were tested in air, one of them machined with the main axis (z) parallel to the rolling direction (direction A) and the other with the main axis perpendicular to the former (direction B). The samples were named AA, AB, CA and CB, where the first letter indicates the geometry and the second one the orientation of the specimen in relation to the rolling direction. The mechanical behavior was clearly ductile in all cases, and no differences were observed between both directions. Fig. 1 Notch A (sharp notch specimen SNS) and C (blunt notch specimen BNS)

SNS

BNS

4.8 mm 0.2 mm

6 mm

4.8 mm

6 mm

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The hydrogen embrittlement tests were performed at constant displacement rate in aqueous solution of H2 SO4 , using a cathodic potential of –1200 mV vs SCE [8]. At this potential, the hydrogen is cathodically introduced into the specimen. The displacement rates ranged from 0.01 to 2.5 µm/s. The mechanical behavior was also ductile (as in air) with decrease in load up to the final rupture. Again no clear differences were observed between the two directions of machining.

3 Experimental Results Experimental results in air and hydrogen were described in [10]. In both environments a ductile-type fracture takes place. The observation of the notch surfaces of specimens tested in hydrogen environment reveals the existence of extensive damage consisting of surface multi-cracking and void formation. Figure 2 shows the superficial state of the notch region in the SNS and BNS at failure situation in two H-embrittlement tests interrupted at the point of maximum load. Surface damage in the form of multicracking—probably extended in volume—is clearly observed in both specimens. From the experimental facts described above, two mechanical models of hydrogen damage were proposed in [9], as depicted in Fig. 3. The notch extension model (NEM) considers that hydrogen effect can be modelled as a geometric enlargement of the notch. In the notch cracking model (NCM), it is assumed that the embrittled area at the notch tip behaves as a macroscopic crack extending the original notch. These two models allow an engineering prediction of the failure load in hydrogen.

Fig. 2 Surface state near the notch tip in the SNS and BNS showing surface damage in the form of multi-cracking (tests interrupted at the point of maximum load)

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Fig. 3 Mechanical modeling of hydrogen damage: notch extension model (NEM) and notch cracking model (NCM)

NEM

c

c

NCM

c

c

4 Fractographic Analysis (Air Tests) Fracture surfaces of samples tested in air and in hydrogen environment were observed by scanning electron microscopy (SEM), in order to assemble micro-fracture maps (MFM) of the whole fractured section. Figures 4 and 5 show the MFM in air. A predominant fracture topography consisting of micro-void coalescence (MVC) is observed in the main inner part of the fractured section, surrounded by an external ring representing the notch surface with an orange-skin appearance which demonstrates the high degree of plasticity achieved before the fracture phenomenon, the Fig. 4 MFM of SNS (sharp notch) fractured in air (AA01)

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Fig. 5 MFM of BNS (blunt notch) fractured in air (CA01)

latter being purely ductile and caused by plastic instability in both notch types [9]. With regard to the differences between both notched geometries, it is observed that the micro-void density increases and the critical micro-void size decreases when the stress triaxiality increases, as happens in the SNS (geometry A) of small notch radius (Fig. 4). This fact is consistent with main classical models of micro-void growth, according to which the stress triaxiality enhances the micro-void growth rate [13] but limits the critical size of such micro-voids [14, 15].

5 Fractographic Analysis (Hydrogen Embrittlement Tests) Figures 6 and 7 show the MFM for hydrogen embrittlement tests on both SNS and BNS, where short and long tests are taken into account. A first experimental fact is observed: a decrease of plasticity development in the vicinity of the notch tip due to the presence of hydrogen, because the external area with orange-skin appearance is smaller than in the air tests. In addition, hydrogen damage appears in the periphery on the form of a multi-cracked region with secondary cracking. This surface damage is not confined at the surface, but probably extended in volume near the notch tip. The microscopic appearance of such an embrittled zone is very rough and irregular at the microscopic scale, and these roughness and irregularity increase with the tests duration (see the embrittled zone in sample CB3, cf. Figure 7 for a test of more than 100 h). This is consequence of the time-dependence of the hydrogen transport phenomenon, either by diffusion or by dislocational dragging. The depth of the embrittled zone or multi-cracked external ring (damage depth or embrittlement depth) is also an increasing function of the test duration, as observed in Figs. 6 and 7. Therefore, hydrogen-assisted micro-mechanical damage is extended in surface and volume, the latter due to the higher irregularity of the multi-cracked ring

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Fig. 6 MFM of SNS in hydrogen in short (left) and long (right) tests

Fig. 7 MFM of BNS in hydrogen in short (left) and long (right) tests

in the case of long tests, which indicates cracking at different levels in the vicinity of the notch tip (cf. Figure 7, test CB3 with volumetric damage). On the other hand, the nucleus (or core) of the transverse section fails by MVC, as in the case of the air tests, although in hydrogen embrittlement tests the plastic collapse is enhanced by multi-cracking at the external ring or damaged zone by hydrogen at the microscopical level. The appearance of the MVC core in hydrogen is different from the same in air. In general terms, hydrogen increases the density of micro-voids and decreases their critical size, due to the stress triaxiality increase as a consequence of multi-cracking.

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6 Damage Produced by Hydrogen The damage depth x (embrittlement depth) was evaluated by image analysis, from the MFM associated with the hydrogen embrittlement tests (Figs. 6 and 7). Figure 8 plots the numerical predictions of the notch extension model (NEM) and the notch cracking model (NCM), obtained in a previous research work [9], together with the experimental results with regard to the fractographic analysis described in this paper. The comparison between model predictions and fractographic results is made through the functional relationship between the failure load in the hydrogen tests and the damage depth measured on the MFM. The former is given in dimensionless terms as the ratio of the failure load in the hydrogen embrittlement test (Fm ) to the same value in the fracture tests in air (F0 ) for the same notched geometry. Figure 8 demonstrates that, considering the logical scatter of this kind of tests, experimental results, expressed as the average damage depth, agree fairly well with the predictions of the NCM, according to which the damage due to the presence of hydrogen can be modeled as a crack extending the original notch. The adequacy of the latter to describe the hydrogen-assisted fracture process in SNS is consistent with the results provided by Valiente et al. [12] using pre-cracked specimens of the same 316L steel subjected to hydrogen embrittlement tests in which two phenomena were detected in the vicinity of the crack tip: firstly crack tip blunting (with high degree of plasticity) and later post-cracking (from the initial blunted crack) with branching. It would be post-cracking analogous to cracking of sharp notches as in the case of SNS (notched geometry A of small radius). In a highly ductile material as the 316L steel, a very blunted crack is geometrically similar to a very sharp notch, i.e., to a notch with a very small notch tip radius. Fig. 8 Prediction of the notch extension model (NEM) and notch cracking model (NCM) and experimental results, in dimensionless terms as the ratio of the failure load in the hydrogen embrittlement test (Fm ) to the same value in the fracture tests in air (F0 ). In all cases the average depth of the embrittled zone is used

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7 Conclusions Hydrogen-assisted micro-damage in 316L stainless steel in tension test was evaluated in axisymmetric notched samples by using scanning electron microscopy (SEM), quantitative fractography and image analysis techniques. The micro-fracture maps (MFM) show that failure in air takes place in a ductile manner by micro-void coalescence (MVC) in the whole fractured surface, with a very high level of ductility associated with plasticity extension. The hydrogen affect manifests in the MFM as an external multi-cracked ring in the periphery of the fracture surface, surrounding a central core or nucleus in which the fracture is ductile by MVC (similar to that in air). The damage depth due to the hydrogen (measured in the MFM) allows an experimental assessment of the two proposed mechanical models of damage: the notch extension model (NEM) and the notch cracking model (NCM). The NCM agrees better with the fractographic data if the average damage depth is used. Previous conclusion is consistent with experimental results on hydrogen embrittlement of pre-cracked samples of 316L austenitic stainless steel, in which crack tip suffers blunting, crack advance and branching. Acknowledgements This work was supported by the Spanish Office for Scientific and Technological Research (CICYT) under Grant MAT91-0113-CE. Funds were also provided by EURATOM as a part of the European Fusion Technology Programme (Task PSM5: “Hydrogen Effects and Water Corrosion in Reference 316 L Steel and Welds”, Sub-Task PSM 5-1: “316L H Embrittlement— Notch Effect”). The authors gratefully acknowledge the support of both organizations, as well as the encouragement of Drs. J. L. Boutard and P. Lorenzetto (THE NEAT TEAM) and Dr. E. Hodgson (CIEMAT).

References 1. NET Status Report: Commission of the European communities. Directorate General XIIFussion Programme, Brussels (1985) 2. Caskey Jr., G.R.: Hydrogen damage in stainless steel. In: Environmental Degradation of Engineering Materials in Hydrogen, 1981, Virginia Polytechnic Institute, Blacksburg, VA 3. Perng, T.P, Huang, J.H., Altstetter, C.J.: Hydrogen-induced cracking of stainless steels. In: 4th International Conference on Hydrogen and Materials, 1988, Beijing, China 4. Hazarabedian, A., Ovejero-García, J.: Effects of strain rate and prior heat treatments on hydrogen embrittlement of 316-L SS and 304 SS in aqueous sulfide environment. In: 4th International Conference on the Effect of Hydrogen on Behaviour of Materials, 1989, Jackson Lake, Wyoming, USA 5. Eliezer, D.: Hydrogen assisted cracking in Type 304L and 316L stainless steel. In: 3rd International Conference on the Effect of Hydrogen on Behaviour of Materials, 1981, AIME, USA 6. Briant, C.L.: A fractographic study of hydrogen assisted cracking in austenitic stainless steels. In: Environmental Degradation of Engineering Materials in Hydrogen, Virginia Polytechnic Institute, Blacksburg, VA, 1981

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7. Rozenak, P., Eliezer, D.: Effects of metallurgical variables on hydrogen embrittlement in AISI Type 316, 321 and 347 stainless steels. Mater. Sci. Eng. 61, 31–41 (1983) 8. Toribio, J.: Effects of strain rate and notch geometry on hydrogen embrittlement of AISI type 316L austenitic stainless steel. Fusion Eng. Design 16, 377–386 (1991) 9. Toribio, J., Valiente, A., Cortés, R., Caballero, L.: Modelling hydrogen embrittlement in 316L austenitic stainless steel for the first wall of the Next European Torus. Fusion Eng. Design 29, 442–447 (1995) 10. Toribio, J.: Experimental evaluation of micro-mechanical damage produced by hydrogen in 316L steel for the first wall of fusion reactors. Fusion Eng. Design 41, 85–90 (1998) 11. Toribio, J., Cortés, R., Caballero, L., Valiente, A.: An integrated approach to the modelling of hydrogen assisted failure in 316L steel. Fusion Eng. Design 41, 91–96 (1998) 12. Valiente, A., Caballero, L., Ruiz, J.: Hydrogen assisted failure of precracked specimens of 316L stainless steel. Nuclear Eng. Design 188, 203–216 (1999) 13. Rice, J.R., Tracey, D.M.: On the ductile enlargement of voids in triaxial stress fields. J. Mech. Phys. Solids 17, 201–217 (1969) 14. Pineau, A.: Review of FRACTURE MICROMECHANISMS and a local approach to predicting crack resistance in low strength steels, Advances in Fracture Research-ICF5. Cannes, France (1981) 15. Beremin, F.M.: Study of fracture criteria for ductile rupture of A508 steel, Advances in Fracture Research-ICF5. Cannes, France (1981)

Effect of Environmental Composition on Fatigue Crack Growth and Hydrogen Permeation in Carbon Pipeline Steel Ihor Dmytrakh, Rostyslav Leshchak, and Andriy Syrotyuk

Abstract The fatigue crack growth rate diagrams of the carbon pipeline steel were received under the presence of the admixtures of sodium nitrite as the passive component in the basic aqueous hydrogen-containing solution. It has been found that the fatigue crack growth rate da/dN depends ambiguously on the concentration CNaNO2 in solution due to the different properties of the passive films formed on the steel surface. The strength of passive films formed under different concentrations CNaNO2 was evaluated as a characteristic value of stress intensity factor K I∗ , which corresponds to the passive film failure of at the crack tip. For the determination of the parameter K I∗ , the special experimental procedure was developed. Received results showed that the dependence K I∗ on the concentration CNaNO2 is ambiguous and the maximum exists at some concentration CNaNO2 when the value K I∗ is maximal. The study of hydrogen permeation in steel at the presence of the passive film on the metal surface showed on some specific value of CNaNO2 , at which the formed passive film is the most resistible barrier against electrochemical hydrogen absorption. This value is very close to the above-mentioned value CNaNO2 , which corresponds to the highest strength of the passive film and also to the maximal deceleration of fatigue crack growth rate. Consequently, it may be concluded that the relationship between passive film strength, its ability to serve as a hydrogen barrier and fatigue crack growth rate exists. Thus, it is possible to decelerate the fatigue crack growth by the targeted variation of environmental composition. Keywords Pipeline steel · Cyclic loading · Fatigue crack growth rate · Stress intensity factor · Passive film · Hydrogen permeation

I. Dmytrakh (B) · R. Leshchak · A. Syrotyuk Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_12

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1 Introduction The prospective plans for introducing the hydrogen energy infrastructure [1–4] lead to permanent increasing of requirements to the pipeline network [5, 6]. The pipelines are the most convenient way to transport large quantities of hydrogen-containing products through very long distances as well as they can serve as a ramification network between the local suppliers and end-users [7–9]. The specific long-term exploitation of pipelines promotes the hydrogenating of steel. The external environmental conditions cause free corroding processes, where hydrogen can evolve on a metal surface as a result of a cathodic counterpart of the anodic dissolution reaction. This fact has been proved by several studies [10–12]. Also under the in-service condition when a cathodic protection system is in place, hydrogen charging of pipeline steels is possible [12, 13]. The effects of hydrogen on metallic materials, which lead to the loss of their plasticity, decrease of fracture toughness and degradation of fatigue properties are well-known (see, for example [14, 15]). However, the current level of understanding of these processes can be defined as insufficient mainly due to the complicated nature of the problem, which contains a number of different aspects [16–20]. It can be confirmed by recent publications [21–29] where some un-clarified questions remain for consideration, namely: the mechanisms of these phenomena [21–24], the effect of specific testing conditions [25–28] and synergistic effects of different factors [29]. Therefore, a further detailed multidisciplinary study is required with the aim of a deeper understanding of the fatigue mechanisms, especially for carbon and low-alloyed pipeline steels. In particular, this is important to clarify the role of passive films on hydrogen permeation into the material with the aim to obtain some optimal passive film properties as an effective hydrogen barrier [30]. Within the frame of the above-mentioned problem, the presented work is related to the fatigue crack propagation in the carbon pipeline steel under hydrogenation conditions when the passive film formation occurs on the metal surface. Here the authors tried to build some bridge between electrochemical parameters and parameters of fracture mechanics of materials. The modernity of this study consists of focusing on the development of the experimental method and study of the passive film’s strength depending on the physicochemical conditions of testing. It was shown that the effect of passive film properties on the process of hydrogen permeation into steel is important for the evaluation of possible hydrogen effect on fatigue crack propagation and for a deeper understanding of the hydrogen assisted fatigue mechanisms.

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2 Experimental Procedure 2.1 Specimens and Environmental Conditions The object of study was the carbon pipeline steel (σY = 260 MPa and σU = 440 MPa) with nominal chemical composition (in weight %): C = 0.17–0.24; Si = 0.17– 0.37; Mn = 0.35–0.65; S < 0.04; remainder Fe. This material consists of grains of ferrite-pearlite, typical for carbon steels (Fig. 1). The rectangular cross-section beam specimens (Fig. 2) were manufactured with the real pipe. Specimens were cut off from the pipe corresponding to the case of the longitudinal cracks. The initial crack of length a0 in the specimen was produced by fatigue loading in air. The value of a0 depended on the aim of conducting test. The specimen contains the special hole of diameter d (Fig. 2) for the installation of the mini-electrodes for electrochemical measurements in the crack cavity [31]. The stress intensity factor K I in the crack tip for such specimen in case of its loading by pure bending can be calculated from the formula [31]:

Fig. 1 Structural specificity of a pipeline steel (×500)

Fig. 2 The geometry of the beam specimen

60°

1 mm

d=1 mm

a0

20 mmmm w=20

Initial crack 200 mm L=200 mm

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 √ λ · f (λ) 6M · KI = √ 4 3 t· w (1 − ε)3

(1)

f (λ) = 1.99 − 2.47λ + 12.97λ2 − 27.17λ3 + 24.80λ4 + 60.59λ16 ,

(2)



where M is bending moment; t is specimen thickness; w is specimen height; a is crack length; λ = a · w −1 ; ε = d · t −1 . The relation (1) is correct under 0 ≤ λ ≤ 0.8, and 0 ≤ ε ≤ 0.5. The 3% aqueous solution of N aCl was used as the basic environment ( p Hbulk = 6.5). Such choice supposes that hydrogen can evolve on a metal surface as a result of the cathodic counterpart of the anodic dissolution reaction under the process of free corrosion. The solution of NaNO2 served as a passive component, which promotes the passive film creation on the metal surface. Five concentrations of N a N O2 were considered in this study, namely: CNaNO2 = 0.007; 0.03; 0.07; 0.14 and 0.21 mol/L.

2.2 Details of Fatigue Crack Growth Test For the realization of experimental studies of the fatigue crack growth under joint action of the cyclic loading and hydrogenation environmental conditions the special testing stand was developed, based on the fatigue testing machine for pure bending of specimens under the environmental conditions. The rectangular cross-section beam specimens (Fig. 2) with initial edge crack of length a0 ≈ 2.5 mm were subjected by cyclic pure bending with frequency f = 1 Hz under stress ratio R = 0. The stress intensity factor K I at the crack tip for such specimen in case of loading by pure bending was calculated from the formula (1). The details of the test procedure are the following. As the environment is transparent, crack lengths were measured on a plane surface of specimens by optical microscope with accuracy ±0.005 mm. The specimens were subjected to pure bending under constant displacement mode. The initial cracks were nucleated in air conditions √ (f = 12 Hz and R = 0) at the final stress intensity factor range K i ≈ 9.5 MPa m that is lower than the initial range of stress intensity factor for the main tests in the environment. The choice of test conditions can be explained by the following. As it is known from literature records [32, 33] the most significant environmental effects can be observed at stress ratio R = 0. The frequency of cyclic loading f is also a very important parameter and it is accepted that fatigue crack growth rate increases with decreasing frequency. However, as it was shown [34] there is some maximum in the curve da/dN = ( f ) and for considered steel, this maximum corresponds to value f = 1.0 Hz. From these reasons the conditions of fatigue test were chosen as R = 0 and f = 1.0 Hz for receiving the maximal environmental effect on fatigue crack growth rate.

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Resulting data under different concentration of the NaNO2 in the 3% NaCl solution were received as the sequence of the following parameters: number cycles of loading Ni , crack length ai , fatigue crack growth rate (da/a N )i , and stress intensity factor range K i .

2.3 Method of Passive Film Strength Evaluation at the Crack Tip This work proposes the characteristic value of stress intensity factor K I∗ , which corresponds to the passive film failure of at the crack tip as the basic parameter of its local strength. For the determination of the parameter K I∗ , the special experimental procedure was developed. To this aim, the special testing equipment [31] for the study of environmentally assisted fracture of materials and determination of electrochemical conditions in the crack was used. The procedure to determine the parameter K I∗ was the following (Fig. 3). The specimen 1 with initial crack 2 of length a 0 was placed in the corrosion cell 3 and fixed in the grips 4 of the testing machine for pure bending. The mini-electrode 5 for measuring the electrode potential E t in the crack tip 6 was installed into the hole of the specimen. It should be noted that this minielectrode, in a physical sense, is minicapillary (like to Luggin-Haber capillary), which provides an electrolytic contact of the local environment in the crack tip with the standard reference electrode (Saturated Calomel Electrode—SCE). Thus, the measurement of the electrode potential E t is realized by the standard mode. A detailed description of this technique can be found in work [31]. The specimen was preliminarly loaded by the bending moment M0 . The values of the electrode potential E and bending moment M were recorded in time by PC with the use of the developed software. At the start of the test, the cell 3 (Fig. 3) was filled by corrosion solution and the dependence of the electrode potential at crack tip E t versus time of exposure τ was Fig. 3 Principal scheme of test for evaluation of passive film strength at the tip of corrosion crack: 1—specimen; 2—initial crack; 3—corrosion cell; 4—grips of testing machine for pure bending; 5—mini-electrode for measuring of the electrode potential E t in the crack tip; 6—crack tip; M—bending moment; PC—personal computer

5 2

M

M

M

4

M PC PC 6

1

3

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M

M*

.

A

ΔM * M0

0

Etstab

Et

recorded. The stabilization of E t value on some level E tstab indicates that the passive film in the crack tip is formed. After that, the specimen was loaded by a monotonic bending moment M with simultaneous recording of the diagram applied bending moment M—electrode potential at crack tip E t (Fig. 4). Such diagram serves for determination of the critical load M ∗ , which corresponds to passive film failure in the crack tip. As the indicator of this event the sharp deflection of E t value from its stabilized meaning E tstab was used (see Fig. 4, point A). Thus, the strength of the passive film at the crack tip in terms of bending moment can be evaluated as M ∗ = M ∗ − M0 . Having the known values of M ∗ and crack length a0 the corresponding critical value of stress intensity factor K I∗ can be calculated using formula (1). Such value can be considered as the basic parameter for strength assessment of passive film at corrosion fatigue crack tip. As an additional explanation to this section, it should be noted that the preliminary loading of the specimen by the bending moment M0 is necessary to create the minimum crack opening, which ensures the supply of the environment in its tip. The value of M0 is chosen from the condition that the stress intensity factor at the crack tip K I should not exceed the threshold value K ISCC , i.e. the value below which the crack growth does not occur: K I (M0 , a) ≤ K I SCC . The exposure of pre-loaded specimen in the environment with simultaneous registration of the electrode potential at the crack tip provides the control of passive film formation. Such control is necessary in order to determine the strength characteristics of the finally formed passive film instead of some occasional intermediate states. The moment of the failure of formed protective passive film is characterized by the creation of a new (fresh) surface in the crack tip and the electrode potential of this surface is significantly different than potential E tstab . Therefore, the diagram applied load—electrode potential at crack tip contains the clear-visible inflection point, at which the failure value of load M ∗ can be accurately determined.

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For each experimental condition, which is defined by the concentration CNaNO2 , all conducted tests were repeated 2–4 times and the averaged values of determined parameters were taken into account under the analysis of the results.

2.4 Study of Hydrogen Permeation in Steel at Presence of Passive Film on Metal Surface The disk specimens of diameter D = 8 mm and thickness t = 4 mm were used for the assessment of hydrogen permeation in steel in the presence of the passive film on the metal surface (Fig. 5). The surface passive films were formed in the 3% NaCl solution with different concentration of NaNO2 , namely: CNaNO2 = 0.007; 0.03; 0.07; 0.14 and 0.21 mol/L. The surface of specimen was hydrogen charged during τ = 2 h at constant cathodic polarization potential E cath = −1200 mV(SC E), which was slightly more negative (E = −200 mV(SC E)) than corrosion potential E corr for each considered condition. For the realization of these experiments, the dynamic electrochemical laboratory VoltaLab40 [35] was used. The hydrogen-charging process was controlled by registration of the cathodic polarization current Icath (τ ). The total quantity of hydrogen evolution on the metal surface during exposure time τexp can be assessed as: τexp Q ev H =

Icath (τ ) dτ .

(3)

0

The hydrogen concentration in bulk of steel was determined on the base of the hydrogen discharging process under anodic polarisation using the hydrogen electrochemical oxidation method proposed in work [36]. The detailed description of the application of this method for the hydrogenation problems of pipeline steels can be found in works [20, 37–39].

Fig. 5 Specimens for the study of surface electrochemical hydrogenation of pipeline steel: a with soldered conductors; b in the plastic case

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Hydrogen discharging of specimens was carried out in 0.2 M NaOH (pH = 12.4) solution under anodic polarization E anodic = +168 mV(SC E) during a defined time τdis . The total quantity of hydrogen absorbed by the metal surface with passive film can be defined as [37]: τdis Q abs H

=

[I H (τ ) − Iref (τ )] dτ ,

(4)

0

where I H (τ ) is the anodic polarization current for hydrogen charged specimen and Iref (τ ) for specimen without hydrogen (reference curve). Hydrogen concentration was calculated according to the formula [37]: CH =

Q abs H , z Fv

(5)

where z is the number of electrons taken in reaction; F is the Faraday constant; v is the effective volume of the specimen.

3 Results and Discussion 3.1 Fatigue Crack Growth Diagrams Under Different Environmental Conditions Fatigue crack growth rate in carbon pipeline steel was studied under different environmental conditions when the passive film formation occurs on the metal surface due to the presence of the different concentration of NaNO2 in solution. It has been done according to the experimental procedure above described. The test results were presented as the separate scatter plots of fatigue crack growth rate da/dN versus maximal value stress intensity factor K max per loading cycle (Fig. 6). These plots showed that the fatigue crack growth rate da/dN depends . It can be clearly seen when we make the ambiguously on concentration CNaNO2√ section of diagrams at K max = 30 MPa m (Fig. 6). Here the maximal fatigue crack growth resistance (maximal deceleration of fatigue crack growth rate) was observed approximately at CNaNO2 = 0.095 mol/L (Fig. 7). These results may be explained on the base of consideration of passive film’s role in the mechanisms of the fatigue crack growth in given steel. It is known [29, 32, 33] that for such system material—environment the mixed mechanism of fatigue crack growth exists where the corrosion factor (local anodic dissolution of metal) and

Effect of Environmental Composition on Fatigue … 05−5 10

da/dN, m/cycle

Fig. 6 Fatigue crack growth diagrams of the pipeline steel in the 3% NaCl solution with additions of NaNO2 : a CNaNO2 = 0.007 mol/L ; bCNaNO2 = 0.03 mol/L ; c CNaNO2 = 0.07 mol/L ; d CNaNO2 = 0.14 mol/L; e CNaNO2 = 0.21 mol/L

1 2 3 4 5

06−6 10

07−7 10

−8 10 08

K max = 30 MPa m = const.

10

100

K max , MPa m

−5

10

K max = 30 MPa m

da/dN, m/cycle

Fig. 7 Dependence of the fatigue crack growth rate da/dN in pipeline steel on the concentration CNaNO2 in the environment √ at K max = 30 MPa m

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1006

−6

∗ C NaNO 2

−7

1007

0,001

0,01

0,1

1

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hydrogen factor (embrittlement of material) act simultaneously. At that, the corrosion factor prevails in the threshold zone [32, 33] and the hydrogen factor—in the middle zone (Paris region [40]) of the fatigue crack growth rate diagram. The abovepresented data refer to the Paris region of the diagram and consequently, it can be supposed that the hydrogen factor is dominant for considered cases. Indeed, for the given system material—environment, the water is the main source of hydrogen generation. The hydrogen atoms are evolved on the steel surface by the electrochemical reduction of water molecules (see, for example [10]): H2 O + e → Hads + OH− .

(6)

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The adsorbed hydrogen atoms can subsequently be combined to H2 molecules by the chemical reaction: 2Hads → H2

(7)

Hads + H2 O + e → H2 + OH−

(8)

or the electrochemical reaction:

or can be absorbed by the steel: Hads → Habs .

(9)

Therefore, the presence of CNaNO2 in the solution, due to its ability to create the passive film on the metal surface, can be considered as a reducing factor of the hydrogen charging of metal. For this reason, the assessment of passive film strength formed under the different composition of the environment is important for the evaluation of possible hydrogen effect on fatigue crack propagation.

3.2 Evaluation of Passive Film Strength at Crack Tip Under Different Environmental Conditions The passive film strength was determined as the characteristic value of stress intensity factor K I∗ , which corresponds to the passive film failure of at the crack tip. The tests were carried out according to the above proposed method for five concentrations of NaNO2 in 3% aqueous solution of NaCl: CNaNO2 = 0.007; 0.03; 0.07; 0.14 and 0.21 mol/L. The process of passive film creation was controlled by the value of electrode potential in the crack tip E t and its stabilization on some level E tstab indicated that that the passive film in the crack tip has been formed. The dependence of the stabilized values of the electrode potential E tstab in the crack tip versus the concentration NaNO2 in solution is given in Fig. 8a. The corresponding time of the passivation process in the crack tip zone τ p depends on the concentration CNaNO2 —in Fig. 8b. The results showed that increasing the NaNO2 concentration leads to increasing the values E tstab , which become more positive. At the same, time the passivation time τ p decreases, which indicates the intensification of the passivation process in the corrosion crack tip. As can be seen (Fig. 8) this trend is especially visible at the concentrations CNaNO2 ≥ 0.1 mol/L. After achieving the stabilized value of the electrode potential in the crack tip E tstab , the specimen was monotonic loaded and the moment of the passive film failure was registered as the moment of sharp deflection of E t value from its stabilized meaning

Effect of Environmental Composition on Fatigue … stab

Et

155 τp, s

,

mV(SCE )

145

-460 -465

140

-470 135

-475 -480 0,001

0,01

0,1

1

C NaNO2 , mol L

a)

130 0,001

0,01

0,1

C NaNO2 , mol L

1

b)

Fig. 8 Dependence of stabilized values of the electrode potential E tstab (a) and time of passivation τ p (b) on the NaNO2 concentration CNaNO2 in solution

E tstab . As the final result of the test, the critical value of the stress intensity factor K I∗ was determined for all considered cases. It has been found (Fig. 9) that dependence of the stress intensity factor value K I∗ , at which the passive film fracture occurs in the crack tip, on the NaNO2 concentration CNaNO2 is ambiguous and the maximum exists at some concentration CNaNO2 when the value K I is maximal. The existence of such extreme can be associated with the kinetic peculiarities of passive film formation. The analysis of the images of passive films on the surface of steel formed under different concentration of the NaNO2 in the 3% NaCl solution showed the following (Fig. 10). At low concentrations of NaNO2 , the passive film forms quite slowly and due to electrochemical heterogeneity of metal, some separate micro-regions are present at the crack tip with more negative potential than the equilibrium potential of oxide formation. In this case, the reaction goes in the opposite Fig. 9 Dependence of the stress intensity factor value K I , at which the passive film fracture occurs in the crack tip, on the NaNO2 concentration CNaNO2

K I∗ ,

10

MPa m 9 8 7 6 5 0,001

∗ C NaNO 2

0,01

0,1

C NaNO2 , mol L

1

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Fig. 10 Images of passive films on the steel surface, which formed under different concentration of the N a N O2 in the 3% NaCl solution (×100): a CNaNO2 = 0 mol/L (Air); b CNaNO2 = 0.007 mol/L; c CNaNO2 = 0.03 mol/L; d CNaNO2 = 0.07 mol/L ; e CNaNO2 = 0.14 mol/L; f CNaNO2 = 0.21 mol/L

direction and the electrochemical reduction of metal from oxide takes place. As a result, the film is formed quite thin and damaged. At high concentrations of NaNO2 the film forms thicker; however, due to the rapid course of the process, obviously, it is quite porous, which affects its strength properties. It follows that there is some ∗ , which provides the maximum strength of the passive optimal concentration CNaNO 2 film at the crack tip (parameter K I∗ ). For  considered system material-environment, ∗ ∼ this value equals CNaNO 0.095 mol L. = 2

3.3 Hydrogen Permeation in Steel at Presence of Passive Film on Metal Surface The ability to absorb hydrogen of pipeline steel at the presence of surface passive films was studied according above-described method. The cases of five different concentration CNaNO2 in solution were considered. The effect of the concentration CNaNO2 in the environment on hydrogen concentration CH in pipeline steel is shown in Fig. 11. The received results indicate the ambiguous effect of the concentration CNaNO2 in the corrosive environment on the hydrogen permeation into the material. Some minimum of the hydrogen concentration value CH can be clearly seen on the curve CH = F(CNaNO2 ). Therefore it may be concluded that some specific value CNaNO2 exists, at which the formed passive film is the most resistible barrier against electrochemical hydrogen absorption. This value  ∗ ∼ 0.095 mol L, which correis very close to the above-mentioned value CNaNO = 2 sponds to the highest strength of passive film (see Fig. 9) and also to the maximal deceleration of fatigue crack growth rate (see Fig. 7).

Effect of Environmental Composition on Fatigue … Fig. 11 Dependence of the hydrogen concentration C H in pipeline steel on the concentration CNaNO2 in the corrosive environment

157

CH ⋅10 6 5, mol cm 3 4 3 2 1 0

∗ C NaNO 2

0

0,05

0,1

0,15

0,2

0,25

C NaNO 2 , mol L

4 Conclusions Fatigue crack growth rate diagrams of carbon pipeline steel were received under the presence of the admixtures of NaNO2 as the passive component in the basic hydrogen-containing solution. It has been found that the fatigue crack growth rate da/dN depends ambiguously on concentration CNaNO2 and maximal deceleration  of ∗ ∼ fatigue crack growth rate was observed approximately at CNaNO 0.095 mol L. = 2 The strength of passive films formed under different concentrations CNaNO2 was evaluated as a characteristic value of stress intensity factor K I∗ , which corresponds to the passive film failure at the crack tip. For the determination of parameter K I∗ , the special experimental procedure was developed and verified. Obtained results showed is ambiguous and the maximum that that dependence K I∗ on concentration CNaNO 2 ∗ ∼ exists at some concentration CNaNO 0.095 mol L when the value K I∗ is maximal. = 2 The study of hydrogen permeation in steel in presence of the passive film on the metal surface showed some specific value of CNaNO2 , at which the formed passive film is the most resistible barrier against electrochemical hydrogen absorption. This value  ∗ ∼ 0.095 mol L, which correis very close to the above-mentioned value CNaNO = 2 sponds to the highest strength of passive film and also to the maximal deceleration of fatigue crack growth rate. It can be concluded that the relationship between passive film strength, its ability to serve as a hydrogen barrier and fatigue crack growth rate exists. Therefore, the knowledge of passive film properties is critically important for considerations of environmental assisted fracture under conditions of the hydrogenation of pipeline steels.

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References 1. Moliner, R., Lázaro, M.J., Suelves, I.: Analysis of the strategies for bridging the gap towards the hydrogen economy. Int. J. Hydrogen Energy 41(43), 19500–19508 (2016) 2. Markert, F., Marangon, A., Carcassi, M., Duijm, N.J.: Risk and sustainability analysis of complex hydrogen infrastructures. Int. J. Hydrogen Energy 42(11), 7698–7706 (2017) 3. Garcia, D.A.: Analysis of non-economic barriers for the deployment of hydrogen technologies and infrastructures in European countries. Int. J. Hydrogen Energy 42(10), 6435–6447 (2017) 4. Stern, A.G.: A new sustainable hydrogen clean energy paradigm. Int. J. Hydrogen Energy 43(9), 424–255 (2018) 5. Medeiros, C.P., Alencar, M.H., de Almeida, A.T.: Hydrogen pipelines: enhancing information visualization and statistical tests for global sensitivity analysis when evaluating multidimensional risks to support decision-making. Int. J. Hydrogen Energy 41(47), 22192–22205 (2016) 6. Messaoudani, Z., Rigas, F., Hamid, M.D.B., Hassan, C.R.C.: Hazards, safety and knowledge gaps on hydrogen transmission via natural gas grid: a critical review. Int. J. Hydrogen Energy 41(39), 17511–17525 (2016) 7. Bolat, P., Thiel, C.: Hydrogen supply chain architecture for bottom-up energy systems models. Part 1: developing pathways. Int. J. Hydrogen Energy 39(17), 8881–8897 (2014) 8. Bolat, P., Thiel, C. Hydrogen supply chain architecture for bottom-up energy systems models. Part 2: techno-economic inputs for hydrogen production pathways. Int. J. Hydrogen Energy 39(17), 8898–8925 (2014) 9. Huang, Y., Ma, G.: A grid-based risk screening method for fire and explosion events of hydrogen refuelling stations. Int. J. Hydrogen Energy 43(1), 442–454 (2018) 10. Cheng, Y.F., Niu, L.: Mechanism for hydrogen evolution reaction on pipeline steel in nearneutral pH solution. Electrochem. Commun. 9(4), 558–562 (2007) 11. Cheng, Y.F.: Fundamentals of hydrogen evolution reaction and its implications on near-neutral pH stress corrosion cracking of pipelines. Electrochim. Acta 52(7), 2661–2667 (2007) 12. Dey, S., Mandhyan, A.K., Sondhi, S.K., Chattoraj, I.: Hydrogen entry into pipeline steel under freely corroding conditions in two corroding media. Corros. Sci. 48(9), 2676–2688 (2006) 13. Shipilov, S.A., May, I.L.: Structural integrity of aging buried pipelines having cathodic protection. Eng. Fail. Anal. 13(7), 1159–1176 (2006) 14. Effects of Hydrogen on Materials: Proceedings of the 2008 International Hydrogen Conference, September 7–10, 2008, Jackson Lake Lodge, Grand Teton National Park, Wyoming, USA, Somerday, B.P., Sofronis, P., Jones, R. (eds.). Published by ASM International—Materials Park, Ohio. Printed in the USA (2009) 15. Hydrogen-Materials Interaction: Proceedings of the 2012 International Hydrogen Conference, September 9–12, 2012, Jackson Lake Lodge, Grand Teton National Park, Wyoming, USA, Somerday, B.P., Sofronis, P. (eds.). Published by ASM International—Materials Park, Ohio. Printed in the USA (2014) 16. Miresmaeili, R., Liu, L., Kanayama, H.: A possible explanation for the contradictory results of hydrogen effects on macroscopic deformation. Int. J. Press. Vessels Pip. 99,100, 34–43 (2012) 17. Turnbull, A.: Perspectives on hydrogen uptake, diffusion and trapping. Int. J. Hydrogen Energy 40(47), 16961–16970 (2015) 18. Dadfarnia, M., Sofronis, P., Neeraj, T.: Hydrogen interaction with multiple traps: can it be used to mitigate embrittlement? Int. J. Hydrogen Energy 36(16), 10141–10148 (2011) 19. Ahn, D.C., Sofronis, P., Dodds, R.H.: On hydrogen-induced plastic flow localization during void growth and coalescence. Int. J. Hydrogen Energy 32(16), 3734–3742 (2007) 20. Dmytrakh, I.M., Leshchak, R.L., Syrotyuk, A.M.: Effect of hydrogen concentration on strain behaviour of pipeline steel. Int. J. Hydrogen Energy 40(10), 4011–4018 (2015) 21. Stashchuk, M., Dorosh, M.: Evaluation of hydrogen stresses in metal and redistribution of hydrogen around crack-like defects. Int. J. Hydrogen Energy 37(19), 14687–14696 (2012) 22. Rosenberg, G., Sinaiova, I.: Evaluation of hydrogen induced damage of steels by different test methods. Mater. Sci. Eng. A 682, 410–422 (2017)

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23. Cheng, A., Chen, N.Z.: Fatigue crack growth modelling for pipeline carbon steels under gaseous hydrogen conditions. Int. J. Fatigue 96, 152–161 (2017) 24. Rajabipour, A., Melchers, R.E.: Service life of corrosion pitted pipes subject to fatigue loading and hydrogen embrittlement. Int. J. Hydrogen Energy 43(17), 8440–8450 (2018) 25. Nagarajan, V.R., Putatunda, S.K.: Influence of dissolved hydrogen on the fatigue crack growth behaviour of AISI 4140 steel. Int. J. Fatigue 62, 236–248 (2014) 26. Zhanga, T., Zhao, W., Li, T., Zhao, Y., Deng, Q., Wang, Y., Jiang, W.: Comparison of hydrogen embrittlement susceptibility of three cathodic protected subsea pipeline steels from a point of view of hydrogen permeation. Corros. Sci. 131, 104–115 (2018) 27. Mohtadi-Bonab, M.A., Eskandari, M., Rahman, K.M.M., Ouellet, R., Szpunar, J.A.: An extensive study of hydrogen-induced cracking susceptibility in an API X60 sour service pipeline steel. Int. J. Hydrogen Energy 41(7), 4185–4197 (2016) 28. Chatzidouros, E.V., Traidia, A., Devarapalli, R.S., Pantelis, D.I., Steriotis, T.A., Jouiad, M.: Effect of hydrogen on fracture toughness properties of a pipeline steel under simulated sour service conditions. Int. J. Hydrogen Energy 43(11), 5747–5759 (2018) 29. Tang, X., Cheng, Y.F.: Quantitative characterization by micro-electrochemical measurements of the synergism of hydrogen, stress and dissolution on near-neutral pH stress corrosion cracking of pipelines. Corros. Sci. 53(9), 2927–2953 (2011) 30. Zhang, T., Zhao, W., Zhao, Y., Ouyang, K., Deng, Q., Wang, Y., Jiang, W.: Effects of surface oxide films on hydrogen permeation and susceptibility to embrittlement of X80 steel under hydrogen atmosphere. Int. J. Hydrogen Energy 43(6), 3353–3365 (2018) 31. Dmytrakh, I.M.: Corrosion fracture of structural metallic materials: effect of electrochemical conditions in crack. Strain 47(2), 427–435 (2011) 32. Dmytrakh, I.M., Akid, R., Miller, K.J.: Electrochemistry of deformed smooth surfaces and short corrosion fatigue crack growth behaviour. Br. Corros. J. 2(32), 138–144 (1997) 33. Akid, R., Dmytrakh, I.M., Gonzalez-Sanchez, J.: Fatigue damage accumulation: the role of corrosion on the early stages of crack growth. Corros. Eng., Sci. Technol. 4(41), 328–335 (2006) 34. Syrotyuk, A.M., Dmytrakh, I.M.: Methods for the evaluation of fracture and strength of pipeline steels and structures under the action of working media. Part I. Influence of the corrosion factor. Mater. Sci. 50(3), 324–339 (2014) 35. VoltaLab 40 (PGZ301 & VoltaMaster 4). Dynamic Electrochemical Laboratory. Instruction. Radiometer Analytical (2009) 36. Yan, M., Weng, Y.: Study on hydrogen absorption of pipeline steel under cathodic charging. Corros. Sci. 48(2), 432–444 (2006) 37. Capelle, J., Gilgert, J., Dmytrakh, I., Pluvinage, G.: Sensitivity of pipelines with steel API X52 to hydrogen embrittlement. Int. J. Hydrogen Energy 33(24), 7630–7641 (2008) 38. Capelle, J., Dmytrakh, I., Azari, Z., Pluvinage, G.: Evaluation of electrochemical hydrogen absorption in welded pipe with steel API X52. Int. J. Hydrogen Energy 38(33), 14356–14363 (2013) 39. Dmytrakh, I.M., Leshchak, R.L., Syrotyuk, A.M., Barna, R.A.: Effect of hydrogen concentration on fatigue crack growth behaviour in pipeline steel. Int. J. Hydrogen Energy 42(9), 6401–6408 (2017) 40. Suresh, S.: Fatigue of Materials, 2nd edn. Cambridge University Press, Cambridge (1998)

Development of Improved Materials for the Production of Forged Integral Buckle Arrestors Francesca Cena, Giovanna Gabetta, and Giuseppe Cumino

Abstract Submarine pipelines are an industry rapidly changing in innovation and technological advances and developments, particularly in challenging operation conditions and deep water applications. Integral buckle arrestors have proved to be an essential device to limit damages induced by a propagating buckle and to reach and ensure very high performances both during the pipelines laying and the service life. New forged integral buckle arrestors are applied especially in case of large diameters and high wall thicknesses and under extreme external load conditions. Their main goal is to guarantee and improve the integrity of the offshore pipelines. After a brief description of the status of the art, the objective of this paper is to show the efforts in progress to better satisfy the requests of the oil & gas industry. The paper analyses the manufacturing steps to obtain the final product including material, forging and mechanical machining processes, intermediate and final tests and inspection. Keywords Offshore pipeline · Buckle arrestor · Buckle propagation · Collapse · Crossover · Finite element analysis · Design criteria · Material characterization

1 Foreword Offshore pipelines—operating in the challenging conditions of deep and ultra deep water applications—are subject to a wide range of loading conditions resulting from internal and external pressure and bending during installation and operations [1]. They are designed to prevent buckling and collapse failure under normal operation conditions. The structural analysis of cylindrical shells constitutes a classical problem of mechanics, with numerous applications. In particular, the nonlinear response and the F. Cena (B) Cena Interpipes S.R.L, Brescia, Italy e-mail: [email protected] G. Gabetta · G. Cumino Milano, Italy © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_13

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Fig. 1 Pipe collapse under combined loads [2]

loss of structural stability of thin-walled structures such as pipelines is a topic of both fundamental and applied research. In the past, this problem has caused significant controversy due to the unreasonably high analytical predictions of buckling loads, compared with the low buckling loads obtained from relevant experiments. These studies are however out of the subject of this paper, where only the empirical approach that allowed the development of buckle arrestors will be summarized. Unfortunately, design requirements are not always sufficient because off-design events can occur both during installation and operations. Dragging ship anchors, fishing equipment interaction, sinking vessels, dropped objects, mudslides, boulders, extreme waves and current loads or other disturbances [2] can locally reduce the integrity of a pipeline and induce local collapse. This can initiate a buckle which propagates at high speed, potentially resulting in a total failure of the pipeline (see Fig. 1). The external pressure required to thrust a propagating collapse is much smaller than the pressure necessary to initiate it when the pipe is undamaged. It has been found that the propagation pressure (Pp) can be as low as 15% of its collapse pressure (Pco) [3]. To avoid problems and costs associated to a propagating collapse failure, it is convenient and preferred to install buckle arrestors. Buckle arrestors are thick steel rings at regular intervals along the pipelines.

2 Scope of the Buckle Arrestor The pipe response under bending and external pressure loads shows a sudden loss of strength. The ovalization is due to the well-known von Karman-Brazier effect [1]. Bending ovalizes the pipe cross section, gradually reducing its bending rigidity, eventually leading to a limit load instability that is followed by localized ovalization and collapse [4]. Due to the ovalization, the buckle resistance of the pipe could be reduced by as much as 40 percent if there is a significant variation of the wall thickness [5].

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Buckle arrestors locally increase the bending stiffness of the pipe in the circumferential direction [6] and prevent the natural ovalization of the pipe under bending. They shall be properly designed, taking into account the maximum water depth, and will limit the damage to the section between two arrestors, impeding downstream propagation of collapse [3].

3 Forged Integral Buckle Arrestors Buckle arrestors have been the subject of a great deal of research from 1980s up to now. There are many different types of arrestors, all of them typically having the form of thick-walled rings. Depending on the design, they can mainly be categorized as integral arrestors, slip-on arrestors, clamped arrestors, and spiral arrestors, as schematically shown in Fig. 2. Integral buckle arrestors are widely believed to be most efficient in terms of the enhancement of the crossover resistance [7]. The integral buckle arrestor (see Fig. 3) is a ring with the same internal diameter of the pipeline and higher wall thickness. To match the thickness of the pipeline at both ends, transition sections are machined and welded between adjacent sections of pipeline (see Fig. 4). Integral buckle arrestors can be manufactured in welded and seamless (hot rolled and forged) execution. This chapter is focused on the manufacture of forged, quenched and tempered carbon steel integral buckle arrestor, for deep water and ultra-deep water offshore

Fig. 2 Example of different kinds of buckle arrestors [7]

Fig. 3 An example of integral buckle arrestor

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Fig. 4 Integral buckle arrestor assembled to the pipeline

applications where large diameters, high wall thicknesses and high performance material properties are required. The family of steel grades is that of the API 5L Standard, typical for pipelines. Buckle arrestors are required to satisfy some of the same properties of the sealine they are connected with, typically manufactured in smls (hot rolled) or welded execution. This means that: • in case of welded pipelines, forged buckle arrestors include the factor αfab, taking into account the effect on the welding UO/UOE fabrication process (U for U-ing cold forming from the plate, O for O-ing cold forming from the U shape, E for expansion to meet the geometric tolerances), which introduces different strength in tension and compression along the circumferential direction of the pipeline, due to cold deformations (Bauschinger effect); • high pipe wall thickness (more than 30 mm) is not well addressed in the relevant Codes/Standards of the pipelines but it is generally accepted that the methodologies for both brittle/ductile transition and minimum Charpy V requirements are applicable to thicknesses up to 25–30 mm [8]. The first critical point is to achieve the metallurgical, mechanical and corrosion characteristics of the material as required by project specifications. The main properties are the toughness at the minimum design temperature (in particular, Crack Tip Opening Displacement (CTOD), a detailed investigation of complete britlle/ductile transition temperature using both Charpy V and Drop Weight Tear Test (DWTT) specimens) and the corrosion resistance. Requirements can be different for different projects: however, at least the following shall be considered [9]: • specific chemical composition; • hardness; • tensile strength;

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ductility; toughness; weldability; corrosion resistance to H2 S and CO2 , i.e. testing for HIC (Hydrogen Induced Cracking), SSC (Sulfide Stress Cracking) and HISC (Hydrogen Induced Stress Cracking).

4 Development of Improved Materials The production cycle of improved materials for forged integral buckle arrestors shall be analyzed in detail, on the basis of the internal know how, historical data and simulations tools. The process optimization can be implemented using empirical laws and the knowhow from experimental tests. Numerical simulation can be used towards a more systematic and scientific approach in design and manufacturing, especially when the scale ratio between the experimental specimens and the real components is very high: more reliable results can be obtained when the test specimens dimensions are comparable to the real components.

4.1 Steel Making Production Process For high quality items, high quality steel shall be manufactured. A number of parameters shall be controlled in the ingot production. The quality of an ingot is not controlled directly, but in totally indirect way, with the only exception of the chemical composition in the liquid stage. Experience in production of special steel grades ingots—with validated operative practices—play a key role to achieve the best results in terms of cleanliness and homogeneity of the material. The following four main requirements shall be considered and satisfied: • Low level of impurity This means to find the right scraps (see Fig. 5, the charge of the Electric Arc Furnace) and ferroalloys. • Low level of segregation The segregation level is connected to the temperature and pouring rate that is based on desired steel grade and ingot design. Simulation is a powerful tool to verify what happens in the first phase of the pouring and also during the solidification. • Good macrocleanness

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Fig. 5 Electric arc furnace

Macro-cleanness is manly dependent from the starting phase of the pouring and also the position of the pouring powder, both necessary for the protection of the steel during mold filling. • Good microcleanness There is a combination of more parameters in several steps of the process: – – – –

deoxydation; ladle furnace (Fig. 6) treatment; vacuum degassing; interaction with pouring powder.

Controls and recording during every steps of the production provide a detailed overview of the steel elaboration, guarantee the quality of the ingot (Fig. 7) as per design criteria and the repeatability of the achieved results.

4.2 Forging and Heat Treatment Production Processes Forging. To achieve the requested material properties, forging activities and final quality quenching and tempering heat treatment play an important role. Hot forging, shown in Fig. 8, is the process imposing a plastic deformation on the

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Fig. 6 Ladle furnace Fig. 7 Ingot after cooling

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Fig. 8 Open die forging

material, to obtain the desired shape and/or certain material properties, through the optimization of microstructure and the preservation of the flow lines. The forging material is constantly maintained at a high temperature and therefore no particular unwanted tensions or phases are created. After forging, the structure and the grain lose their dendritic conformation and become equiassic. Segregation, possible inclusions, carbides, further chopped nitrides and strengthened casting defects are reduced or eliminated. The contact area and the pressure cones imposed by the forging are significantly higher than those of lamination and this guarantees the deformation of the material at the heart. This allows, after the quality heat treatment, to obtain a significant reduction of the multidimensional dispersion of the material properties, thus increasing the fatigue life of the material. The isotropy of a material is always desired in critical components. The numerical tool typically adopted to simulate this process is the finite element modeling and analysis (FEM), having as input parameters the model mesh, the physico-chemical characteristics of the material and heat exchange parameters (both topologically different within the same model). The thermodynamic simulator allows to quickly and accurately analyze the production stages of the forgings and better understand the physical phenomena that occur with the aim to anticipate and predict their behavior. Heat Treatment. After forging, the quality heat treatment is mandatory. Heat treatment is the last very important operation to achieve the metallurgical properties required by the Customer. Considering the required steel grade (i.e. F60 or F65) as well as the basic chemistry used for the product, the typical heat treatment applied is quenching and tempering.

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Fig. 9 Forged buckle arrestor before quenching

Quenching consists in an austenitization over 900 °C in a gas furnace (Fig. 9), with soaking time defined according to the wall thickness of the buckle arrestor, followed by a quick immersion in a water tank. The water in the tank is under strong agitation and its temperature is controlled and maintained generally below 40 °C. After complete cooling the buckle arrestor is subject to a tempering treatment. This is done generally at temperature below 700 °C with a certain soaking time and the exact temperature/soaking time are defined according to the final metallurgical required properties. To help this definition, the metallurgist can use TTT (Time Temperature Transformation) and/or CCT (Continuous Cooling Transformation) diagrams (see an example of CCT, Fig. 10). Mathematical models are also

Fig. 10 CCT diagram

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available for setting up the heat treatment parameters. Destructive Tests for Forged Material Characterization. A complete package of destructive tests, to verify the achieved metallurgical, mechanical and corrosion properties, and to validate the final buckle arrestor, must be executed on an end section of the forged item in the finished heat-treatment conditions. Most of the tests are performed in correspondence of the greater wall thickness, some other tests are also conducted on the smaller thickness. Here below the list of typical tests: • • • • • • •

chemical composition; hardness test; tensile test; impact test; grain size dimension; inclusion content; other specific tests like CTOD, DWTT, corrosion tests (SSC-HIC-HISC) could be required according to the project.

4.3 Mechanical Machining Mechanical machining follows the whole cycle of fabrication of the forged item (Figs.11, 12 and 13): • depending on the severity of properties and dimensions to be reached, a mechanical preliminary fully body machining for quality heat treatment could be required, to prepare correctly the surface of the forging and achieving the best and most homogeneous results;

Fig. 11 Raw forged buckle arrestor, ready for mechanical machining

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Fig. 12 Buckle arrestor—turning operations

Fig. 13 Buckle arrestor, boring operations (left)—internal surface after honing operation (right)

• after quality heat treatment, fully body mechanical machining is performed to reach the greater wall thickness along all the length of the buckle arrestor and to prepare it for hydrostatic test; • once hydrostatic test has been performed, the new turning operation provides the final shape of the buckle arrestor, with the transition of the wall thickness at both ends to match the wall thickness of the pipeline, and the ends are beveled, for the following activity of girth welds for assembly. A good mechanical machining allows to reduce the required extra-material to get the final shape from the quality heat treated of the forging, thus optimizing the quality heat treatment process.

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Fig. 14 An image of manual ultrasonic test

4.4 Non-destructive Tests and Final Inspection The following final non-destructive tests are performed on the item: • hydrostatic test; • 100% manual ultrasonic test (Fig. 14) for the detection of inclusions and laminations, longitudinal and transversal discontinuities within the agreed acceptance criteria; • 100% magnetoscopic test on the accessible surface of finished buckle arrestor; • final visual and dimensional inspection.

5 Conclusions Integral forged buckle arrestors represent an important technological achievement for the manufacturing Companies and can be strongly recommended for the following reasons: • manufacture of items with large and/or out of standard diameters and very heavy wall thickness; • achievement of very tight tolerances on diameters, wall thickness and ovality, parameters that are taken into consideration during the design phase of the items, especially when local FEM analyses are applied; • achievement of the best isotropy that forged items can guarantee; • absence of longitudinal seam welds; • absence of Baushinger effect typical of the UO/UOE manufacturing process of welded pipes.

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Items

O.D. (mm)

I.D. (mm)

W.T. (mm)

Buckle arrestor

699,24

603,24

48,00

Pipeline

660,40

603,24

28,58

Acknowledgements The work was conducted with the support of Asonext (Steel Making Company) and Forge Monchieri (Forging Company). Any findings, conclusions and recommendations expressed herein are those of the authors and do not necessary reflect those of the above-mentioned Companies.

References 1. Guarracino, F.: Influence of stiffeners and buckling arrestors on the behaviour of offshore pipeline under bending. Int. J. Petrol. Technol. 5, 12–18 (2018) 2. Bartolini, L.M., Marchionni, L., Spinazzè, M., Battistini, A., Parrella, A., Vitali, L.: Pipe strength and deformation capacity: a novel FE tool for the numerical lab. In: Proceedings of the ASME 33rd International Conference on Ocean, Offshore Mechanics and Artic Engineering, OMAE2014, June 8–13. San Francisco, California, USA (2014) 3. Kyriakides, S., Park, T.D., Netto, T.A.: On the design of integral buckle arrestors for offshore pipelines. Appl. Ocean Res. 20, 95–104 (1998) 4. Liu, Y., Kyriakides, S., Hallai, J.F.: Reeling of pipe with L˝uders bands. Int. J. Solids Struct. 72, 11–25 (2015) 5. Muszynski, L.C.: United States Patent 4,449,852. May 22, 1984. Inventor: Muszynski, L.C., Houston, Tex. Assignee: Shell Oil Company, Houston, Tex 6. Toscano, R.G., Mantovano, L.O., Amenta, P.M., Charreau, R.F., Johnson, D.H., Assanelli, A.P., Dvorkin, E.N.: Collapse arrestors for deepwater pipelines. Cross over mechanisms. Center for Industrial Research, TENARIS. Argentina 7. Gong, S., Li, G.: On the prediction of arresting efficiency of integral buckle arrestors for deepwater pipelines. Int J Steel Struct 17(4), 1443–1458 (2017) 8. Torselletti, E., Vitali, L., Bruschi, R.: Design criteria versus line pipe requirements for offshore pipeline. Snamprogetti S.p.A., Fano, Italy 9. Ashtiani, H.T.: A glance through—from conceptual design to detail engineering in submarine pipeline projects. INIOAS. Marine Pipeline Engineering Short course, 12–14 Jan 2014, Teheran, Iran

Assessment of Operational Degradation of Pipeline Steel Based on True Stress–Strain Diagrams Ihor Dzioba, Olha Zvirko, and Sebastian Lipiec

Abstract The in-service degradation of pipeline steels, affecting performance of natural gas transportation infrastructure, is now comprehensively investigated with the usage of various approaches. Steel degradation implies embrittlement and decreasing the mechanical properties, increasing a failure risk of pipelines. The mechanical properties of strength and plasticity, which can be changed due to degradation under long-term operation of pipeline steels, are usually evaluated by tension tests based on the obtained stress–strain diagrams in nominal values, i.e. without taking into account a change of cross-section of specimen during tension. In this paper it is proposed to use true stress–strain diagrams for an assessment of in-service degradation degree of gas pipeline steels. The low-alloyed X52 pipeline steel in as-received state and after 30 years of operation on the gas transit pipeline was investigated. The obtained results demonstrating the advantage of a usage of true stress–strain dependences instead of nominal ones are discussed. Keywords Pipeline steel · Microstructure · Degradation · True stress–strain dependences

1 Introduction In-service degradation of mechanical properties of high-pressure gas transmission pipeline steels is one of the main reasons that may affect the pipeline integrity [1–5]. The problem is that the characteristics of brittle fracture, namely impact strength and fracture toughness, are the most intensively decreased among the mechanical properties of steel during operation. Thus, impact toughness of operated steel reached I. Dzioba (B) · S. Lipiec Kielce University of Technology, Kielce, Poland e-mail: [email protected] O. Zvirko Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_14

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the extremely low value of ~30 J/cm2 ; it was decreased 3–5 times in comparison with that for as-received steel [6]. The resistance to stress corrosion and hydrogen induced cracking, and corrosion fatigue is significantly reduced as well, especially at the stage of corrosion crack growth [7–10]. It is very important for pipeline steels, since these failure mechanisms are acknowledged as the predominant failures in pipeline steels in wet environments, which causes the rupture of natural gas transit pipelines. Strength and plasticity characteristics are less sensitive to the in-service degradation of pipe steels; operational changes in them are lower than that in other mechanical characteristics. The recent trend was to evaluate steel degradation by application of the mechanical stability concept [11] based on determining degree of embrittlement and residual mechanical stability of operated steel indicating loss of plasticity. In general, a significant decrease in resistance to brittle fracture and corrosionmechanical fracture is accompanied by some decrease in plasticity of steel. However, decreasing basic plasticity characteristics of steel due to long-term service is much less noticeable than its brittle and corrosion-mechanical fracture resistance. Therefore, determining plasticity of a metal based on tensile stress–strain diagrams in nominal values could be insufficient to make a proper decision about the effect of long-term operation on metal state and its degradation degree. This article presents a method for assessing the condition of material of a gas pipeline based on the analysis of stress and strain fields in the local area in front of the crack tip. The proposed approach is based on the concept of local fracture criteria. Those criteria assume that the failure process will be initiated when stresses or strains exceed a critical value in a certain critical area of the material [12, 13]. When the critical stress values are reached and exceeded, the failure involves cleavage fracture, while, if the critical strains are reached, the mechanism of development and coalescence of voids is involved in the failure process [14, 15]. To calculate the stress and strain fields in the local most stressed areas it is necessary to know the true stress–strain relationship of the material. Creating such a relationship is a complex task. Solutions to this problem have been presented in a number of works in recent years [16–18]. However, still a method is missing that would unequivocally describe the relationship in a range of large strains of the material, exceeding of 100% of strain level. In this article, the authors propose a method to create the true stress–strain relationship based on the experimental results obtained from tensile tests. Critical values of stress and strain are proposed to be determined based on metallographic study of the microstructure of the material of specimens subjected to uniaxial tensile testing.

2 Materials In this paper low-alloyed API 5L X52 pipeline steel was investigated. API 5L X52 steel was the most common gas pipeline material used for transit of oil and gas during 1950–1960. The chemical composition of the steel is presented in Table 1. The specimens were cut out from two different pipes: reserved pipe (in the as-

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Table 1 Chemical composition of X52 steel (wt.%) Steel

C

Mn

Si

P

S

X52_00

0.23

0.94

0.33

0.006

0.018

X52_30

0.21

0.96

0.41

0.023

0.040

Fig. 1 Ferrite-pearlite microstructure of X52 pipeline steel: a as-received state and b after 30 years of operation

received state) and pipe after 30 years of operation, marked as X52_00 and X52_30, respectively. The microstructure of X52 steel of tested pipes was analysed by the SEM. The steel had a ferrite-pearlite microstructure (Fig. 1).

3 Basic Mechanical Properties of Tested Steels Basic mechanical characteristics, namely ultimate strength σ UTS , yield strength σ Y , reduction in area (RA) and elongation (Elt ) were determined using uniaxial tension tests of cylindrical specimens with gauge length of 25 mm and diameter about 5.0 mm. Testing was performed on specimens cut out from the pipes in longitudinal direction with the major axis parallel to the rolling direction of the pipe. Tensile testing of specimens was carried out at ambient temperature according to standard ASTM [19]. The nominal stress–strain diagrams are presented in Fig. 2. The mechanical characteristics obtained from uniaxial tensile tests are presented in Table 2. The data obtained during these tests were used to obtain true stress–strain diagrams of materials that would be presented below at next section of this chapter. The standard specimens for impact testing (10 × 10 × 55 mm with V-type notch) were machined from pipes in longitudinal direction and tested according to ASTM Standard [20]. Next results were obtained: for unexploited pipeline material CV =

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Fig. 2 The stress–strain diagrams of pipeline steel: for as-received state and after 30 years of operation

Table 2 The nominal mechanical characteristics of X52 steel Steel

E (GPa)

σ YS (MPa)

σ UT (MPa)

εUTS

El t (%)

RA (%)

Ru (MPa)

X52_00

200

469

542

0.11

25.7

73.3

1473

X52_30

202

484

658

0.14

25.3

79.1

1500

E—Young’s modulus; σ YS —yield strength; σ UTS —ultimate tensile strength; εUTS —strain at ultimate tensile strength; El t —total elongation; RA—reduction of specimen area; Ru —rupture stress

142 J or KCV = 177 J/cm2 ; for pipeline material after 30 years of service, CV = 52 J or KCV = 65 J/cm2 .

4 Analysis of In-Service Degradation of Pipeline Steel For pipeline steel after 30 years of operation, compared to the steel in the as-received state, the level of strength characteristics σ UTS is significantly higher, while the yield strength σ YS after service does not significantly exceed the corresponding characteristics for pipeline steel in the initial state (Table 2, Fig. 2). For the plasticity characteristics, no clear difference was noted for the as-received material of pipeline and those after 30 years of service. However, impact strength decreased sharply, about three times decrease of KCV level was noted for operated steel compared to the initial state. For metal after 30 years of service KCV is equal only to 65 J/cm2 , which is too low for this type of steels in as-received state. The obtained results may indicate that the difference in the level of KCV characteristics for X52_00

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and X52_30 steels is caused not only by difference in the microstructure, but by the in-service degradation of the pipeline metal, as well. Comparable low levels of impact characteristics of gas pipeline steels after long-term operation have also been presented in the papers [1, 3, 6]. It should be noted that the service embrittlement of pipeline steel, which is demonstrated by decrease of the impact fracture characteristic, was not accompanied by the corresponded change of nominal plasticity characteristics. Accordingly, the nominal plasticity characteristics are not sensitive to processes of steel embrittlement. Therefore, a necessity arises to search the characteristics of the material sensitive to operational embrittlement. For this reason, the approach of the stress and strain analysis in a most loaded local area using the true stress–strain relationship of material seems to be a good approach to assess degradation degree. The values obtained in this analysis may be sensitive to in-service degradation of pipe steel.

5 Technique of True Stress–Strain Diagrams Obtaining The process of creating the true stress–strain relationship can be divided into several basic stages: (1) the elastic range; (2) uniform elastic specimen elongation range; (3) the range of neck formation [18]. At the first and second stage, the gage length of the specimen elongates evenly over the entire length so, assuming the constant volume principle, it is not difficult to demonstrate that the true stress and strain values are calculated from formulas: σt = σn (1 + εn ), εt = ln(1 + εn )

(1)

In the Eq. (1), σ n and εn are the nominal stress and strain values over the section of uniform elongation of the specimen, i.e. until neck formation (Fig. 3). At the section between the corresponding points, σ YS and σ UTS , the stress–strain relationships are described by a power function: ε = ασ n . The exponent of the selected function is called the material strengthening factor n. The n values for the materials tested are given in Table 3. On the other hand, the description of the stress–strain relationship over the neck formation section is less precise. The key problem here is to determine the true critical stress and true critical strain values which correspond to the moment of the specimen rupture. Various techniques to obtain the true stress–strain relationship have been proposed. The direct extension (extrapolation) of the power function obtained for the uniform elongation section is not verified, as the numerical results differ significantly from the experimental results [21]. Some researchers directly select that relationship iteratively so that the results of numerical calculations using the above relationship are as close as possible to the experimental results [22]. In a number of works, it has been proposed to calculate the stress and strain levels in the neck considering it as a concentrator with a radius of R [23, 24]. This approach is only suitable for materials with low plasticity [18]. A more advanced method

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Fig. 3 The stress–strain diagrams of pipeline steel: a for as-received state and b after 30 years of operation

Table 3 The basic values of the true stress–strain dependences for X52 steel Marks

E (GPa) σ YS (MPa) εt_UTS σ t_UTS (MPa) n

l0 (µm) lc (µm) εt_c

σ t_c (MPa)

X52_00 201

472

0.10

620

10.9 12.65

56.85

3.43 1604

X52_30 203

487/502

0.13

770

5.5 11.67

40.76

2.49 1650

εt_UTS and σ t_UTS are true strain and stress values at ending part of specimen evenly elongation

of obtaining a constitutive relationship for material with the high level of strain in a neck was proposed by Bai and Wierzbicki [16]. In their method, for the stress– strain relationship, the triaxiality stress factor and the Lode parameter are also taken into account. Calibration of this relationship is performed on specimens of various shapes and concentrators to secure a wide range of their variability. A modification and supplement of this method, consisting in the introduction of the function, which describes the material weakness caused by the initiation and development of voids, was proposed by Neimitz et al. [17, 21]. The research showed that the procedure to obtain the true stress–strain relationship for materials with a low level of plasticity can be simplified by limiting the stage of uniform elongation of the sample material [25]. During the tests performed to determine the nature of the true stress–strain relationship in the section that corresponds to the neck formation, the rectilinear type relationship was found the most appropriate [17, 21]. This type of dependence was also used to obtain the constitutive relationship in this article. To define the linear relationship, the knowledge of coordinates of at least two points is required. It was assumed that the coordinates for the first point were equal to those of the last point of the power relationship describing the uniform specimen elongation during the tests. For determination of the coordinates of the second point, experimental results taken

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from the tested specimen were used. The critical stress is commonly calculated as the ratio of force to cross-section of the specimen at rupture: σ c = F c /S c . In order to determine the level of critical strain (at the moment of rupture), metallographic microstructure tests were performed. The microstructure of the material was compared in a non-deformed and deformed condition in the neck, in close proximity to the place of rupture. The steel microstructure for those two positions is shown in Figs. 4 for unexploited pipe (a, b) and pipe after 30 years of operation (c, d), respectively. It can be seen in Fig. 4b, d that the grains of both tested steels deformed during necking are elongated and their basal planes are oriented parallel to the tensile direction. When determining the strains, the average ferrite grain size in the material of the respective pipe was assumed as the base unit. The strain at the critical moment was determined as the ratio of the average grain elongation increment (lc – l 0 ) to its base value in a non-deformed condition (l0 ): εt_c = (l c – l 0 )/l 0 . The strain values determined on dimensional basis equalled to the average ferrite grain size were assumed as the true strain values. Adopting the principle of maintenance of a constant volume of the

Fig. 4 Microstructure of X52 steel in as-received state (a, b) and after 30 years of operation (c, d): a, c undeformed material and b, d deformed in the neck

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Fig. 5 The true stress–strain dependence: a the scheme of a dependence and b the dependences obtained for tested states of X52 steel

ferrite grain, the neck cross-section was calculated directly at the rupture point: Sc = S 0 /4.43 for specimens of the unexploited steel and Sc = S 0 /3.49—after 30 years of operation. The true stress–strain relationships obtained in that way are shown in Fig. 5 and the characteristic values for those relationships are given in Table 3. According to the data in Table 3 it follows, that in contrast to the nominal plasticity characteristics, the value εt_c characterizing the true critical strain in the specimen neck directly near the fracture surface is more sensitive to the impact of operational degradation of the pipeline steel. For steel in the unexploited state εt_c = 3.43, and for that after 30 years of operation εt_c = 2.49, which indicates a reduction of about 27%. Consequently, the εt_c plasticity characteristic allows a qualitative assessment of the operational degradation degree of pipeline steel without the need for impact fracture or fracture toughness tests.

6 Numerical Modelling and Loading Simulation of a SENB Specimens In order to determine the stress and strain fields in the local area of the material in front of the crack tip, the SENB specimen modelling and load simulation were carried out using the finite element method. The true stress–strain relationships were introduced as materials constitutive dependences. For modelling, load simulation, and calculation of stress and strain fields the ABAQUS program was used. For numerical calculations, a model of three-point bend specimen SENB (W = 24 mm, S = 96 mm, B = 12 mm, a0 /W = 0.55) was worked out. 1/4 of the SENB specimen was modelled, due to existing symmetry (Fig. 6). The numerical specimen model was divided into 21 layers in the thickness direction. The front of the crack

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Fig. 6 The schemes of specimen model used in numerical calculation

was modelled as an arc with a radius of 0.012 mm. 8-node, three-dimensional finite elements were adopted. The size of the elements was reduced in direction to the crack front. The choice of the finite element size and the division of the specimen into layers was preceded by preliminary analyses in order to achieve convergent analysis results with the appropriate quality of the finite element mesh. The definition of boundary conditions assumed the following: (1) the possibility to move the cracked part of the XOZ specimen; (2) blocking the possibility of movement of the uncracked part of the XOZ specimen along the y axis; (3) blocking the possibility of moving the central plane of the XOY specimen along the z axis; (4) complete blockage of the lower roller (Fig. 6). The true stress–strain relationships of X52 pipeline material in different states defined according to the method described in the previous section were introduced into the numerical model. The load on the SENB specimen was applied by displacement it at the point of force application. For both materials, the calculation of stress and strain fields was carried out for the same level of displacement, which was equal to 1.2 mm. This level of displacement corresponds to the maximum values obtained in the stress distributions for the as-received pipeline steel.

7 Results of Numerical Calculation of Mechanical State in Crack Tip for a SENB Specimen As a result of numerical calculations performed, the stress and strain distributions in front of the crack tip were obtained for X52 steel of two pipes, the as-received one and the one after 30 years of operation (Fig. 7). According to the main criteria of the brittle fracture [12, 13], brittle fracture is possible in the material if in a certain local area of the material the level of normal stress to the crack plane exceeds the critical value. A high level of triaxiality stress factor η is also necessary for realization of brittle fracture [14, 15]. A triaxiality stress

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Fig. 7 The results of numerical calculation: stress components distributions for a X52_00 and b X52_30 steel; c the stress state factor distributions η and d distributions of plastic strain

factor η defined as: η = σm /σeff

(2)

σm = (σ11+ σ22+ σ33 )/3

(3)

1/2  = 1/6[(σ11 − σ22 )2 + (σ22 − σ33 )2 + (σ11 − σ33 )2 ] σeff = (3J2 )1/2 = 3/2sij sij (4) where σ m is a middle (hydrostatic) stress, σ eff is an effective stress.

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Table 4 The basic characteristic points of stress and strain distributions Steel

σ 22

σ 22 /σ YS

Max level (MPa)

Distance from crack tip (mm)

X52_00

1429

0.337

X52_30

1480

0.206

η

εpl_eff

Max level

Distance from crack tip (mm)

Max level

Distance

3.02

2.32

0.375

1.31

In front

3.03

2.46

0.273

1.35

In front

Therefore, as presented in the papers [26, 27], an increase in the level of normal stress, an increase in the value of the triaxiality stress factor, and a decrease in the distance from the crack tip to the point of occurrence of the maximum normal stresses, indicate an increase in the susceptibility of the material to cracking according to the brittle mechanism. The X52 steel of gas pipeline operated for 30 years shows a higher tendency to brittle fracture compared to the as-received metal, as that material achieves a higher level of stress, stress maximum is closer to the crack tip, and the triaxiality stress factor distributions achieve higher values, as well (Fig. 7, Table 4). The correctness of the prediction was proven by the results of testing the specimen for impact strength. The impact strength of the pipeline steel after 30 years of operation was lower compared to the as-received material. The reduction of the impact characteristic of the material after 30 years of operation was almost threefold. For the pipeline steel after many years of service, a decrease of about 27% in the true critical strain was also observed. Moreover, the increase in the operational brittleness of the investigated steel of gas pipeline resulted not only from the impact of stress arising from load factors, but also from the effect of hydrogen absorbed by the metal during electrochemical corrosion due to interacting with transported hydrocarbons and penetrated through the pipe wall [28]. Subsequently, a higher level of maximum stress and its location closer to the crack tip means a higher stress gradient, which is the driving force behind the hydrogen diffusion process around the crack tip [29]. That in turn leads to an increase in the concentration of hydrogen to a level at which brittle fracture of steel caused by hydrogen embrittlement occurs.

8 Closing Remarks The API 5L X52 pipeline steel in as-received state and after 30 years of service was studied. The metal in-service embrittlement was evidenced by decreasing impact strength of the exploited steel up to three times compared with that of the steel in as-received state. However, the nominal characteristics of plasticity were practically insensitive to in-service degradation of the metal.

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The method of obtaining the true stress–strain relationship was proposed, in which the average ferrite grain size of the tested material, the API 5L X52 steel, was assumed as the basis for measurement. The critical level of strain and stress was determined by measuring the deformed ferrite grains in close proximity to the specimen fracture plane. It was shown that the value of the true plastic strain of material εt_c , which, according to the proposed approach, characterized the real strain of steel directly at the fracture surface, was sensitive to the service degradation of gas pipelines steel. For the steel of gas pipeline operated for 30 years, the level εt_c was about 27% lower than for the as-received one. The obtained constitutive dependencies of the materials were used to calculate stress and strain distributions in the numerically modelled SENB specimen. Such approach allowed the analysis of stress and strain fields in the most stressed area of materials that can occur in real pipelines directly close to crack-like defects. As a result of the analysis, it was determined that the pipeline steel after 30 years of operation is more susceptible to brittle fracture than the steel of the unexploited pipeline.

References 1. Krasowsky, A.Y., Dolgiy, A.A., Torop, V.M.: Charpy testing to estimate pipeline steel degradation after 30 years of operation. Proc. Charpy Centary Conf. Poitiers 1, 489–495 (2001) 2. Tsyrul’nyk, O.T., Nykyforchyn, H.M., Zvirko, O.I., Petryna, D.Y.: Embrittlement of the steel of an oil-trunk pipeline. Mater. Sci. 40(2), 302–304 (2004) 3. Maruschak, P.O., Danyliuk, I.M., Vuherer, T., Bishchak, R.T.: Impact strength of main gas peline steel after prolonged operation. Metallurgist 59(3–4), 324–329 (2015) 4. Bolzon, G., Rivolta, H., Nykyforchyn, H., Zvirko, O.: Mechanical analysis at different scales of gas pipelines. Eng. Fail. Anal. 90, 434–439 (2018) 5. Krechkovs’ka, H.V., Tsyrul’nyk, O.T., Student, O.Z.: In-service degradation of mechanical characteristics of pipe steels in gas mains. Strength Mater. 51(3), 406–417 (2019) 6. Zvirko, O., Gabetta, G., Tsyrulnyk, O., Kret, N.: Assessment of in-service degradation of gas pipeline steel taking into account susceptibility to stress corrosion cracking. Proc. Structural Integr. 16, 121–125 (2019) 7. Zagorski, A., Matysiak, H., Tsyrulnyk, O., Zvirko, O., Nykyforchyn, H., Kurzydlowski, K.: Corrosion and stress corrosion cracking of exploited storage tank steel. Mater. Sci. 40(3), 421–427 (2004) 8. Andreikiv, O.E., Hembara, O.V., Tsyrulnyk, O., Nyrkova, L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238 (2012) 9. Zvirko, O.I., Savula, S.F., Tsependa, V.M., Gabetta, G., Nykyforchyn, H.M.: Stress corrosion cracking of gas pipeline steels of different strength. Proc. Struct. Integr. 2, 509–516 (2016) 10. Nykyforchyn, H., Krechkovska, H., Student, O., Zvirko, O.: Feature of stress corrosion cracking of degraded gas pipeline steels. Proc. Struct. Integr. 16, 153–160 (2019) 11. Meshkov, Y.Y., Shyyan, A.V., Zvirko, O.I.: Evaluation of the in-service degradation of steels of gas pipelines according to the criterion of mechanical stability. Mater. Sci. 50(6), 830–835 (2015) 12. Ritchie, R.O., Knott, J.F., Rice, J.R.: On the relationship between critical tensile stress and fracture toughness in mild steel. J. Mech. Phys. Solids 21, 395–410 (1973)

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13. Pineau, A.: Development of the local approach to fracture over the past 25 years: theory and applications. Int. J. Fract. 138, 139–166 (2006) 14. Dzioba, I., Pala, R.: Strength and fracture toughness of Hardox-400 steel. Metals 9, 508 (2019a) 15. Dzioba, I., Lipiec, S.: Fracture mechanisms of S355 steel—experimental research. FEM Simul. SEM Observe. Mater. 12(23), 3959 (2019a) 16. Bai, Y., Wierzbicki, T.: Application of extended Mohr-Coulomb criterion to ductile fracture. Int. J. Fract. 161, 1–20 (2010) 17. Neimitz, A., Galkiewicz, J., Dzioba, I.: Calibration of constitutive equations under conditions of large strains and stress triaxiality. Arch. Civil Eng. Mater. 18, 1123–1135 (2018) 18. Tu, S., Ren, X., He, J., Zhang, Z.: Stress-strain curves of metallic materials and post necking strain hardening characterization: a review. Fatigue Fract. Eng. Mater. Struct. 1–17 (2019) 19. ASTM E8: Standard test method for tension testing of metallic materials. ASTM International West Conshohocken, PA, USA (2003) 20. E23-07a: Standard Test Methods for Notched Bar Impact Testing of Metallic Materials. Annual Book of ASTM Standards: West Conshohocken, PA, USA (2011) 21. Neimitz, A., Galkiewicz, J., Lipiec, S., Dzioba, I.: Estimation of the onset of crack growth in ductile materials. Materials 11, 2026 (2018) 22. Deprenski, L., Seweryn, A.: Experimental research into fracture of EN-AW 2024 and EW-AW 2007 aluminum alloy specimens with notches subjected to tension. Exp. Mech. 51, 1075–1094 (2011) 23. Gromada, M., Mishusis, G., Oshner, A.: Correlation formulae for the stress distribution in round tension specimens at neck presence. Springer Science and Business Media (2011) 24. Choung, J.M., Cho, S.R.: Study on true stress correlation from tensile test. J. Mech. Sci. Technol. 22(6), 1039–1051 (2008) 25. Dzioba, I., Lipiec, S.: Calibration of constitutive equations for materials with different levels of strength and plasticity characteristics based on uniaxial tensile test data. IOP Conf. Series: Mater. Sci. Eng. 461(012018), 1–6 (2018) 26. Dzioba, I., Pala, R.: Influence of the local stresses and strains at the crack tip on the mechanism of fracture of Hardox-400 steel. Mater. Sci. 55(3), 345–351 (2019b) 27. Dzioba, I., Lipiec, S.: Evolution of the mechanical fields and fracture process of S355JR steel. Proc. Struct. Integr. 16, 97–104 (2019b) 28. Tsyrulnyk, O.T., Slobodyan, Z.V., Zvirko, O.I., Hredil’, M.I., Nykyforchyn, H.M., Gabetta, G.: Influence of operation of Kh52 steel on corrosion processes in a model solution of gas condensate. Mater. Sci. 44(5), 6190–629 (2008) 29. Toribio, J., Kharin, V.: The effect of history on hydrogen assisted cracking: 1. Coupling of hydrogenation and crack growth. Int. J. Fract. 88, 233–245 (1997)

Effect of Impact-Oscillatory Loading on the Variation of Mechanical Properties and Crack Resistance of Pipe Steel Mykola Chausov, Pavlo Maruschak, Andrii Pylypenko, and Andriy Sorochak

Abstract To study a full range of the mechanical properties on small-sized flat specimens from the pipe steel, including the characteristics of crack resistance after the realization of certain loading modes, the authors used the method of complete stress–strain diagrams. This method was previously substantiated both theoretically and experimentally by professors A. A. Lebedev and M. G. Chausov for assessing the fracture kinetics of plastic materials on small specimens subjected to various types of preliminary loading. The effect of preliminary plastic deformation under static tension on changes in the crack resistance and mechanical characteristics of the pipe steel is extreme at a strain level εpl = 6.3%. Test results were compared at identical levels of the preliminary plastic deformation under static tension and impact-oscillatory loading at strain levels of 4.5–8.8%. The comparison showed significant differences in the effect of impact-oscillatory loading on changes in the mechanical properties and crack resistance of the pipe steel. Nanotechnologies were used to analyze the original results on the effect of preliminary plastic deformation under static tension and identical levels of dynamic deformations caused by impactoscillatory loading on changes in the mechanical properties and crack resistance of the 17G1S-U pipe steel in the initial state. This was especially noticeable when tungsten carbide and carbon nanoparticles were used under impact-oscillatory loading. To confirm the revealed mechanical effects, detailed fractographic studies of specimen fractures were conducted along with investigations into the surface macrohardness of the steel. Keywords Pipe steel · Fracture · Failure analysis · Impact-oscillatory loading

M. Chausov · A. Pylypenko National University of Life and Environmental Sciences of Ukraine, Kyiv, Ukraine P. Maruschak (B) · A. Sorochak Ternopil National Ivan Puluj Technical University, Ternopil, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_15

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1 Introduction Pipe steel 17G1S-U is widely used in domestic pipelines [1, 2]. The overstrain of pipes due to the movement of surrounding soil in shear zones, the excessive bending of pipes during laying operations, as well as bending of insufficiently fixed sections of pipelines cause the formation of plastically deformed zones in pipelines, which, as a rule, turn into crack-like defects. The latter can develop over time and lead to emergencies. In literature, there are lots of experimental data on the effect of previous plastic deformation at static tension on changes in the mechanical properties and crack resistance of materials of different classes. Moreover, the nature of these changes can differ significantly depending on the original mechanical properties and structure of materials [3–5]. On the other hand, it should be noted that plastically deformed zones can also be formed in pipelines due to impact-oscillatory loading, for example, under hydroshock in pipe systems. As shown by numerous studies on various materials conducted by the authors, the effect of impact-oscillatory loading on the mechanical properties of materials and crack resistance under subsequent loading requires further study. Under such circumstances, low-cycle (15 … 20 cycles) high-frequency (1 … 2 kHz) loading with a high level of stress amplitude (tens of MPa) can be realized, which usually leads to the formation of specific dissipative structures in plastic materials, the density of which is less than that of the base material. The authors call this type of impact-oscillatory loading a Dynamic Nonequilibrium Process (DNP) [6–9]. Thus, the identical levels of the preliminary plastic deformation under static tension and impact-oscillatory loading may cause different effects on changes in the mechanical properties and crack resistance of the pipe steel under subsequent loading. A clear consequence of significant structural transformations of materials under impact-oscillatory loading is the appearance of microextrusions on the specimen surface due to the formation of less dense dissipative structures [9]. This effect indicates changes in the structure and mechanical properties in the volume and, to a greater extent, in the surface layers of materials. In addition, a special plastic “wave” was detected, which passed along the surface of flat specimens during the realization of DNP [10]. The “wave” front moved at a low speed. For example, for stainless steel 12Kh17, this speed was 0.3–0.7 m/s. The occurrence of the plastic “wave” under impact-oscillatory loading along with microextrusions on the specimen surface allows assuming the possibility of significant deformations in local points of the surface layers of materials. The authors used the revealed effects to develop an effective method for the hardening and nanostructuring of the material surface and to obtain a uniformly controlled nanostructure of the surface layer with an enhanced mechanical strength using impact-oscillatory loading and nanosolutions of various metals [11, 12].

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2 Methods of Mechanical and Physical Research All mechanical tests were performed on a modernized ZD-100Pu testing machine equipped with two special devices, one of which was for recording complete stress– strain diagrams, and the other for applying additional impulse loads of varying intensity at any given degree of initial static deformation [13]. Specimens from pipe steel 17G1S-U in the initial state with a thickness of 2.45 mm (Fig. 1) were tested. The specimens were cut from a pipe with a diameter of 1220 mm and a wall thickness of 8 mm in the longitudinal direction. The corresponding mechanical characteristics of the steel in the initial state were: σys = 420 MPa, σus = 580 MPa, δ = 23%. The intensity of impulse introduction of energy into the steel was adjusted by changing the dynamic strain εimp , which was measured by optical method [7]. The choice of εimp as a parameter that characterizes the intensity of impulse introduction of energy into the alloys greatly simplifies the test procedure. Since the modes of impact-oscillatory loading can be created on hydraulic test machines of different rigidity, the complex calculations of effect of transfering a certain force directly to the specimen, depending on the total impulse applied to the mechanical system, were unnecessary. In addition, such procedure made it possible to evaluate the effect of intensity of energy impulse introduction on changes in the mechanical properties of the steel under study, which will be shown later. The strain measurement base under static tension was 16 mm. Measurements were made using a standard extensometer. Specimen fractures were studied by electron scanning microscopy on a REM 106I microscope [14, 15]. Macrohardness of the surface layers of specimens was measured on the NPO-10 hardness meter using the Vickers method at a working load of 5 kg. The number of injections made on each test site from both sides of the test specimen was 30. It should be noted that in conditions of full-scale fluidity, there are practically no reliable methods for assessing crack resistance of materials on small-sized specimens. Therefore, crack resistance of plastically deformed pipe steel 17G1S was measured by the authors of [16] on beam specimens at 233 K, since room temperature was not suitable to obtain the flat-deformed state during fracture of specimens. To study the

Fig. 1 Test specimen

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full complex of mechanical properties of the plastically deformed pipe steel 17G1SU, including the characteristics of crack resistance, a new method to study the fracture kinetics of materials, the so-called method of complete stress–strain diagrams, was used at room temperature in this research. This method was theoretically and experimentally substantiated by professors Lebedev and Chausov [17]. They were the first to develop a new fracture toughness criterion Kλ based on the analysis of complete stress–strain diagrams. Kλ =



√ Sk · l p · E, (MPa m),

(1)

Here, S k is the real resistance of the torn-off material; i.e., the specimen elongation at the growth stage of the macrocrack of tearing, normalized to the cross-sectional area of the standard specimen; E is the Young’s modulus of materials, for steel 17G1S-U it is equal to 2 × 105 MPa. In the process of construction of a complete stress–strain diagram, the stability of the material deformation and fracture is ensured at all stages, including the stage of initiation and propagation of a macrocrack in the material. It is important that when using the complete stress–strain diagram method, all operations of simple or complex loading are performed on the same small-sized specimens. In addition, changes in the mechanical properties of materials, including crack resistance, under subsequent static tension are evaluated on the same specimens. When complete stress–strain diagrams of sheet materials are recorded, different fracture mechanisms are observed, which are associated with the formation of an internal macrocrack of tearing in the sheet material, its exit to the lateral surfaces of the sheet material with the formation of a cross-sectional macrocrack, and its subsequent growth in width [18]. This causes difficulties in identifying the auto-growth of the macrocrack of tearing. Therefore, the authors have improved the procedure to study the energy costs on the crack growth in sheet materials using the method of complete stress–strain diagrams [8, 11]. The proposed method effectively utilizes the technical possibility of ensuring the stability of the material fracture micromechanism (I + III). To this aim, identical central circular holes were drilled in specimens. Due to this, the auto-growth of the macrocrack by a mixed type of fracture (I + III) is ensured, and the initial almost straight descending sections are recorded on complete stress–strain diagrams. In this case, the influence of the preliminary plastic deformation of the pipe steel on the static crack resistance is assessed with exactly the same mixed type of fracture (I + III). Therefore, the proposed method makes it possible to reliably estimate changes in energy costs for the development of cracks by type (I + III), depending on the nature of the previous plastic deformation—dynamic or static. Thus, bending of the straight descending branch of the stress–strain diagram (upwards or downwards) and the S k value at the macrocrack start allow us to unambiguously judge about changes in the crack resistance of a particular sheet material at room temperature. The research technique was as follows. At first, a series of specimens from pipe steel 17G1S-U were subjected to a gradually increasing pulse loading. After a jump

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Table 1 Crack resistance Kλ for steel 17G1S-U subjected to different modes of previous plastic deformation  √  Designation of the test scheme εpl (%) εimp (%) S k (MPa) l p (mm) K λ MPa m A

4.5

–

724.18

0.72

322.9

B

6.3

–

622.48

1.53

436.4

C

8.8

–

706.21

0.76

327.6

D

–

4.5

856.53

0.97

407.6

E

–

6.3

563.64

1.29

381.3

F

–

8.8

686.75

0.90

351.6

of dynamic deformation, the specimens were completely unloaded immediately. In addition, tungsten carbide nanosolution (W–C) and carbon (C) nanosolution were applied to some specimens in this series prior to the application of additional impulse loads. For further studies, three increasing degrees of previous dynamic deformation due to impact-oscillatory loading εimp = 4.5; 6.3; 8.8% were selected. Next, the specimens of the second series were deformed to the same levels of deformation by static stretching εpl = 4.5; 6.3; 8.8%. Only such sequence of mechanical tests guarantees exactly the same values of plastic deformation under dynamic and static loading. After that, identical holes 1 mm in diameter were drilled in the middle of the workpiece, and all specimens were reloaded by static tension until fully divided into parts under conditions of balanced deformation according to loading schemes: A, B, C, D, E, F, see Table 1.

3 Results of Experimental Studies and Discussion Figure 2 presents some results of the studies in the diagram coordinates F − l. This is done to demonstrate the method of parameter definition lp (see Fig. 2d, h). The unloading was performed on the descending sections of all stress–strain diagrams to estimate the elastic energy reserve by measuring the specimen strain at the macrocrack start. This energy is part of the total energy required for the crack propagation under the full-scale yielding of the specimen material. The results obtained are shown in Fig. 2. On the left (Fig. 2a–c), the effect of the preliminary plastic deformation under static tension on the mechanical properties and crack resistance of steel 17G1S-U is generalized. On the right (Fig. 2e–g), the impact of the preliminary plastic deformation caused by DNP is systematized. The data shown in Fig. 2 were obtained by repeated static stretching under equilibrium deformation. The analysis of Fig. 2a–c shows the extreme nature of the effect caused by previous plastic deformation under static tension on changes in the mechanical properties of pipe steel upon repeated equilibrium deformation. Structural changes leading to this are the topic of individual research. In this case, we can only state that strength properties of the steel are deteriorated significantly at the previous plastic deformation

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Fig. 2 Changes in mechanical properties of steel 17G1S-U subjected to different modes of previous plastic deformation: a–c static tension εpl = 4.5; 6.3; 8.8%; d–f impact-oscillatory loading εimp = 4.5; 6.3; 8.8%; d, h comparative analysis of diagrams

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Fig. 3 Variation of Kλ for steel 17G1S-U subjected to different modes of previous plastic deformation

εpl = 6.3%. At the same time, the plastic properties are improved significantly. It is noteworthy that strength properties of the steel subjected to previous plastic deformations εpl = 4.5 and 8.8% remain virtually unchanged. The revealed patterns of changes in the mechanical properties of the steel directly affected the variation of crack resistance Kλ . Table 1 presents the relevant data. The results of comparing the effect of identical previous plastic deformations under static tension and impact-oscillatory loading without using nanotechnology are not considered in detail in this research. However, nearly identical patterns (see the comparison of the curves in Fig. 2e and Table 1) are revealed from the test results. Impact-oscillatory loading practically does not impair the strength properties of the steel in the variation range of the previous plastic deformation under study. However, it reduces the plastic properties and crack resistance of the steel. At the same time, nano-solutions of tungsten carbide and carbon added to the steel subjected to impactoscillatory loading can improve the mechanical properties and crack resistance of the steel (see the comparison of the curves in Fig. 2d, h and Table 1). It is noteworthy that the abnormal behavior of steel at εpl = 6.3% was repeated at εimp = 6.3%. According to the results of Table 1, a graph of Kλ variation for steel 17G1S-U subjected to different modes of previous plastic deformation is constructed (Fig. 3). Here, we should pay attention to the fact that crack resistance of steel 17G1S-U has an extreme character depending on the previous plastic deformation at static tension. A similar effect was obtained earlier by the authors in assessing crack resistance of pipe steel 17G1S [16]. However, the maximum on the curve showing the dependence of K1c on the previous plastic deformation εpl was about 10% in [16]. In the development of the Kλ parameter, the authors indicated that with an increase in the stiffness of the stress state at the start of the macrocrack of tearing, the Kλ parameter approaches the K1c [19, 20]. For engineering calculations of a wide range of plastic materials, a simple algorithm for estimating the K1c based on the test results of small-sized specimens was proposed: K1c = α Kλ , where α = 0.23. Using coefficient α, it is possible to roughly estimate K1c of steel 17G1S-U for all types of previous plastic deformation considered in this paper, and compare them with the results presented in [16]. It can be stated that these results are in a good agreement with each other. As seen from the analysis of Fig. 3, when using nanosolutions of different metals under

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Fig. 4 Macrohardness variation of steel 17G1S-U around the central circular hole: a preliminary plastic deformation under static tension, b under impact-oscillatory loading

impact-oscillatory loading, the characteristics of the crack resistance of steel 17G1SU are improved. The authors have previously found similar effects when tungsten carbide and carbon nanosolutions where added to the high-strength titanium alloy VT23 subjected to impact-oscillatory loading [11, 12]. To explain the revealed mechanical effects, additional studies of the surface macrohardness around the hole are conducted, along with detailed fractographic studies of specimen fractures. Figure 4 presents the results of investigations into macrohardness of the surface layers of steel specimens for all analyzed cases by the same method—15 indentations on each side of the specimen in the direction of its loading axis. Here, the results showing the influence of previous plastic deformation under static tension are given on the left (Fig. 4a), and those showing the influence of previous plastic deformation under dynamic loading are given on the right (Fig. 4b). Again, one can see the extreme nature of changes in the mean macrohardness caused by previous plastic deformation under static tension. Thus, for instance, at εpl = 4.5%, the mean macrohardness of the surface layers of steel specimens is 175 by Vickers; at εpl = 6.3%—192, and at εpl = 8.8%—171. A simultaneous decrease in the strength properties of steel at εpl = 6.3% (see Fig. 2b) and a significant strengthening of the surface layers at the same deformation level (see Fig. 4a) also requires additional physical studies. Macrohardness measurements of the surface layers of steel 17G1S-U subjected to the previous dynamic plastic deformation, including by means of nanotechnologies, are more predictable (Fig. 4b). For example, given the occurrence of microextrusions on the specimen surface due to the formation of less dense dissipative structures

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under impact-oscillatory loading [9], it is easy to explain a decrease in the mean macrohardness of the surface layers of steel specimens at εimp = 6.3% to 183, as compared to the mean value of 192 at εpl = 6.3%. Also, considering the results given in [11, 12], it is possible to explain a significant increase in the macrohardness of the surface layers of steel specimens when nanosolutions of titanium carbide and carbon are used under impact-oscillatory loading. In this case, nanostructured surface layers are formed, which account for such results. Thus, for instance, when using a titanium carbide nanosolution under static and dynamic strain of 4.5%, the mean macrohardness of the surface layers of steel specimens increased from 175 to 187. When using a carbon nanosolution at the static and dynamic strain of 8.8%, the mean macrohardness of the surface layers of steel specimens increased from 171 to 196. However, it should be noted that the scatter of macrohardness values under impactoscillatory loading, found also with the use of nanotechnologies, is much greater, as compared to the same levels of the previous plastic deformation under static tension. This indicates a significant structural change in the steel under impact-oscillatory loading not only in the volume of the material, but also in its surface layers. To explain the revealed variation patterns of the parameter Kλ depending on the different modes of previous plastic deformation, the authors conducted a detailed fractographic analysis of fractures of steel specimens. Figure 5 presents relevant data. Here, the authors used a similar technique to compare the experimental data. On the left, data on the influence of the previous plastic deformation under static tension are presented, and on the right—under impact-oscillatory loading. In addition, the results of fractographic analysis into the central zones of tearing are specifically presented to contrast the revealed difference between the fractures of specimens. It is found that, regardless of a similar dimple structure formed on all fractures (dimples have sizes from 2 to 6 μm, and their array on all investigated specimens makes from 1105 to 1841 dimples within the field of view of researches), significant local morphological differences between fractures are revealed. In particular, this applies to the pair of specimens A–D, on which the maximum difference in the Kλ parameter was revealed. Firstly, local laminations of the fracture surface of specimen A were found. One of the reasons for this is the accumulation of dislocations generated under static deformation, which caused delamination at the boundary between ferrite and pearlite grains, and microcracks formation [15]. On the other hand, dimples on specimen A are more elongated and less deep, which indicates a much lower energy intensity of fracture during the growth of a macrocrack [19, 20], as compared to the pronounced, deep dimple structures on specimen D. In the pair of specimens B–E, dimple structures are more similar, however, the nature of deep dimples on specimen B, which are combined into numerous clusters, indicates a much higher energy intensity of fracture during the growth of a macrocrack. Attention should be paid to the local surface laminations of specimen E and the presence of relatively large flat separation zones of fracture, which, first of all, indicate a decrease in the energy intensity of the specimen fracture with the growth of a macrocrack. Comparison of fractures of specimens C–F indicates that they have a kind of rotary mechanisms of fracture, which always leads to a decrease in the energy intensity of the fracture process [21–23]. However, specimen F has a more pronounced deep

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Fig. 5 Fractograms of specimens from steel 17G1S-U: a–c under prior plastic deformation with static tension, respectively (see Table 1); d–f at similar levels of DNP, see Table 1

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Fig. 5 (continued)

dimple structure, which could lead to an increase in the energy intensity of fracture with the growth of a macrocrack compared to specimen C. In general, data of fractographic studies qualitatively confirm the results of mechanical tests on crack resistance of steel 17G1S-U by the method of complete diagrams after the application of different modes of previous plastic deformation.

4 Conclusion The efficiency of using the method of complete stress–strain diagrams on small-sized specimens to estimate changes in the mechanical properties of pipe steel 17G1SU, including the characteristics of crack resistance, is shown. The specimens were subjected to the previous plastic deformation at static tension and similar levels of the previous plastic deformation at impact-oscillatory loading. An extreme nature of changes in the mechanical properties of steel 17G1S-U, including the characteristics of crack resistance, is revealed at the previous plastic deformation of 6.3%. In particular, the level of previous plastic deformation, both at static stretching and at impact-oscillatory loading, significantly reduces the strength

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properties of steel. However, plastic properties are increased significantly, including the characteristics of crack resistance. In general, a negative impact of impact-oscillatory loading on changes in mechanical properties and characteristics of crack resistance of steel 17G1S-U compared to similar levels of previous plastic deformation due to static tension was revealed. At the same time, the simultaneous use of nanosolutions of tungsten carbide and carbon and impact-oscillatory loading at the same levels of previous plastic deformation led to the improvement of practically all the studied mechanical characteristics of the steel. Investigations into the surface layers of steel specimens by the macrohardness method revealed a similar extreme nature of changes in the microhardness of specimens subjected to the previous plastic deformation of 6.3%. Fractographic studies qualitatively confirm the results of mechanical tests on crack resistance of steel 17G1S-U by the method of complete diagrams after the application of different modes of previous plastic deformation.

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12. Chausov, M., Khyzhun, O., Brezinová, J., Maruschak, P., Pylypenko, A., Brezina, J., Buzova, K., Lopat’ko, K.: Improving of mechanical properties of titanium alloy VT23 due to impactoscillatory loading and the use of carbon nano-solution. Metals 9, 652, (2019). https://doi.org/ 10.3390/met9060652 13. Chausov, N.G., Voityuk, D.G., Pilipenko, A.P., Kuz’menko, A.M: Setup for testing materials with plotting complete stress–strain diagrams. Strength Mater. 36, 532–537 (2004) 14. Konovalenko, I., Maruschak, P., Prentkovskis, O.: Automated method for fractographic analysis of shape and size of dimples on fracture surface of high-strength titanium alloys. Metals 8, 161 (2018). https://doi.org/10.3390/met8030161 15. Hutsaylyuk, V., Maruschak, P., Konovalenko, I., Panin, S., Bishchak, R., Chausov, M.: Mechanical properties of gas main steels after long-term operation and peculiarities of their fracture surface morphology. Materials 12, 491 (2019). https://doi.org/10.3390/ma12030491 16. Petryna, D.Y.: Crack resistance of plastic deformed pipe steel 17G1S. Naftogazova Energetika 2(7), 56–60 (2008) (in Ukrainian) 17. Lebedev, A.A., Chausov, N.G.: Phenomenological fundamentals of the evaluation of crack resistance of materials on the basis of parameters of falling portions of strain diagrams. Strength Mater. 15, 155–160 (1983) 18. Chausov, N.G.: Full deformation diagram of source of information about accumulation of damages and materials crack resistance. Zavodskaya Laboratoriya. Diagnostika Materialov 70(7), 42–49 (2004) 19. Lebedev, A.A., Chausov, N.G., Zaytseva, L.V.: Effect of stressed-state form on failure kinetics and crack resistance in martensitic-aging steel. 1. Study of the failure process stages. Strength Mater. 23, 833–843 (1991) 20. Lebedev, A.A., Chausov, N.G., Zaytseva, L.V.: Effect of the stressed-state form on the failure kinetics and crack resistance of martensitic-aging steel. 2. Evaluation of the crack resistance of steel. Strength Mater. 23, 844–849 (1991) 21. Zhukov, D., Konovalov, S., Afanasyev, A.: Morphology and development dynamics of rolled steel products manufacturing defects during long-term operation in main gas pipelines. Eng. Fail. Anal. 109, 104359 (2020) 22. Nazarchuk, Z.T., Nykyforchyn, H.M.: Structural and corrosion fracture mechanics as components of the physicochemical mechanics of materials. Mater. Sci. 54(1), 7–21 (2018) 23. Student, O.Z., Krechkovs’ka, H.V., Nykyforchyn, H.M., Kurnat, I.M.: Fractographic criterion of attainment of the critical technical state by carbon steels. Mater. Sci. 55(2), 160–167 (2019)

Prediction of Residual Service Life of Oil Pipeline Under Non-stationary Oil Flow Taking into Account Steel Degradation Oleksandr Andreykiv, Oksana Hembara, Iryna Dolinska, Yaroslav Sapuzhak, and Nataliya Yadzhak

Abstract Analytical researches of growth of internal surface cracks in oil pipeline pipe wall under real conditions of operation and determination of its residual service life were carried out. The analysis of the operating conditions of the pipeline was carried out during the research. It is believed that the flow of oil is turbulent with possible hydraulic shocks; produced water is collected at the bottom of the pipe, which causes corrosion in contact with a crack in the pipe wall. An important point in these studies is to consider the corrosion-hydrogen degradation of the pipe material (X60 steel) when calculating its residual life. Such calculations are based on a mathematical model of corrosion crack growth in metallic materials under appropriate loading conditions, in particular time variables (turbulent oil flow with hydraulic shocks), the action of the corrosive environment (groundwater) and the change in the characteristics of X60 steel over time as a result of its degradation. It is shown that the turbulence of the oil flow and the shocks significantly reduce the residual life of the pipeline. The degradation of its material (X60 steel) over time puts the value of this resource in the interval between the values of the residual life of the degraded and not degraded pipe. Keywords Oil pipeline · Degradation of X60 steel · Residual resource · Soil corrosion · Laminar oil flow · Turbulent oil flow · Hydraulic shocks · Corrosion-mechanical crack

O. Andreykiv (B) · N. Yadzhak Ivan Franko National University, Lviv, Ukraine e-mail: [email protected] O. Hembara · I. Dolinska · Y. Sapuzhak Karpenko Physico-Mechanical Institute of National Academy of Sciences of Ukraine, Lviv, Ukraine © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_16

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1 Introduction The analysis of the causes of the trunk oil pipeline leakage cases allowed us to establish that the failures are due to breaks in the metal, or in the annular butt seams. Most pipes ruptures are due to corrosion damage. Accidents are often caused by poor quality metal, which is characterized by insufficient plasticity, impact strength, lowquality fused lines, factory seams and especially hydraulic shocks and pipe vibration due to turbulence in the flow of oil during its intense pumping. Poor quality can be due also to metal degradation. Therefore, pipeline reliability is currently one of the most important problems. This task is complicated by the fact that the service life (especially in Ukraine) of more than 37% of the total length of trunk oil pipelines (TP) exceeded the length of the term of depreciation of the linear part (33 years), and 38% of oil pipelines already operated between 20 and 33 years. Recently, a series of experimental studies of pipeline material degradation were held within 30–60 years of operation and changes in their mechanical characteristics were measured [1, 2]. Oil pipelines are subjected to dynamic loads throughout their lifetime (pressure ripples and related vibrations, hydraulic shocks and so on). Dynamic loads occur during pumping installations, triggering of the locking pipeline fittings, accidentally during erroneous actions of the personnel, emergency power outages, erroneous triggering of technological protections, etc. Hydraulic shocks, oscillations and pressure ripples, increased vibration of pipelines many times increase the speed of internal corrosion processes, contribute to the accumulation of fatigue microcracks in the metal, especially in places of stress concentration (welds, scratches, burrs, factory defects, etc.). This is the main background of emergencies. Several studies are devoted to these questions, especially those contained in [2–6]. However, there are currently several unexplored important issues that require the creation of a reliable quantitative theory of predicting the resource (residual life) of pipelines with cracks in laminar and turbulent oil flows, the effects of corrosive media, shocks and degradation. This work is dedicated to this issue.

2 Pressure Distribution in the Pipeline Under Operating Conditions In order to prevent the pipeline from bursting, the pumping pressure cannot be greater than the specified operating pressure. Since the pressure fluctuations depend on the number of stations in the site, the nature of the mode change, and a number of other parameters, pressure increase at each pumping station may take different values [3, 4]. At start-ups and stops of pumping stations the deviation of pressure can reach up to 2–3 MPa, at successive pumping of different types of oil—up to 1 MPa; at start and stop of individual units—0.5–1.0 MPa and as a result of clogging of the pipeline and formation of air plugs—usually within 0.5 MPa. If this deviation leads to an increase in operating pressure, then measures must be taken to limit the pressure at

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Fig. 1 Pipeline pressure fluctuation curve for turbulent oil flow

the outlet of the station. The described pressure fluctuations can lead to an excess of the outlet operating pressure of 0.2–0.5 MPa. In this case, it is not necessary to exclude the pump, as this may result in a reduction in the supply of oil through the pipeline. Due to the turbulence of the oil flow, to the presence of some pump imbalances and to fluctuations in the frequency of power supply, the pressure in the pipeline continuously pulses. The curve of pressure fluctuation in a pipeline (diameter 1000 mm) is shown in Fig. 1. The value of pressure change can be 0.2–0.3 MPa from the average [3, 4]. If the pump units are started on closed latches, dangerous pressure may occur when starting the unit. As the unit is started on a closed latch, the pressure it develops here at zero flow added to the pressure of the previous units can exceed the design pressure causing a problem for the durability of the pipeline. At the closing of the latch, there is a sharp increase in pressure, which is determined by the flow velocity. The resulting pressure wave propagates with the speed of sound. After approaching the latter, a wave of reduced pressure of the reversed direction is formed. The pressure increase at the closing of the latch on the pipeline, which pumps the boiler fuel with a capacity of 7250 m3 /h, is shown in Fig. 2. The latch closure time with a diameter of 900 mm in this experiment is 10.5 s. From Fig. 1, it implies that a significant change in pressure begins after closing the latch by 70%. The wave formed at the close of high pressure reached 4.44 MPa. Due to the increase in the diameters of the oil pipelines, increasing the pressure and temperature of the Fig. 2 Pressure increasing on closing of the pipeline gate

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oil products, the stressed state of the pipe wall has significantly increased. And this is especially true for longitudinal stresses. The uneven distribution of soil properties along the pipeline route creates different conditions for its degradation. Therefore, significant longitudinal stresses ση caused by changes in the temperature and pressure of petroleum products, which are determined by the following formula, may occur between the fixed points [5]: ση = η(T )E − 0.3 pd(D − d)−1 ,

(1)

Here η is the coefficient of linear expansion of the pipe metal, which is taken 12 · 10−6 1/°; d—inner diameter of the pipe; D—outer diameter of the pipe; p—oil pressure; E—modulus of elasticity of the metal pipe; T = TM − Te ; TM —pipeline temperature during installation; Te —temperature of the pipeline during operation. Stresses ση can increase significantly when settling soil. In field studies of real oil pipelines, it has been found that ση can exceed 200 MPa. Thus, based on the analysis of the results of the studies presented in [2–6], it is possible to adopt the following power scheme of loading of the pipeline wall with time. The longitudinal stresses ση are determined by the formula (1) and depend on the variation of ΔT and P in time. Ring stresses σr will change cyclically due to oil turbulence, pump imbalance, switching or stopping of individual pumps or stations.

3 Determination of the Residual Life of the Oil Pipeline with Laminar Oil Flow Consider a underground pipeline of X60 steel with a wall thickness of h = 18.7 mm subjected to long-term static pressure p = 8 MPa, which is weakened by an external surface semi-elliptic crack with axis a0 , b0 (Fig. 3). It is believed that the soil environment enters the crack, causing corrosion-mechanical propagation. As mentioned above, as a result of long-term operation under these conditions, the pipe material degrades over time together with the propagation of corrosion-mechanical cracks [1, 2]. Fig. 3 Scheme of loading of a pipe with a crack and its contact with the environment

Prediction of Residual Service Life of Oil Pipeline Under … Table 1 Corrosion-mechanical characteristics of X60 steel √ √ State of metal K SCC , (MPa m) VSC , (mm/year) K fC , (MPa m) Stock pipe Operated pipe

207

α0

σ0 , (MPa)

11.5

0.50

105

2

502

9.2

3.53

91

4

485

The task is to determine the time t = t∗ when the corrosion-mechanical crack will pass through the walls of the pipe, that is b = h, and depressurization will occur. According to the results of experimental studies in [7–11], under long-term static loading and the action of soil corrosion, the corrosion-mechanical crack will propagate mainly at constant speed VSC in X60 steel. The corrosion-mechanical characteristics of X60 steel are presented in the Table 1. The table indicates: VSC — the rate of growth of corrosion-mechanical crack; σ0 —average stress in the area of fracture near the crack tip; K SCC , K fC , α0 are parameters of kinetic diagram of corrosion-fatigue crack growth [7]. Based on these data, for an arbitrary time of operation of the X60 steel pipe we can write the following formula for approximate determination of velocity VSC ≈ VSC (t): Vsc (t) ≈ 0.10(t + t0 ) + 0.50 (mm/year),

(2)

where t0 is the initial time of operation of the pipe until the forecasted life (t∗ ) of the pipeline. The above task can be solved based on the previously developed energy approach [12]. As a result, it will be reduced to the next mathematical problem:  ∂ 2ρ ∂ρ = Vk (t) 1 + ρ −2 2 , ∂t ∂α t = 0, ρ(0, α) = ρ0 (α); t = t∗ , ρ(t∗ , π/2) = h.

(3)

Here α, ρ—coordinates of the polar system that determine the kinetic system of contours of corrosion-mechanical crack. For its approximate solution we proceed as follows. Since the initial crack is of the semi-elliptic form and the rate of its propagation is constant, it can be assumed [12] that it will differ little in its distribution from the semi-elliptic. In this regard, we consider that the crack will have a semi-elliptic configuration in its propagation, and therefore the solution of Eq. (3) will be reduced to such a system of ordinary differential equations: da = 0.10(t + t0 ) + 0.50, dt

db = 0.10(t + t0 ) + 0.50, dt

t = 0, a(0) = a0 , b(0) = b0 ; t = t∗ , a(t∗ ) = a∗ , b(t∗ ) = h.

(4) (5)

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Solving the system of differential Eqs. (4) with initial and final conditions (5), we obtain the following relations: a(t) = a0 + 0.1(5t + tt0 + 0.5t 2 ), b(t) = b0 + 0.1(5t + tt0 + 0.5t 2 ).

(6)

Substituting the second Eq. (6) into the last relation (5), we obtain t∗2 + (10 + 2t0 )t∗ − 20(h − b0 ) = 0.

(7)

Solving (7), we obtain the formula to determine the residual pipe life: t∗ = −(5 + t0 ) +

 (5 + t0 )2 + 20(h − b0 ).

(8)

Fig. 4 shows the dependence of the residual durability of the pipe t∗ on the initial depth of the crack b0 and the initial time of its operation t0 built by the formula (8). However, Fig. 5 shows a system of kinetic contours for the propagation of a semielliptic crack, starting with the initial a0 = 2 mm, b0 = 1 mm and t0 = 0. In this Fig. 4 Dependency t∗ ∼ b0 of the residual durability of the pipe on the initial depth of the crack b0 and the initial time of its operation t0 : 1—t0 = 0 ;2—4; 3—8; 4—15; 5—25; 6—35 years

Fig. 5 Growth kinetics of crack contours at different times: 1—t = 0; 2—3; 3—6; 4—9; 5—12; 6—14.47 years

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case, the construction of a system of such contours is carried out in a time interval 0 ≤ t ≤ t∗ . The value t∗ for this case is determined based on formula (8) and it is equal to t∗ = 14.47 years. According to these graphs, the residual durability of the pipe depends largely on the time t0 of initial operation, and the semi-elliptic contour of the crack eventually goes to the semicircular.

4 Determination of the Residual Life of the Pipeline with the Turbulent Flow of Oil, Hydrogenation and Considering the Degradation of Material As it is known [1, 2], most of the oil pipelines, which are intensively used, are exposed to the external corrosive soil environment, especially when the external coating is broken. Therefore, in many cases, the damage of the oil pipeline begins at the outer surface of the pipe (see Fig. 3), where surface cracks are generated as a result of degradation of the material and due to loading. As follows from the results in [3], in the case of turbulent oil flow, the pipeline is subjected to two-frequency load: high frequency ω1 = 0.6 s −1 (cycle period T1 ≈ 1.7 s) caused by oil flow turbulence, low frequency ω2 = 2.1 · 10−6 s −1 (cycle period T2 ≈ 476190 s) caused by oil pumping stops (due to shutting down pumps, closing latches, etc.). So, N1 oscillations of high frequency pass in one cycle of low frequency, where N1 = ω1 /ω2 ≈ 28 · 104 .

(9)

Such two-frequency nature of the load must be considered in determining the residual life of the pipeline; to this purpose, the energy approach described in [12] is used. The essence of this approach is as follows. Consider an oil pipeline of radius r = 710 mm and wall thickness h = 18.7 mm (see Fig. 3) made of X60 steel. It has an internal surface semi-elliptic crack along which a turbulent oil flows with a pressure P ≈ 4 MPa, which increases with turbulence. In this case, the change in pressure inside the pipe changes, as stated above, according to the two-frequency law. The task is to determine the residual life of the pipe N = N∗ , considering the load, the action of the corrosive medium, the hydrogenation and degradation of the X60 steel over time. Diagrams of fatigue crack propagation for the operated and as received/reserved pipe (see Fig. 6) for X60 steel has a plateau where the crack growth rate V is constant at variable stress intensity coefficients. As follows from Fig. 6, the rate of crack growth on the plateau material for the reserved pipe and 30 years of service pipe will have respectively the following values: V (0) ≈ 1.4 · 10−7 m/cycle; V (30) ≈ 5.6 · 10−7 m/cycle.

(10)

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Fig. 6 Effect of operation on the diagram of fatigue damage of X60 steel in soil environment and flood [7, 9]

Since they are slightly different for the operating time of 30 years, the given rate V (N ) for any operating time in cycles N can be represented approximately as follows: V (N ) ≈ 10−7 [1.4 + 0.14(N0 + N )] m/cycle.

(11)

In what follows, the problem is solved as discussed in the first section of this paper. As a result, to determine the residual life of the oil pipeline, considering the above factors of its operation and the degradation of its material steel X60, we obtain the following formulas: 

(10 + N0 )2 + 14.3 · 107 (0.0187 − b0 ) − 10 − N0 cycles,   t∗ = 0.015 (10 + N0 )2 + 14.3 · 107 (0.0187 − b0 ) − 10 − N0 years.

N∗ =

(12)

Figure 7 graphically depicts the residual durability of the pipe t∗ from the initial depth of the crack b0 and the initial time of its operation t0 that were built by formula (12). As can be seen from the graphs in Fig. 6, the residual durability of the pipe decreases significantly with an increase in the above factors.

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Fig. 7 The dependence of t∗ ∼ b0 residual lifetime of the pipe on the initial depth of the crack b0 and the initial time of its operation N 0 : 1—N 0 = 0; 2—50; 3—100; 4—150; 5—300; 6—500

5 Estimation of the Residual Life of the Pipe with the Laminar Flow of Oil and Multiple Hydraulic Shocks The long-lasting effect on pipelines of operational loads and the environment, as well as the degradation over time of their materials, accelerates the development of the defects in them and their welded seams. All this leads to operational failures of oil pipelines. Therefore, determining their residual resource, considering their operational factors and degradation of materials, is essential to prevent their unforeseen damage and emergencies. To find the residual durability of the oil pipeline considering the hydraulic shocks (time before depressurization), we propose a model of development in the pipe wall of the outer surface semi-elliptic crack with the initial values a0 , b0 . In this case, according to Fig. 3, we introduce the following notation: r —pipe radius; h—thickness of the pipe wall. We believe that constant pressure p is applied inside the pipeline, and at some intervals its additional load times the time-amplified, quasidynamic loads (hydraulic shocks) P (Fig. 8). In this case, we assume that n such additional time-averaged loads pass during the crack growth. The task is to determine the residual durability of such a pipe taking into account these changes in loads, that is the time t = t∗ when, as a result of mechanical stresses, degradation of the pipe material with time and corrosive environment, the corrosion-mechanical crack will pass through the wall of the pipe causing collapse. Based on the results of the works, we solve this problem based on the energy approach outlined in [12] and convert to the following differential equations, initial and final conditions:

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Fig. 8 Scheme of change in time of loading of the pipeline

∂ dS =  dt ∂t



  ∂   − A − Ws − Wp(1) − W p(2) , ∂S

(13)

t = 0, S(0) = S0 ; t = t∗ , S(t∗ ) = S∗ . S∗ = π b (t∗ ) a(t∗ ) , b (t∗ ) = h. (14) Here A is the work of external forces; Ws —elastic component of the deformation energy W ; W p(1) (S)—part of the work of plastic deformation in the zone of fracture near the contour of the crack, caused by pressure p and depends only on the crack area S; W p(2) (t)—part of the work of plastic deformation in the area of fracture, caused by hydro shock amplitude P and depends only on the crack area W p(2) (t); —the energy of rupture of the pipe wall, which depends on the area of the crack, the characteristics of the environment and time t. The solution of the problem (13), (14) is associated with considerable mathematical difficulties. Therefore, to simplify without losing the necessary precision for engineering purposes, we apply the method of equivalent areas [12], according to which the change in the crack area of the considered configuration will be approximated to that for a semicircular crack of radius of the same initial area. It is considered that the velocity of propagation of a semicircular crack at all points of its contour will be the same. Given this, we write the mathematical model (13), (14) as follows: dρ = dt

Vsc (K 2f c − K I2 ) n 

4 K 2f c − K I2 − 0.25α0 σ0−1 E −1 (1 − R)4 δ(ρ − ρi ) K I4h − K scc

(15)

i=1

under initial and final conditions t = 0, ρ(0) = ρ0 =

 a0 b0 ; t = t∗ , ρ(t∗ ) = h.

(16)

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Here E is Young’s module; ρi —radius of the semicircular crack at the time of the i-th promotion of the crack; δ(ρ − ρi )—Dirac delta function [13]. In this case, the stress intensity factor K 1 for a semicircular crack in the pipe wall based on article [12] is written in the form: √ K I = 0.7σ π h f (ε),

f (ε) =



√ ε 1 + 0.32ε2 1.04 + 0.23ε2 − 0.11ε4 ;

ε = ρ/ h; ε0 = ρ0 h −1 ; σ = pr h −1 .

(17)

The calculation of the residual durability t = t∗ of the pipes taking into account the corrosion propagation of cracks, material degradation and shocks, will be carried out for the following geometry of the pipes and the power load: r = 0.71, h = 0.0187 m, p = 9 MPa, P = 12 MPa and mechanical and corrosion characteristics for the operated pipes are given in the Table 1. Based on these data, we can write the following approximate ratios of changes in the mechanical and corrosion characteristics of X60 steel over time as a result of its degradation: √ K SCC (t) ≈ 11.5 − 7.6 · 10−2 (t + t0 ) MPa m, VSC (t) ≈ 0.50 + 10.1 · 10−2 (t + t0 ) mm/year, √ K f C (t) ≈ 105 − 46.7 · 10−2 (t + t0 ) MPa m, α0 (t) ≈ 2 + 6.6 · 10−2 (t + t0 ), σ0 (t) ≈ 502 − 56.7 · 10−2 (t + t0 ) MPa.

(18)

The calculation will be carried out for specific steel pipes of oil pipelines X60. We turn Eq. (15) to the following form: V = dρ/dt = VSC [1 − φ(ρ, t)]−1 , φ(ρ, t) = 0.25α0 σ0−1 E −1 (1 − R)4

n 

(19)

4 δ(ρ − ρi ) [K I4h − K scc ][K 2f c − K I2 ]−1 ,

i=1

(20) where values α0 , σ0 , VSC , K SCC , K f C are time dependent t and determined from (18). To simplify the solution of the problem, we choose the largest value φ(ρ, t) in time t in this form: max[φ(ρ, t)] = φ1 (ρ) = 33 · 10−10

n 

δ(ρ − ρi ) [K I4h − 7226] [11026 − K I2 ]−1 .

i=1

(21) Substituting (21) into Eq. (19) instead of a function φ(ρ, t) and integrating it under initial and final conditions (16) we obtain

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t∗2 + 2t∗ (5 + t0 ) − 20φ2 = 0, φ2 = (h − ρ0 ) − 33 · 10−7

n 

[K I4h − 7226] [11026 − K I2 ]−1 .

(22)

(23)

i=1

From here we find that t∗ = −(t0 + 5) +



(t0 + 5)2 + 20φ2 .

(24)

Given that n is large enough, and using the theorem on the mean [13], relation (23) can be written in the following form: 66 · 10−7 n φ2 = h(1 − ε0 ) − 1 − ε0

 −1 1

2.37P 4 r 4 h −2 f 4 (ε) − 7226

 dε. 11026 − 1.54 p 2 r 2 h −1 f 2 (ε)

(25)

ε0

We will assume that in the year the pipe is subjected to m hydraulic shocks, and n is defined so: n = m · t∗ ,

(26)

where t∗ —number of years of pipe operation. Then the residual durability of the pipe, considering hydraulic shocks, we find by the following formula: t∗ = −(5 + t0 + m φ3 ) + 0.0306 φ3 = (1 − ε0 )

1 ε0



(5 + t0 + m φ3 )2 + 20(h − ρ0 ),

f 4 (ε)  dε.

3.31 − f 2 (ε)

(27)

Figure 9 shows the dependency of the residual durability t∗ of the plate on the dimensionless value ε0 of the initial crack size without taking into account (curve 1) (stationary mode of operation) and taking into account (curve 2) the effects of time-concentrated quasi-dynamic loads (hydraulic shocks) in t0 = 0 was built based on the relation (27). In engineering practice, the significant question is how durability of an oil pipeline depends on the number and intensity of shocks. Based on the proposed mathematical model (15), (16), it was possible to investigate this.

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Fig. 9 Dependency t∗ ∼ ε0 in stationary mode (curve 1) and for m hydraulic shocks (curves 2–4): 1-m = 0; 2-m = 95; 3-m = 195; 4-m = 395

6 Summary We have developed a method to estimate the residual life of pipelines with surface semi-elliptic cracks for laminar and turbulent oil flows, the action of corrosive medium, water shocks and consideration of the degradation of their materials with time. It is shown that the degradation of the pipe material and the shocks significantly reduce the residual durability of the pipe, compared to laminar flow only.

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7. Nykyforchyn, H., Tsyrulnyk, O., Zvirko, O.: Electrochemical fracture analysis of in-service natural gas pipeline steels. Procedia Struct. Integrity 13, 1215–1220 (2018) 8. Tsyrul’nyk, O.T., Slobodyan, Z.V., Zvirko, O.I., Hredil’, M.I., Nykyforchyn, H.M., Gabetta, G.: Influence of operation of Kh52 steel on corrosion processes in a model solution of gas condensate Mater. Sci. 44(5), 619–629 (2008) 9. Slobodyan, Z.V., Nykyforchyn, H.M., Petrushchak, O.I.: Corrosion resistance of pipe steel in oil-water media. Mater. Sci. 38(3), 424–429 (2002) 10. Andreikiv O.E., Hembara O.V., Tsyrul’nyk O.T., Nyrkova L.I.: Evaluation of the residual lifetime of a section of a main gas pipeline after long-term operation. Mater. Sci. 48(2), 231–238, (2012) 11. Andreikiv, O.E., Hembara, O.V.: Influence of soil corrosion and transported products on the service life of welded joints of oil and gas pipelines. Mater. Sci. 49(2), 189–198 (2013) 12. Andreikiv, O.E., Sas, N.B.: Subcritical growth of a plane crack in a three-dimensional body under the conditions of high-temperature creep. Mater. Sci. 44(2), 163–174 (2008) 13. Heydari, M., Avazzadeh, Z., Navabpour, H., Loghmani, G.B.: Numerical solution of Fredholm integral equations of the second kind by using integral mean value theorem II. High Dimensional Problems. Applied Mathematical Modelling 37(1–2), 432–442 (2013)

Application of the Magnetoacoustic Emission Method for Estimation of Pipelines Material State V. Skalskyi, Ye. Pochaps’kyi, O. Stankevych, B. Klym, and N. Melnyk

Abstract The influence of hydrogen factor and residual stresses on the sum of the magnetoelastic acoustic emission (MAE) signals amplitudes during magnetization of the oil and gas pipeline material is investigated. The regularities of change of the MAE signals parameters by the thickness of the pipe wall and around the longitudinal welded joint are established. The largest sum of the MAE signal amplitudes is recorded in the material from the internal layer of the pipe wall, which is evidently caused by the presence of hydrogen in the material that under long-term operation of the pipelines has penetrated into structural defects and facilitates jumping of the domain walls under samples magnetization. For the longitudinal welding of oil and gas pipelines, the MAE signals with the largest sum of amplitudes are generated in the material from the weld zone and the smallest—from the heat-affected zone. This effect is caused by the peculiarities of the restructure of the material structure under the influence of high-temperature fields under welding in different parts of the welded joint. It is found that residual stresses around the welded joints reduce the intensity of domain wall jumps and cause decrease in the sum of the MAE signals amplitudes. The use of the obtained research results in the newly developed methods of non-destructive testing makes it possible to quickly assess the local damage of the pipes of long-term operation. Keywords Magnetoacoustic emission · Ferromagnetic materials · Hydrogen · Welding joint · Residual stresses

1 Introduction Pipeline transport is traditionally considered to be the most economically sound and technologically advanced among other types of transport. In the case of transportation V. Skalskyi · Ye. Pochaps’kyi · O. Stankevych (B) · B. Klym · N. Melnyk Karpenko Physico-Mechanical Institute of the National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_17

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of large volumes of products (oil, gas, etc.), it is important to ensure the reliability of main pipelines to prevent failures and accidents. The main cause of failures during pipelines operation (according to statistics 80% of all failures) is corrosion, which is manifested by thinning of the pipe wall, corrosion and hydrogen cracking, corrosion-fatigue crack propagation.[1, 2]. A particularly dangerous factor of corrosion-mechanical fracture is the aggressive effect of hydrogen, which can cause uncontrolled failure of structure in a short period of time [3–5]. The composition of the transported fluid (oil, gas) and the operating conditions of pipelines suggest the possibility of such hydrogenation and, respectively, the danger of fracture caused by hydrogen brittleness. Welded joints (WJ) are the most vulnerable areas in terms of their damage and fracture, especially in the conditions of metal hydrogenation [6]. The WJ have some specific features: in particular, structural heterogeneity in the WJ cross-section, accumulation of non-metallic inclusions in the weld metal, residual post-weld stresses, hot and cold cracks during welding. In the case of long-term operation, these factors can contribute to the formation of macrocracks and, as a consequence, to material failure. Therefore, it is important to diagnose timely the state of structural elements to ensure their fail-safe operation. For this purpose it is necessary to create the upto-date methods of monitoring and diagnostics of the state of pipes and individual units and assemblies of technological equipment of pipelines. The existing methods of non-destructive testing are mainly focused on finding defects such as cracks and determining their geometric dimensions. Acoustic methods, in particular, the acoustic emission method (AE), are the most common and well developed ones [7]. The AE method traditional implementation requires the application of additional external mechanical loading applied to the object under control [8]. Because the level of loading required to start small defects propagation can significantly exceed the acceptable optimal load modes of the object, the practical application of the AE diagnosis is limited. The phenomenon of generation of magnetoacoustic emission (MAE) signals under the influence of an external magnetic field, which causes the movement of the magnetic domains walls, is an alternative to its use and local diagnostics of ferromagnetic structural elements and products [9–12]. These processes occur most intensively in the region of the individual defects or their clusters, where significant mechanical stress gradients are present. In addition, the numerous factors, in particular residual stresses [13–15], microstructure [16– 18], microhardness [17, 19], heat treatment modes [20], applied stresses and plastic deformation [21–24], hydrogen [25–28] etc. have a significant influence on the MAE signals parameters. The aim of the performed researches is to establish the peculiarities of the MAE generation by the tube steels of oil and gas pipelines of long-term operation.

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2 Materials and Methods Materials of the main oil pipelines pipes with a lifetime of 38 years and a gas pipeline of 39 years were investigated. The oil pipe had an external diameter of 720 mm and a wall thickness of 10 mm. The chemical composition of steel (wt. %): 0.18C–0.49Si– 0.95Mn–0.035S–0.03P–0.11Cr–0.19Cu. External gas pipe diameter was 1000 mm and wall thickness – 10 mm. The chemical composition of steel (wt. %): 0.16C– 0.51Si–1.33Mn–0.04S–0.035P–0.32Cr–0.14Cu. It can be seen from Fig. 1a that the orientation of the metal blanks for specimens preparation was along the axis of the pipe. The specimens were cut from the bottom part because it was most exposed to the effect of aggressive environment of the transporting products. To manufacture specimens from the pipe wall it was conventionally divided on three zones (Fig. 1b): the external layer (1) that was about one third part of the thickness and included the outer surface of the pipe, the middle layer (2) and the internal layer (3) that included the inner surface of the pipe. The prismatic specimens in size 240 × 30 × 2 mm were made from the metal blanks, adhering to such modes of processing under which minimal cold work and mechanical stresses are formed, as well as minimal changes in structure and phase state occur. Figure 2 shows the test chart. The quasi-static magnetization of the samples was carried out by a sinusoidal current in solenoid 1, having 1500 turns of five-layer copper wire. The outer diameter of the coil was 35 mm with its length of 94 mm. The magnetization signal was formed by a magnetoacoustic measuring system and applied to the solenoid coil. The frequency of the magnetization was 9 Hz. The MAE was measured using a piezoelectric wide band transducer with the frequency range from 0.2 to 2.0 MHz. After amplification, the recorded signal was input to the magnetoacoustic system, which statistically processed a signal, visualized and stored the results on a personal computer. The induction of magnetic field varied from 0.21 to 1.03 T (0.21, 0.45, 0.7, 0.9, 1.03 T) and measured with a coil.

Fig. 1 The places of cutting the blanks from the pipe bottom (1) and the welded joint (2) and a chart of cutting out the experimental specimens of pipes (b) (1–3—internal, middle and external layers of the pipe wall respectively; 4—places for cutting specimens from the pipe wall; 5—pipe wall)

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Fig. 2 A chart of experimental set-up for magnetization in a solenoid: 1 solenoid; 2 measuring winding; 3 specimen; 4 MAE measuring transducer; 5 previous amplifier; 6 reference resistor for measuring magnetization current; 7 MAE device; 8 personal computer

Fig. 3 Places of samples cutting from a pipe fragment with a longitudinal WJ: a 1 base metal, 2 weld metal, b 3 heat-affected zone

The influence of the structure heterogeneity of the WJ pipeline on the parameters of the MAE signals was studied on the samples of size 240 × 10 × 3 mm, cut from three main zones (base metal, heat-affected zone, weld) of the longitudinal WJ (Figs. 1 and 3). They were magnetized using a C-core electromagnet [29] with 1260 coils of copper wire on each leg of the magnetic circuit. The induction amplitude of the magnetic field in the sample was measured by a coil with an active resistance of 14 . To estimate the effect of residual stresses in the vicinity of the WJ and the stressed sections of the ferromagnetic structural elements on the MAE signal parameters, a pipe section of 1020 mm diameter, 10 mm wall thickness, after 48 years of operation was investigated. The plate with a longitudinal WJ had dimensions of 300 × 150 × 10 mm (Fig. 4a). Chemical composition of steel (wt. %): 0.18 °C – 0.49Si— 0.95Mn—0.035S—0.03P—0.11Cr—0.19Cu (%). Figure 4b shows the test chart. To remove the internal stresses, the fragment was annealed for 2 h at T = 550 °C, after which it was cooled down together with the oven. Heating of the steel to the selected temperature does not change the microstructure of the material, but at the same time ensures the removal of residual stresses in it. The MAE measurements were performed on the plate before and after annealing at different distances from the middle of the WJ. Figure 4a shows the scale of measurement points on either side of

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Fig. 4 General view of the investigated plate with longitudinal WJ (marked by a dashed line) (a) and structural diagram of magnetization by the electromagnet (b): 1 C-core electromagnet, 2 excitation coil, 3 pipe fragment, 4 weld, 5 acoustic emission converter, 6 measuring coil

the middle of the WJ. The dependence of the MAE signals amplitude on the location of the C-core electromagnet on the research object before and after annealing was built using the experimental results.

3 Results and Discussion 3.1 Effect of Hydrogen Factor on the MAE Signals Amplitude It is known that the structure and mechanical characteristics of pipelines steels change due to their long-time operation under the influence of corrosive environments. The steels hydrogenation has also a significant effect on their degradation. After prolonged exploitation of the steel due to the increase of the metal defectiveness, the intensity of hydrogen retention in traps increases significantly. To study the influence of hydrogen on the amplitude of the MAE signals, the microstructure of oil and gas pipeline steels, as well as micro- and macrohardness, and the peculiarities of MAE generation under magnetization of pipe material samples from different layers of its wall are analyzed. Note that the microstructure of the degraded metal consists of ferrite-pearlitic columnar crystals [27]. Metallographic investigations show that metal is damaged by a large number of pores of size of 1–3 µm in the pipe wall cross-section (Fig. 5). The number of pores increases by 10–20% over the thickness of the metal pipe from the external (Fig. 5a) to the internal (Fig. 5c) layer. Pores, formed under operation have a spherical shape, typical of defects caused by the presence of gases in the metal structure. Figure 6 shows a typical distribution of defects in the pipeline material for each layer of the gas pipeline pipe wall [27]. The microstructure of metal of the gas pipeline consists of ferrite and perlite grains (about 65% of ferrite and 35% of perlite) and is fine-grained. At the same time, there is no striation inherent to the tube steels, which are produced mainly by the rolling method. Average grain sizes are as follows:

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Fig. 5 Distribution of pores in the oil pipeline wall: a external, b middle and c internal

Fig. 6 Typical distribution of technological defects in the pipe wall layers: a phosphide inclusions in external layer; b defects of forge-rolling in the middle and c in the internal layers

ferrite—30 … 35 µm; perlite—20 … 25 µm. The technological defects caused by the process of steel production are also found. Figure 6a shows the nonmetallic phosphide inclusions, formed during final deoxidation of the liquid metal. The cavity caused by metal shrinkage (Fig. 6b) and a small amount of gas pores caused by the gas evolution under metal cooling to the solid phase (Fig. 6c) are also recorded. Figure 7a shows the averaged values of metal microhardness of different layers by the thickness of the pipe wall for the oil pipeline and Fig. 7b—of the gas pipeline. According to the results of microhardness studies of the oil pipeline steel, it is found that its highest value (~200 HV) was recorded in the internal layer, and the lowest

Fig. 7 Microhardness of the metal of different layers by the thickness of the pipe wall: a oil and b gas pipelines: 1 external, 2 middle, 3 internal layers.

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(170 HV)—in the external layer (Fig. 7a). By measuring the macrohardness of the metal of different layers of the pipe wall of the oil pipeline it is found that the macrohardness by both Rockwell and Brinell is the same—90 HRB and 187 HB, respectively. The internal wall layer had the highest microhardness for the material of the gas pipeline—185 HV, and the external and middle layers—within 170 … 175 HV (Fig. 7b). According to the measurements of the metal macrohardness of different layers of the gas pipeline wall, it was found that samples from the inner layer of the pipe wall had a somewhat higher macrohardness according to Rockwell and Brinell—92 … 93 HRB and 192 … 197 HB, respectively, and the samples from the external and middle layers had the same macrohardness both according to Rockwell and Brinell—91 HRB and 187 HB, respectively. According to literature data [30], the impact toughness and hardness of the oil and gas pipes surface decrease due to their long-term operation, which is a phenomenon of operational degradation and is explained by the development of scattered damages. The hardness of the internal surface layers of a non-operated pipe is substantially higher than that of the external ones. For long-term operation pipes, this difference remains, though it is significantly reduced. The results obtained in our studies correlate well with the literature and indicate, on the one hand, the operational damage of the metal in the volume of the pipe wall, while the hardness gradient by its thickness—confirms the negative role of hydrogen in the process of steel degradation. Figure 8a shows the dependences of the sum of the MAE signals amplitudes versus the magnetic field induction during magnetization of the oil pipe samples cut out from the internal, middle and external layers of the wall. We can see that the largest sum of amplitudes is obtained from the MAE signals generated under magnetization of samples from the internal layer of the pipe wall and the smallest—from the external one. For the magnetic field induction of 0.92 T, the sum of the MAE signals amplitudes in the internal layer of the wall is greater by 10% than in the external one. This

Fig. 8 Sum of MAE signals amplitudes versus magnetic field induction for the specimens of the pipe material of the oil (a) and gas (b) pipelines for various layers of the pipe wall: 1 external; 2 middle; 3 internal layer.

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phenomenon can be explained by a number of factors. The microstructure of various layers of the pipe wall is slightly different. In particular, a significant number of pores were detected in the internal layer of the pipe. It is known that the greater porosity of the material cause a decrease in the MAE due demagnetizing effect of the pores [31]. Thus the MAE in the internal layer of the pipe wall should have been the smallest. At the same time, the results of our experiments showed an inverse effect. By comparing the obtained dependence of the sum of the MAE signals amplitudes with literature data [27] for the structural steel in as-received stage and after hydrogenation it can be assumed that the dominant factor of the increase of the sum of the MAE signals amplitudes in the internal layer of the pipe wall is the presence of some concentration of adsorbed hydrogen, which facilitates the domain walls jumps in the ferromagnetic material during magnetization. Since the aggressive medium less affects the external layer of the pipe wall, the sums of the MAE signals amplitudes in this layer is smaller than in other layers. Therefore, the damage of ferromagnetic materials can be estimated by the sum of the MAE signals amplitudes. Figure 8b shows the dependence of the sum of the MAE signals amplitudes versus the magnetic field induction under magnetization of the specimens of gas pipeline from the various layers of the pipe wall. Similar to the previous case, we can see that the MAE signals generated during magnetization of specimens from the internal layer of the wall pipe have the greatest sum of the signals amplitudes, while from the external layer of the wall pipe have—the lowest sum. For the magnetic field induction of 0.92 T, the sum of the MAE signals amplitudes in the internal layer of the wall is greater by 37% than in the external one. This effect can be caused by a significant degradation of the internal layer of the pipe wall metal due to prolonged contact with the aggressive gas mixture, as well as by the presence of hydrogen in the metal structure adsorbed from it.

3.2 Estimation of Effect of Residual Stresses of Welded Joints on the MAE As noted above, the change in the stress–strain state of the object under study, different modes of heat treatment, the change in the chemical composition of the metal and its hardness have an effect on the material magnetic properties. Each of these factors is present during welding. The presence of different microstructures in all WJ zones and introduction of additional stresses due to the influence of high temperatures remain the main problems after WJ crystallization. To study the effect of residual stresses on the MAE signals amplitude, the metal microstructure of different WJ zones was investigated, and then the samples were magnetized using C-core electromagnet. For example, Fig. 9 shows the microstructure of the different zones of the WJ metal of gas pipeline.

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Fig. 9 Microstructure of the gas pipe WJ metal: a base metal, b heat-affected zone, c weld (×125).

We can see that the structure of the weld metal is characterized by greater dispersion (Fig. 9c) when compared with the base metal (Fig. 9a), which is characterized by a certain banding due to rolling. In the heat-affected zone, the area of overheating with coarse-grained ferrite-pearlite structure and existing Widmanstatten ferrite is the main area (Fig. 9b). It is known that increasing grain size leads to a decrease in the MAE activity [32], on the other hand [33–35] no-180° domain walls, which are the main source of MAE, are located along the grain boundaries. Therefore, in the absence of other factors in the metal structure with a higher degree of dispersion, and due to a greater overall length of the boundaries, the activity of MAE signals generation increases and, as a result, their sum of amplitudes increases too. Figure 10 shows the dependence of the sum of the MAE signals amplitudes versus the magnetic field induction for the specimens from different zones of the pipe WJ of the oil and gas pipelines. We can see that the increase of magnetic field induction leads to the increase of the sum of MAE signals amplitudes in all samples. In the case of constant magnetic field

Fig. 10 Sum of MAE signals amplitudes versus magnetic field induction for the specimens from different zones of the pipe WJ of the oil (a) and gas (b) pipelines (1 base metal, 2 heat-affected zone, 3 weld)

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Fig. 11 Sum of MAE signals amplitudes versus location of the C-core electromagnet on the pipe fragment before (curve 1) and after (curve 2) annealing

induction, the highest magnitudes of the amplitude sums are obtained from the MAE signals generated during magnetization of the weld metal samples (Fig. 10a and b, curve 1) and the lowest during magnetization of the samples from the heat-affected zone (Fig. 10a and b, curve 2). The obtained results agree well with the results of study of the microstructure of different WJ zones. Using the experimental results obtained on the pipe fragment with the longitudinal WJ, the dependences of the sum of the MAE signals amplitudes versus the location of the C-core electromagnet on the object was constructed (Fig. 11). We can see that both before and after annealing with the increase of the distance of the MAE measurement point from the middle of the WJ on both sides, the sum of the MAE signals amplitudes increases, which is associated with a decrease in the metal structure dispersion with the distance from the weld. It is established that the sum of the MAE signals amplitudes in the WJ of the plate before annealing (Fig. 11, curve 1) is smaller than in the annealed state (Fig. 11, curve 2). It is known that domain walls can jump due to their separation from the fixation centers if the values of the externally applied fields exceed the critical values of the fixation field. Obviously, the residual stresses after welding contribute to the creation of additional fixation centers of walls, which decreases the intensity of their jumps, and therefore leads to a decrease in the sum of the MAE signals amplitudes.

4 Conclusions These researches made it possible to establish the peculiarities of the MAE generation of pipe steels of oil and gas pipelines of long-term operation. It was found that: • the dominant factor of the increase of the MAE signals generation activity in the oil and gas pipeline steels is the presence of hydrogen in their structure, which, during long-term operation, has deeply penetrated into the defects (traps), thus facilitating the jumping of the domain walls during material magnetization;

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• the difference in the MAE activity in different layers of the pipe wall prove the different degree of their defectiveness and, consequently, the different degree of hydrogenation; • the highest values of the sum of the MAE signals amplitudes are recorded for the weld material, which is caused by the greatest dispersion of its structure, compared to other welded joint zones; • the sum of the MAE signals amplitudes increases with increasing distance from the weld, what is associated with a decrease in the dispersion of the metal structure with the growing distance from the welded joint; • residual stresses decrease the intensity of domains walls jumps and cause a decrease in the sum of the MAE signals amplitudes, which is obviously caused by the creation of additional fixation centers of domains walls. The obtained investigation results confirm the possibility of the effective use of the MAE method to estimate the damage of steels of long-term operation, and thus for the diagnostics of the volume damage of structural elements made of such ferromagnetic materials.

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Corrosion-Mechanical Failure of Pipe Steels in Hydrogen Sulfide Environments Myroslav Khoma, Vasyl Vynar, Maryan Chuchman, and Chrystyna Vasyliv

Abstract The relationship between the hydrogenating of steels 20, 30CrMo and 17Mn1Si and their resistance to corrosion-fatigue fracture under static and cyclic loads in NACE solution has been investigated. It was found that the volume of adsorbed hydrogen does not determine the corrosion cracking resistance of steels. Steels 20 and 17Mn1Si absorb about the same amount of hydrogen under static loads, however their corrosion cracking resistance is different. The threshold tension for 20 steel is less than for 17Mn1Si steel. Corrosion fatigue resistance of 20 steel under cyclic loads is higher than of 17Mn1Si. Absorption of hydrogen by steels increases under the action of tensile static stresses and decreases at the symmetric cyclic loading. The threshold tension for 30CrMo steel at static stresses is high enough (440 MPa, σth /σ0.2 = 0.8), but threshold average tension does not reach at cyclic asymmetric stresses with amplitudes σa = 0.2σ0.2 and samples fail before 720 h. It indicates a higher sensitivity of this steel to the action of cyclic asymmetric stresses compared to 20 and 17Mn1Si steel. Reducing of resistance to corrosionfatigue fracture of 30CrMo steel under asymmetric cyclic loads correlates with the change in the hydrogenating nature of environment. Corrosion-mechanical failure of steel 20 occurs mainly as a result of hydrogen embrittlement, and the failure of steel 17Mn1Si caused by the simultaneous action of corrosion and hydrogen factors. Keywords Hydrogen sulfide stress corrosion cracking · Corrosion fatigue · Hydrogen sulfide environment · Pipe steel · Hydrogen embrittlement · Absorption

1 Introduction The protection of pipe steels against failure caused by hydrogen sulfide is the topical problem in oil and gas industry. The hydrogen sulfide in environments M. Khoma · V. Vynar · M. Chuchman · C. Vasyliv (B) Karpenko Physico-Mechanical Institute of National Academy of Sciences of Ukraine, Lviv, Ukraine e-mail: [email protected] © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_18

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accelerates corrosion of steel, promotes its localization and intensifies absorption and diffusion of hydrogen. It can cause hydrogen embrittlement of loaded metal elements and their accelerated fracture as a result of hydrogen-induced cracking (HIC) and hydrogen sulfide stress corrosion cracking (SSCC) [1–7]. Hydrogen sulfide significantly reduced fracture resistance of steels under cyclic loading [7–10]. In general, hydrogenation of steel in hydrogen sulfide environments is related with the rate of cathodic process of hydrogen release and its retarding stage nature. Hydrogen can be absorbed on the metal surface only in the form of atoms. Further, adsorbed atoms can diffuse into metal. It causes the appearance of internal stresses and embrittlement of metal [3–6]. Hydrogenation of metal depends on the stability of adsorbed hydrogen and is determined by many conditions: environment composition, metal nature, formation of insoluble corrosion products on the surface etc. High diffusion mobility, insignificant dissolution and great damaging action are unique features of hydrogen behavior in iron and steel [3–6]. It is considered that hydrogen in the metal exists in two kinds: diffusion-moving hydrogen (activation energy ≈12.6 kJ/mol) and residual hydrogen (activation energy (≈37 … 42 kJ/mol) [3]. Diffusion-moving hydrogen can be released from the metal at a temperature of 200 °C, and residual hydrogen—at 800 °C. Diffusion-moving hydrogen has a considerable damaging effect in metals and causes initiation and propagation of microcracks. Residual hydrogen is less active [3–6]. Investigations on the influence of diffusion-moving and residual hydrogen in metals on the structure and properties have not been completed [3–5]. The relationship between the hydrogenating of steels 20, 30CrMo and 17Mn1Si and their resistance to corrosion-fatigue fracture under static and cyclic loads in hydrogen sulfide environment has been investigated in this work.

2 Experimental Program Pipe steels 20, 17Mn1Si and 30CrMo were tested (Table 1). The resistance of steel to stress corrosion cracking under static loads was determinated according to the requirements of the standards of NACE TM0177-90 [11]. Corrosive environment was a standard aqueous NACE solution (mass.%: 5% NaCl + 0.5% CH3 COOH + H2 S(saturated) , pH 3… 4, 20 ± 3ºC). During an experiment H2 S was bubbled through solution with speed ~0.2 ml/min. Cylinder specimens with diameter 6.4 mm were placed in a cell with solution and loaded by permanent static tension. Threshold tension σth (criterion of steel resistance to SSCC) was estimated in the 720 h test. The combined effect of static and cyclic stresses on steels durability was studied. Asymmetric cyclic loads (R = σmax /σmin > 0) with a frequency of 0.5 Hz and tension amplitudes σa = 0.2 σ0.2 were applied. Duration of test—720 h. Resistance of steels to low-cycle fatigue during symmetrical cyclic stresses was studied on round specimens with a diameter of the working part of 5 mm. Duration of test—was 200,000 cycles, loading frequency 1 Hz.

C

0.17–0.24

0.15–0.2

0.26–0.33

Steel

20

17Mn1Si

30CrMo

0.17–0.37

0.4–0.6

0.17–0.37

Si

0.4–0.7

1.15–1.6

0.35–0.65

Mn

< 0,3

< 0.3

< 0.3

Ni

< 0.025

< 0.035

< 0.04

S

Table 1 Chemical composition of steels (mass.%). (Fe-bal.)

< 0.025

< 0.03

< 0.035

P

Cr

0.8–1.1

< 0.3

< 0.25

–

–

< 0.12

V –

–

< 0.008

N

–

–

0.02– 0.05

Al

< 0.3

< 0.3

< 0.3

Cu

< 0.08

< 0.08

As

0.1–0.25

–

-

Mo

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Concentration of hydrogen in steels was determined by the vacuum extraction method [2, 6]. Samples were heated in vacuum and the volume of hydrogen desorbed from the metal was measured at 200 °C (CH200 ) and 800 °C (CH800 ). Liquid differential pressure gauge was used, which was filled by dibutyl phthalate. Diffusion-moving hydrogen desorbs at 200 °C and residual hydrogen—at 800 °C. The volume of desorbed hydrogen from 1 dm2 of surface was presented in cm3 /dm2 . Metallographic investigations were performed using scanning electron microscope EVO 40XVP with a system of microanalysis on energy-dispersive X-ray spectrometer INCA ENERGY 350.

3 Experimental Results and Discussion Steel 20 is sensitive to stress corrosion cracking in NACE solution: threshold tension is σth = 175 MPa (σth /σ0.2 = 0.6) and reduces 1.2 times under the influence of cyclic asymmetric tension with amplitudes σa = 0.2σ0.2 . The threshold tension of steel 17Mn1Si at static stresses is 295 MPa (σth /σ0.2 = 0.7) and decrease to 160 MPa at cyclic asymmetric load. The threshold tension of 30CrMo steel at static stresses is high enough (440 MPa, σth /σ0.2 = 0.8), but average threshold tension have not been reached at cyclic asymmetric load with amplitudes σa = 0.2σ0.2 and samples failed before 720 h. It indicates a higher sensitivity of this steel to the action of cyclic asymmetric stresses compared to 20 and 17Mn1Si steel. It was found that high resistance of steels to hydrogen sulfide stress corrosion cracking does not guarantee the same resistance to stress-corrosion fatigue under symmetrical cyclic stresses. In the last case, the corrosion fatigue limit (σ-1c ) for steel 20 in the NACE solution reduces by ~1.4 times compared to the test on air (σ-1 ), and for 30CrMo and 17Mn1Si steels—by ~2.7 and 2.5 times (Table 2). It is believed that the absorption of hydrogen is the main factor contributing to the reduction of steels resistance and to its brittleness in hydrogen sulfide environment [1–5]. Therefore, the effect of different stresses on the hydrogenation of steels was investigated. The vacuum extraction of samples at temperatures of 200° and 800° was used. Table 2 Corrosion-mechanical properties of steels Steel

σth a , MPa

σth /σ0,2

σR , MPa

σ-1 , MPa

σ-1c , MPa

σ-1 /σ-1c

Steel 20

175

0.60

140

300

210

1.4

17Mn1Si

295

0.70

160

320

130

2.5

30CrMo

440

0.8

–

320

120

2.7

aσ

th threshold tension at corrosion cracking; σ 0,2 yield limit; σ R threshold average tension at asymmetrical stress; σ -1 low cycle fatigue limit; σ -1c low cycle corrosion fatigue limit

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20 and 30CrMo Steels in the Unloaded State Absorbs ~24 cm3 /dm2 of Hydrogen, and 17Mn1Si Steel ~16.62 cm3 /dm2 . All tested steels absorbed more hydrogen under static and cyclic loads, than unloaded samples, which were in the same environment. Additional asymmetric cyclic stress into the direction of static tension slightly reduces the volume of absorbed hydrogen in 20 and 17Mn1Si steels and increases it by a third in 30CrMo steel. Application of cyclic symmetric loads significantly decreases the volume of hydrogen (Figs. 1, 2 and 3). Therefore, tensile loads increase the amount of absorbed hydrogen.. Steel 20 and 17Mn1Si under static loads absorbed about the same amount of hydrogen, but their corrosion cracking resistance in NACE solution is different. Therefore, the amount of absorbed hydrogen is not a criterion for estimation the resistance of steel to corrosion cracking or the corrosion fatigue resistance. The most sensitive parameter of the steels hydrogenating is the ratio CH200 /CH800 (volume of extracted hydrogen at temperatures of 200 and 800 °C). The CH200 is more than CH800 for both loaded and unloaded 20 and 17Mn1Si steels. However, the ratios CH200 /CH800 for loaded and unloaded 30CrMo steel are different: absorbed hydrogen is mostly diffusion-mobile in unloaded samples, but it is mostly residual in samples under stress: CH800 increases almost 7 times under asymmetrical cyclic loads.

Fig. 1 The influence of mechanical stress on the steel 20 hydrogenation at different tensions: a static; b cyclic asymmetric; c cyclic symmetric

Fig. 2 The influence of mechanical stress on the steel 17Mn1Si hydrogenation at different tensions: a static; b cyclic asymmetric; c cyclic symmetric

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Fig. 3 The influence of mechanical stress on the steel 30CrMo hydrogenation at different tensions: a static; b cyclic asymmetric; c cyclic symmetric

This means, that tensile stresses change the hydrogenation nature of the 30CrMo steel. Taking into account that fracture resistance of 30CrMo steel reduces under the influence of asymmetric cyclic stresses, it can be argued that the change in the nature of hydrogenating correlates with the reduction of corrosion-fracture resistance. Microstructure of steel 20 consists of ferrite and local inclusions of perlite globular grains (Fig. 4a). Single defects appear in metal under the influence of static stress. (Fig. 4b). It causes propagation of cracks along of applied tensures and multi-blade breaking (Fig. 4c). Local corrosion-mechanical damages and cracks nucleation are not registered on the surface. Therefore, hydrogen cracking can be considered as a main factor of steel 20 failure under the static load in NACE solution. Metallographic studies of steel 20 showed a slight increase of cracking under asymmetric cyclic stresses. (Fig. 4d). Surface corrosion-mechanical damages were not detected. Several cracks without significant etching of the surface appears on steel 20 at symmetrical cyclic stresses (Fig. 4e). There are hydrogen cracks, which stopped due to the corrosion etching of their peaks. Therefore, hydrogen can be considered the dominant factor in the steel damage. No stratification inside of metal is observed. The structure of 17Mn1Si steel is a heterogeneous striped ferrite-pearlite (Fig. 5a). Under the static stresses local surface damages were observed, which initiated the

Fig. 4 Microstructure of steel 20: initial (a); after destruction in NACE solution under the influence of static stress (b, c); asymmetrical cyclic stress (d); symmetrical cyclic stress (e)

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Fig. 5 Microstructure of steel 17Mn1Si: initial (a); after destruction in NACE solution under the influence of static stress (b); asymmetrical cyclic stress (c); symmetrical cyclic stress (d), × 100

corrosion cracking (Fig. 5b). Therefore, the main destroying factors of the ferritepearlite steel 17Mn1Si in hydrogen-sulfide environment are simultaneous hydrogen charge and local corrosion of the stressed metal, which cause the emergence and propagation of many cracks. Significant increase in the hydrogen cracking was detected in near-surface layer of 17Mn1Si steel under the influence of asymmetric cyclic stresses. Obviously, in this case the volume of hydrogen in the internal micro cavities is more than at static stresses. Corrosion-mechanical damages were also detected on the surface. It was found, that cracks are generated on the surface damages and propagated into internal layers of metal. When cracks reach sections of steel with layering, they stop, which promotes their branching (Fig. 5d). Under the influence of symmetrical cyclic stresses, a large amount of local corrosion-mechanical damage is observed on the 17Mn1Si steel surface. Cracks originates on the surface damages and propagates into internal layers of metal. There is also a small amount of hydrogen seams in metal (Fig. 5e). The microstructure of 30CrMo steel is a fine-dyspersated sorbite with single globular nonmetallic inclusions (Fig. 6a, b). Corrosion damage and hydrogen delamination of 30CrMo steel are not observed after static and cyclic loading tests. The

Fig. 6 The microstructure of 30CrMo steel in initial state (a, b) and after loading tests (c)

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corrosion is uniform (Fig. 6c). It can be associated with a low concentration of sulfur in metal (0.008% mass). The failure of this steel in hydrogen sulfide NACE solution occurs in one crack. Obviously, it is a result of hydrogen embrittlement. Therefore, stress corrosion cracking of steels 20 and 30CrMo in NACE hydrogen sulfide environment is mainly the result of hydrogen embrittlement, and steels 17Mn1Si fails in the result of simultaneous action of corrosion and hydrogen embrittlement.

4 Concluding Remarks 1. It was found that the volume of absorbed hydrogen cannot be the criterium to estimate the resistance of steel to stress corrosion cracking or low-cycle corrosion fatigue in NACE solution. The volume of absorbed hydrogen is almost the same for 20 and 17Mn1Si steels under static loads, and their resistance to stress corrosion cracking is different. The threshold stress for 20 steel is 175 MPa (σth /σ0,2 = 0.6) and for 17 Mn1Si steel—295 MPa (σth /σ0,2 = 0.76). 2. Tensile deformation increases the absorption of hydrogen in 20CrMo, 17Mn1Si and 30CrMo steels in NACE solution. Simultaneous action of asymmetric cyclic and static loads slightly reduces the volume of absorbed hydrogen in 20 and 17Mn1Si steels. 3. Reducing of resistance to corrosion-fatigue fracture of 30CrMo steel under asymmetric cyclic loads correlates with the change in the hydrogenating nature. Volume of residual hydrogen under asymmetrical cyclic loads increases almost 7 times. 4. Stress corrosion cracking of 20 and 30CrMo steels in NACE hydrogen sulfide environment is mainly the result of hydrogen embrittlement, and 17Mn1Si steel fails as a consequence of corrosion and hydrogen embrittlement.

References 1. Nogueira, R.P., Roche, V., Berthomé, G., Chauveau, E., Estevez, R., Mantel, M.: Sulfide stress corrosion study of a super martensitic stainless steel in H2 S sour environments: metallic sulfides formation and hydrogen embrittlement. Appl. Surf. Sci. 394, 132–141 (2017) 2. Loto, C.A.: Stress corrosion cracking: characteristics, mechanisms and experimental study. Int. J. Adv. Manuf. Technol. 93, 3567–3582 (2017) 3. Zhang, T.C., Jiang, X.X., Li, S.Z.: Hydrogen-induced embrittlement wear of a high-strength, low-alloy steel in an acidic environment. Corrosion 53, 200–205 (1997) 4. Gabetta, G., Cioffi, P., Bruschib, R.: Engineering thoughts on Hydrogen Embrittlement. Procedia Structural Integrity 9, 250–256 (2018) 5. Hirth J.P.: Effects of hydrogen on the properties of iron and steel. Metall. Mater. Trans. A 11A, 861–891(1980) 6. Das, G.S.: Influence of Hydrogen Sulfide on CO2 Corrosion in Pipeline Steel. Int. J. Eng. Res. Technol. (IJERT) 3(4), 2224–2228 (2014)

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7. Khoma, M.S., Chuchman, M.R., Ivashkiv, V.R., Sysyn, H.M.: The influence of cyclic loading on fracture resistance of pipe steels and their weld joints in hydrogen sulphide environments. Mater. Sci. 49, 334–340 (2013) 8. Beidokhti, B., Dolati, A., Koukabi, A.: Effects of alloying elements and microstructure on the susceptibility of the welded HSLA steel to hydrogen-induced cracking and sulfide stress cracking. Mater. Sci. Eng., A 507(1), 167–173 (2009) 9. Khoma, M.S., Ivashkiv, V.R., Chuchman, M.R., Vasyliv, Ch.B., Ratska, N.B., Datsko, B.M.: Corrosion cracking of ferrite-pearlitic steels of different structure in the hydrogen sulfide environment under static load. Procedia Structural Integrity 13, 2184–2189 (2018) 10. Khoma M.S.: Influence of Static and Cyclic Tensions on Corrosion—Mechanical Destruction of Steels in Hydrogen Sulfide Environments, Proceedings of the NATO Advanced Research Workshop «The Black Sea: Strategy for Addressing its Energy Resource Development and Hydrogen Energy Problems, pp. 343–350 Batumi, Georgia (2012) 11. NACE Standard TM 0177–90. Standard Test Method Laboratory of Metals for Resistance to Sulfide Stress Corrosion Cracking in H2 S Environments. Houston, Tx. National Association of Corrosion Engineers (NACE) 22 p. (1990)

Determination of Preconditions Leading to Critical Stresses in Pipeline During Lowering Yurii Melnychenko, Lubomyr Poberezhny, Volodymyr Hrudz, Vasyl Zapukhliak, Ihor Chudyk, and Taras Dodyk

Abstract The problem of changing the spatial position of pipelines at different stages of their life cycle is described. The stages and conditions of pipeline construction or operation as well as different modes of technological equipment operation mainly effect on it. In various applied researches of these processes, an attention is mainly paid to recommendations on how to achieve the optimal mode of bending the pipeline. However, in the practice of pipelines construction and operation, the optimal load mode of equipment rarely becomes the subject of interest. In the first place becomes the issue of ensuring the load regime within the permissible limits. To define them a finite-element model of a hypothetical pipeline was created. After defining loads and impacts occurring within the typical pipeline construction sequences as well as under pipelines operation appropriate pipeline deformations were obtained. The processes of pipeline constructing both onshore and offshore (so called S-method) was taken into account. It is shown that the range of permissible pipeline displacements during pipeline lowering on the seabed is an order of magnitude lower than the one on land. It was found that bending stresses in the pipeline are mainly determined by the angle of inclination of the stinger and the axial tension force of the pipeline laying ship. Concerning onshore pipeline construction process they are determined by the position of the first pipelaying crane (so called side boom) from the laying side. Dependence of critical values of process managing parameters from the pipe laying conditions was obtained. Keywords Pipeline · Installation · Lowering · Stress · Offshore · S-method · On land

Y. Melnychenko (B) · L. Poberezhny · V. Hrudz · V. Zapukhliak · I. Chudyk Ivano-Frankivsk National Technical University of Oil and Gas, Ivano-Frankivsk, Ukraine e-mail: [email protected] T. Dodyk JSC Ukrtransnafta, Brody, Ukraine © The Editor(s) (if applicable) and The Author(s), under exclusive license to Springer Nature Switzerland AG 2021 G. Bolzon et al. (eds.), Degradation Assessment and Failure Prevention of Pipeline Systems, Lecture Notes in Civil Engineering 102, https://doi.org/10.1007/978-3-030-58073-5_19

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1 Introduction The process of laying main pipelines is carried out in substantially the same algorithm of action. The construction process differs in that the installation of the pipeline itself occurs remotely from the place of its operation. Different technologies have been put into practice for placing in the design position [1, 2], each of which involves separation in time and space of welding and assembly work. In this case, depending on the direction of movement of the fully welded pipeline in space, the laying work can be divided as such that involves the movement of the pipeline relative to its design position: in the radial, axial and radial-axial directions. Installation of the pipeline in its design position by moving the latter in the axial direction is usually applied at the pipeline crossings due to natural and artificial obstacles. The transverse bend of the pipeline is determined by the geometric profile of the prepared trench or well and the integrity of the pipeline during the laying process is determined by the amount of longitudinal force under which the pipeline is pulled. These loads are, as a rule, clearly regulated by the technological requirements for the execution of the work and also easily controlled, as they are mainly determined by the pulling force of the winches or jack mechanisms. If the pipeline is placed in the design position, it is extremely difficult to check or control the position of the pipeline in the process of displacement, as well as the stresses that occur in the pipeline wall in the process of such displacement. Therefore, the entire process must be clearly planned and calculated before carrying out the work. Today there is on the market a wide range of software for modeling of stress–strain state of pipelines. Their calculator is based on the numerical solution of the equation of the balance of forces and moments of an integral elastic-curved beam, which in its simplest form has the form [3, 4] d2 y dx2

M(x) = E I   2 3/2 ; 1 + ddyx ⎧ ⎪ ⎪ ⎪ ⎨

d2 y

(1) ⎫ ⎪ ⎪ ⎪ ⎬

d2 y dx2 EI  , q(x) = 2  2 3/2 ⎪ ⎪ dx ⎪ ⎪ dy ⎪ ⎪ ⎩ ⎭ 1 + dx

(2)

where x, y—longitudinal and radial coordinates; M(x)—integral bending moment in the pipeline cross section with x coordinate; q(x)—relative weight of the pipeline in the cross section with x coordinate; E—Young modulus; I—mass moment of Inertia of pipe cross section. If the residual axial force appears in the pipeline as well as the additional concentrated forces, then Eq. (2) becomes the following: [4]

Determination of Preconditions Leading to Critical Stresses …

q(x) =

⎧ ⎪ ⎪ ⎪ d2 y ⎨ dx2 ⎪ ⎪ ⎪ ⎩

2

d y dx2

⎫ ⎪ ⎪ ⎪ ⎬

d2 y + N (x) ,   2 3/2 ⎪ dx2 ⎪ dy ⎪ ⎭ 1 + dx

EI 

243

(3)

where N(x)—axial force in the pipe body. However, other auxiliary load-holding or hoisting devices, such as pontoons or anti-personnel inserts during the laying of offshore pipelines, or pipe-layers, cleaning, heating, priming or insulating machines, etc., are used during the laying of the pipeline from the berm trench. Under these conditions, the pipeline will be represented by a non-integral multi-span beam, which is a statically indeterminate mechanical system and a three-moment equation system must be used to reveal its static uncertainty [3, 4]. Given the presence of concentrated forces in the pipeline for the construction of the equations of three moments, it is necessary to apply the universal equation of the elastically-curved beam of the form [5]. Formula (law of change) of beam deflection in section with coordinate x and angle of rotation of pipeline section is as follows y(x) = y(0) + θ (0) · x +

θ (x) =

F(x − b)3 q(z − d)4 q(z − c)4 M(x − a)2 + + − ; 2E I 6E I 24E I 24E I (4)

dy(x) M(x − a) F(x − b)2 q(z − d)3 q(z − c)3 = θ (0) + + + − , dx EI 2E I 6E I 6E I (5)

where a and b are the abscissas of the points of application of the concentrated moment M and the concentrated force P, respectively; c and d are the coordinates of the beginning and end of a section loaded with distributed load (Fig. 1). Considering the nonlinearity of this equation, its integration is carried out by approximate methods, and in practice, using CAE software systems based on the implementation of the solution of the nonlinear equation of the elastically curved beam by the finite element method [6]. Fig. 1 The structure of the schematic elastic-curved beam

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There are both universal calculative systems and highly specialized tools available on the market to simulate the widest possible range of probable loads and impacts on the laying process. On the one hand, universal systems require the construction of primitive elements of the pipeline manually, in addition, the correctness and optimization of the design scheme of the pipeline model in the software complex and how to use them must be optimized by the criteria of sufficient accuracy- ease of model construction and speed of calculation [7, 8]. However, universal engineering computing complexes are less costly to research, because the market for providing services using these products is much wider [9, 10]. The stress state of the pipeline during its laying in a trench on land, on the sea or river bottom has been studied in sufficient detail and described in the reference and regulatory literature [11, 12]. In those cases, the pipeline loads are considered to be nominal and any deviations thereof are taken into account by safety factors. The stress state of the pipeline influence significantly on a safe serviceability due to possible intensification of corrosion, hydrogenation and degradation of pipeline steel, which may cause many issues during long-term operation [13–16]. At the same time, the methodology of predicting the pipelines behavior when it is laid in the trench is not unified. Thus, individual situations of the pipeline construction process that have a direct impact on the stress–strain state of the pipeline are simulated being based on subjective approaches and assumptions. Therefore, using 3-D simulation of laying of the pipeline calibration process of the safety factors has been provided to reach the increase of pipe lay reliability [17, 18]. The influence of sea waves and sea currents [19], pipe-laying vessels oscillations [20] on stresses appearing in the pipelines, the interaction of the pipeline and the bottom soil when laying the pipeline to the seabed [21] were analyzed and classified. The design of the stinger is a subject of research by many researchers [22]. The process of laying a pipeline in a trench on land is characterized by ambiguity regarding the methods of implementation and quality control of laying works [23, 24]. Both processes have common features, and therefore, common approaches of predicting their behavior can be applied to them. Thus, it is important to choose the optimal load configuration scheme provided in the model to provide sufficient accuracy and robustness without the involvement of specialized software systems, that is using universal CAE-systems.

2 Research Methodology Trends in oil and gas production are such that the main undeveloped, and therefore not provided by pipeline transportation of oil and gas fields are located mainly on the offshore and offshore shelf. Given the potential volume of work, the methods of constructing main pipelines are generally divided into two main groups: the construction of pipelines on land and at sea. Both groups of methods involve to a certain extent a change in the stress state of the pipeline in the process of its laying.

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With regard to offshore pipelines, the following technologies are used for their laying [8, 11, 12]: S—laying; J—laying; Pipelaying by reel ship; Pipeline installation by tow or pull method. The latter two methods are limited in use, in particular pipeline reeling is effective for laying pipelines with DN 400 and smaller, and a towing technique is effective for laying coastal pipelines of small length. The S-pipeline laying method is more productive than the J-method and therefore desirable for use. The limits of expediency of its application are determined depending on the depth of the reservoir and on the diameter of the pipeline [1]. However, this classification is rather limited and does not take into account all the factors that determine the stress–strain state of the pipeline during its laying. Therefore, in the conditions of pipelines construction especially large diameter, the potential stress state of the pipeline is subject to detailed forecasting by its modeling. The S-method pipeline laying process is governed by the following factors [17, 22]: – – – –

the wall thickness of the pipeline; traction effort of the pipe-laying vessel; geometric dimensions of the stinger; the design of the roller supports of the stinger and the range of distances between them. The following factors influence the laying process:

– dynamic influence of oscillation of a vessel-pipe-layer due to sea waves; – marine currents; – the composition of the seafloor to which the pipeline is laid. The influence of each of the above factors has been studied in detail in numerous researches. In continuation of the conducted research, it is proposed to determine the spatial position of the pipeline by the results of three-dimensional modeling of the process of its laying S-method. To solve this problem, we formulate a number of assumptions. We believe that the configuration was chosen for the sake of minimizing stresses in the pipeline wall during the laying process at the stage of construction of the pipeline vessel. In this case, the radius of elastic bending on the stinger meets the requirements given in [17, 25], that is, determined by the dependence Rcur v =

ED , 2σ y f D

(6)

where σ y —minimum yield stress; D—pipe outer diameter; f D —design factor, usually f D = 0.85. The design of the stinger implies the bend of the pipeline on the stinger with radius R = 200D (external pipeline). Such consideration is applied on the basis of an analysis of the technical characteristics of the largest Pioneer Spirit and Solitaire pipe-laying vessels. According to the specifications of the vessels, the radius of curvature of the

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Fig. 2 Three-dimensional model of the pipeline during its laying on the seabed using the S-method

Stingers, which they are equipped with, is approximately 150 m. This confirms the permissibility of bending a 200 DN thick-walled marine pipeline. The load diagram of the three-dimensional model of the pipeline in the process of its construction is shown in Fig. 2. To verify the constructed three-dimensional model, a calculation was made during the laying of the marine pipeline according to the initial data given [3], namely: diameter; all other fixed and adjustable parameters.

3 Results and Discussion It is proposed to create a three-dimensional pipeline model on the stinger during the laying period in the advanced CAE-system Ansys Structural. The problem with this model is the complexity of solving contact problems in that kind of software. To enable such analysis, the displacement of sagging part of the pipeline must be limited by the configuration of temporary acting local supports, which are available in Ansys Structural toolbar. In quality of those, so called, conservative supports it is proposed to use the point displacements of the pipe body. It is suggested to select the application points on the lower part of the pipeline. Figure 3 shows a threedimensional model of the interaction of the pipeline with the environment, namely the stinger (Fig. 3a) and the seabed (Fig. 3b). As can be seen in Fig. 4a the stinger supports must be introduced by radially motional springs allowing the axial motion of laid pipeline. Those supports were developed combining the available tools of the software. To set acceptable ranges of work of pipe-laying equipment it is necessary to set which parameters are considered unchanged and what—parameters of influence (regulation). In doing so, the invariable parameters must reflect the worst conditions of the pipeline assembly process. Regarding the laying of offshore pipelines invariable we suggest to establish: – radius of curvature of the stinger; – the wall thickness of the pipeline;

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Fig. 3 Modeling of pipeline contact with environment: a with soil on the seabed; b with stringer supports

– weight of the linear meter of the weighted pipeline in case of positive buoyancy of the latter. The parameters of influence should be considered the following: – – – – – –

depth of pipeline laying; pulling force of the pipeline on the pipeline vessel; the angle of inclination of the end of the stinger to the horizon (vertical); reaction of soil support during contact with the bottom of the trench; distance between the roller supports of the Stinger; the force of elasticity in the radial direction on the rollers of the Stinger.

Consider laying a pipeline with a diameter of 820 mm and 426 mm, wall thickness respectively 29 and 16 mm. The wall thickness value of the smaller pipeline was

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Fig. 4 Pipeline maximum stress distribution during pipeline laying process: a for pipelines with DN = 400 mm; b for pipelines with DN = 200 mm

chosen from the point of ensuring the appearance of the same stress values in the pipe body of both compared pipelines when they are loaded with the same value of internal pressure. The estimated model of the pipeline in the process of its construction is shown in Fig. 2. The stress state of pipelines was calculated during their laying by the S-method to a depth of 200, 350 and 500 m. For these depths, the dependence of bending stresses in the lower part (sag bend) of the pipeline on the tension force created by a pipe-laying vessel was studied. Under the criterion of the admissibility of stresses in the wall of the pipeline it is figuratively selected yield strength of steel. Normally this criterion is calculated in the way of ensuring the strength of the pipeline from local or collapse buckling under the hydrostatic outer pressure [7, 8]. In the initial moment of modelling time the sagged part of the pipeline should be laid on the seabed and fixed, Fig. 3a. Simulation has been conducted as follows. By increasing the axial force applied to the sagging end of the pipeline starting from zero up to the maximum possible

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Fig. 5 Scheme of pipeline loading during its laying on land on a bottom of the trench

value that is equivalent to applying the pulling force of the pipe-laying vessel to the pipeline end on sea surface we obtain a tendency of change of the maximum stress in the pipe body along the laid pipeline section during the whole simulation process, Fig. 4. The maximum and minimum permissible values of the longitudinal tension force of the pipeline correspond to those values for which, in accordance with Fig. 4, maximum bending stresses occur on the sagging section of the pipeline, not exceeding the selected criterion for the strength of the pipeline, in our case, the yield strength of steel of the pipe. The pipeline maximum stress distribution during pipeline laying process is built for both analyzed pipeline sizes: Fig. 4a—for DN 400 mm pipeline and Fig. 4b—for the one with DN = 200 mm. As can be seen from the graph, with an increase in depth, the allowable range of pipeline tension forces decreases. Furthermore, the range even more rapidly decreases with decreasing of pipeline diameter. This approves the significance of providing the accurate substantial analysis before designing the offshore pipeline installation process. The onshore pipeline lay scheme utilizing of 4 pipe-lay cranes in conjunction with construction machines mounted on the pipeline is simulated in CAE system using similar methodology using input data from [18], Fig. 5. Verification of the deformation of the pipeline during its loading is shown in Fig. 7. When laying a pipeline on land, a typical violation of the laying technology is the deviation of the spatial position of the pipeline after false actions of pipe-lay crane engine-driver. In order to evaluate the potential risks of the occurrence of extreme conditions of the pipeline caused by an abnormal change in the spatial position of the pipeline, a number of calculations were performed with a change in the height of the carrying of the pipeline by individual pipe layers (Fig. 6). The corresponding changes in maximum values of stresses are shown in Fig. 7. There can be seen that in case of releasing the pipeline by the first crane from the side of the trench the equivalent stress reaches the minimum yield stress value for given steel. Meanwhile the reaction force appearing on each crane can significantly increase in those cases. The outcomes of the last scenarios are constituted by carrying capacity of the cranes.

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Fig. 6 Comparison of simulation results of the pipeline laying process with reference data on each pipe-lay crane: a force reaction; b equivalent stress (von-Mises)

Fig. 7 Change in time of equivalent stress in pipeline body after an abnormal change in the spatial position of the pipeline: a sudden release of the pipeline by crane 1; b sudden elevation of the pipeline by crane 1 on 1 m higher; c sudden release of the pipeline by crane 2; b sudden elevation of the pipeline by crane 2 on 1 m higher

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4 Conclusions 1. Before laying pipelines, at the design stage, to determine the ranges of permissible values of managing parameters and to optimize the pipe laying process model, calculations should be carried out. 2. For marine pipelines, the axial tension force the pipe laying vessel creates, is the main managing parameter. It is established that for the pipeline with diameter DN 400 is laid on the depth down to 500 m, the range of permissible tension force considers to be from 20 kN up to 100 kN, meanwhile for 200 m depth such range is equal from 0 kN up to 250 kN. For the pipelines of DN 200 the value of the range of permissible tension force for the 500 m depth of pipeline lay becomes ten times narrower. 3. Main managing parameters composing the stress–strain state of the pipeline when it is laid into the trench consider the height of pipeline holding by each of pipelay cranes and distances between them. As the simulation results show for the pipelines with DN 1000 critical stress appears only in case of sudden releasing the pipeline by the first pipe-lay crane counting from the side of the trench. In other cases of sudden releasing or holding up of the pipeline no critical stresses arising in pipeline body were observed.

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