Pipeline Technology Journal 1-2024

Cover
Preface
Dr. K. A. Al-Jabr
Table of Content
Editorial Board
ptj Insights - Defects in Pipelines and their Assessment
P. Hopkins
The Challenge of an All-In-One Inspection - First Results and Benefits
S. Benichou, C. Senah, B. Marquis, D. Le Friant & H. Ez Zaki
Small Diameter Pipeline Inspection
J. Phipps, N. Bettley & C. Peyton
Robust Ultrasonic Transducers for Pipeline Inspection
A. Mück
How to see what cannot be seen within a Disastrous, Highly Corroded Subsea Gas Pipeline during Repair and Pre- Commissioning Process
P. Gholami & M. Nouri
In-pipe Ultrasonic Inspections of Mud and Tailing Lines: how to manage difficult to remove Scaling, provide quality and accurate Defect Assessments of steel and HDPE
A. O’Neill; H. Quakkelsteijn
Ask the Experts
Company Directory

Pipeline Technology Journal - 1/2024 editorial Selecting the proper inspection programs Dr. Khalid A. Al-Jabr Asset Management Engineering Specialist UK Chartered Engineer Certiﬁed Reliability Leader Considering systemic approaches and effective models, with detailed steps and an integrated management program for all components and assets in any pipeline network can enhance the reliability of the network, and promote the system to the next level of excellence. Pipelines comprise of the most efficient methods of energy transportation and distribu- tion, if they are designed, constructed, and maintained accord- ing to the proper standards and practices. Thus, it is important to regularly inspect and maintain pipelines to avoid the shortening the pipeline service lifetime at all stages of the pipeline’s lifetime cycle. Contributing factors to lifespan decline include: design errors, com- missioning, operation interval caused by either external influences (mechanical damage) or internal factors (corrosion issues), or during maintenance (errors in repairs). Moreover, the proper inspection programs can also, improve safety re- cords by avoiding failures and injures, and also avoid environmental damage. In this issue of the Pipeline Technology Journal, we will see how safety procedures and inspection techniques can be applied and implemented to the pipeline systems, according to experts in the pipeline industry. It is exciting to see the safety & inspection practices in the hands of those who are closest to the critical problems, bringing all their deep exper- tise in pipeline integrity to the table by summarizing the best practices, engineering standards, initiatives, new projects, new technologies, les- son learned and success stories in the pipeline field. Sincerely, Dr. Khalid A. Al-Jabr Asset Management Engineering Specialist UK Chartered Engineer Certified Reliability Leader

Pipeline Technology Journal - 1/2024 This Issue’s COMPLETE CONTENT 10 Insights Defects in Pipelines and their Assessment P. Hopkins 18 The Challenge of an All-In-One Inspection - First Results and Benefits S. Benichou, C. Senah, B. Marquis, D. Le Friant & H. Ez Zaki 30 Small Diameter Pipeline Inspection J. Phipps, N. Bettley & C. Peyton 38 Robust Ultrasonic Transducers for Pipeline Inspection A. Mück   Pipeline Technology Journal - ptj www.pipeline-journal.net  # @pipelinejournal #pipelinejournal

Pipeline Technology Journal - 1/2024 How to see what cannot be seen within a Disastrous, Highly Corroded Subsea Gas Pipeline during Repair and Pre-Commissioning Process P. Gholami & M. Nouri In-pipe Ultrasonic inspections of Mud and Tailing Lines: how to manage difficult to remove Scaling, provide quality and accurate Defect Assessments of steel and HDPE A. Murray 44 56 64 Ask the Experts Safety & Inspection Company Directory Page 68

6 Pipeline Technology Journal - 1/2024 Chairman Dr. Michael Beller Director, Global Market Strategy ROSEN Europe Members Editorial Board Adrian Lim Global Management Consultant INTECSEA Ana Nunez Anton EU Chemicals Pipeline Manager Shell Asle Venas Senior Principal Pipeline Specialist DNV Prof. Dr. Jürgen Schmidt Excecutive Director CSE Center of Safety Excellence Dr. Khalid A. Al-Jabr Reliability Engineering Specialist Saudi Aramco Mahmoud A. Hakim Head of Discipline Pipeline Engineering ADNOC Group Dr. Marion Erdelen-Peppler Secretary General EPRG Max Wedekind Managing Director DENSO Group Germany Dr. Mike Kirkwood Director, Integrity Engineering Solutions T.D. Williamson Mohd Nazmi bin Mohd Ali Napiah Custodian/Head/Group Technical Authority PETRONAS Steffen Paeper Freelance Pipeline Consultant www.pipeline-journal.net ptj@eitep.de puBlishEr EITEP, Euro Institute for Information and Technology Transfer GmbH Marie-Jahn-Straße 20 30177 Hannover, Germany Tel: +49 511 90992-10 URL: www.eitep.de issn e-ISSN: 2196-4300 p-ISSN: 2751-1189 usEd Copyright MatErial P. 1 © Anna Heskamp / ROSEN Group P. 8 © 2023 Ralph Thiele / EITEP Managing Board Dennis Fandrich & Marian Ritter Register Court: Amtsgericht Hannover Company Registration Number: HRB 56648 Value Added Tax Identification Number DE 182833034 Editor in ChiEf Dennis Fandrich E-Mail: d.fandrich@eitep.de Tel: +49 511 90992-22 tErMs of puBliCation Four times a year Editorial ManagEMEnt Marian Ritter E-Mail: m.ritter@eitep.de Tel: +49 511 90992-15 Constantin Schreiber E-Mail: c.schreiber@eitep.de Tel: +49 511 90992-20 Editorial staff Mark Iden Daniel Onyango

Pipeline Technology Journal - 1/2024 9 19th Pipeline Technology Conference (ptc 2024) – Leading the Future of Pipeline Technology The 19th Pipeline Technology Conference (ptc) returns to Berlin, bringing together global experts and innovators in the pipeline industry. ptc 2024 promises to be a landmark event, featuring discussions on hydrogen, CO2 transport, methane emissions and pipeline construction, pivotal to the future of energy and infrastructure. Prime keynote speaker will be Stefan Wenzel, the Parliamentary State Secretary at the German Federal Ministry for Economic Affairs and Climate Action. His insights into the interplay of economic policies and climate action are expected to provide a thought-provoking start to the conference, underlining the crit- ical role of pipeline technology in a sustainable future. The ptc Conference will host a series of enriching panel discus- sions. These sessions are carefully curated to focus on emerging trends in energy resilience, methane emissions, hydrogen tech- nology, and digital transformation and cyber security. Attendees will gain valuable insights from industry leaders and partake in engaging debates. A special feature of this year’s event is the Global Women in Pipeline initiative. This segment is dedicated to highlighting and supporting the vital role of women in the pipeline indus- try. Through various activities, including networking events and focused discussions, the forum celebrates diversity and aims to empower women leaders and professionals. Read the full article here: https://www.pipeline-journal.net/news/19th-pipeline-technol- ogy-conference-ptc-2024-leading-future-pipeline-technology Read more pipeline news: https://www.pipeline- journal.net/news

10 Pipeline Technology Journal - 1/2024 ptj Insights Insights Well-known industry experts share their experience, insights and opinions on pipeline related topics Defects in Pipelines and their Assessment P. Hopkins > Phil Hopkins Learning Ltd. Abstract There are over 4 million kilometres of transmission pipelines trans- porting crude oil and its products, and natural gases around the World. These costly and valuable, but potentially hazardous, assets are ageing, with most over, or approaching, 50 years old. This ageing can cause de- fects such as corrosion in the pipelines, but the good news is that these pipelines are not exhibiting increased failure rates. Part of the reason for this is good management of the pipelines, and also the ability to find and assess these defects, both quickly and safely. This article explains how the industry assesses the defects, and why pipelines continue to perform safely.

1. Introduction Transmission pipelines are the most popular method of transporting natural gas, crude oil, and its products, as they are cost-effective and safe [1], Figure 1. They are a hugely important and valuable asset: • they are one of a nation’s critical infrastructures; • • • they have a total length of about 4 million kilo- metres in the World today; assuming pipeline construction costs (which vary dramatically due to varying length, diameter, ter- rain, region, etc.) of ~$US5,000,000/km, the re- placement cost of the world’s pipelines is $20,000 billion; and, these pipelines support a huge oil and gas busi- ness: crude oil is one of the most traded commod- ities in the World at around $1,000 billion dollars per year [2]. 1.1 Pipelines are Ageing… This pipeline asset is ageing; for example, the USA’s oil and gas transmission pipeline system is over 800,000 km (500,000 miles) in total length [3, 4]: 67% of the USA natural gas pipeline system was built before 1970; and, Pipeline Technology Journal - 1/2024 PTJ Insights 11 This means well over 50% of this system is over 50 years old, but there is no evidence of this ageing caus- ing more failures or incidents on pipelines [5, 6, 7]. This may be surprising, as ageing during operation will inevitably introduce defects and damage in the pipelines, such as corrosion (due to the pipelines being in contact with soil/seawater) and dents (due to, say, earth-moving equipment inadvertently hit- ting a buried pipeline) [8]. The term ‘defect’ usually means substandard, but in this article it means a flaw/ discontinuity/anomaly that exceeds specified accept- ance limits in a pipeline or its welds [9]. Defects can also be introduced during the pipeline materials manufacture, and transportation/construction. Certainly, operators of our ageing pipelines now have a better understanding of ‘… welding, inspection, condi- tion monitoring using in-line inspection and improved procedures for damage prevention and detection…’ [7]. Additionally, they now adopt ‘pipeline integrity man- agement’ processes to ensure pipeline safety. This is im- portant - operators have historically relied on pipeline maintenance and inspection to ensure the pipeline was safe [10]. This approach is focused on the pipeline itself, and the supporting systems, and is delivered through an operator's inspection program. It has a bias: it ensures a pipeline does not fail (i.e., it is concentrated on con- trolling the probability of failure), paying little attention to any consequences of failure, which is short-sighted, as risk of a pipeline failure is a product of its probability and consequences. • • 55% of the liquid pipeline system was built before 1970. Integrity management of a pipeline takes a much wider view, as it includes the environment around the pipe- line, as well as the pipeline. This means that operators Figure 1: Pipelines Transport most of our Natural Gas and Oil.

12 Pipeline Technology Journal - 1/2024 ptj Insights are required to know more about [10]: • the areas their pipeline crosses; • • the type and density of the population in those areas; and, the presence of environmentally-sensitive areas around the pipeline. 1.2 Defects during Operation Integrity management allows understanding and control of both the probability of failure, and the potential con- sequences of failure of a pipeline on its route [10]. Part of this pipeline integrity management process is managing defects in the pipeline, as they appear. Defect control and assessment are very important as these defects often ap- pear as the headline cause of pipeline failures, Figure 2 [11], although it has been argued that human error plays a far bigger role [12]. This article covers how these defects are assessed and managed, and why they are not causing increasing fail- ures as the pipelines age. 2. Assessing Damage and Defects in a Structure Damage or defects in a structure are not necessarily unacceptable. A defect may have failed a quality stand- ard, but it may not be a threat to the structural integrity. How do we show it is not a threat? The UK standard BS 7910 [13] states: ‘Where it is necessary to examine critically the integrity of new or existing struc- tures by the use of non-destructive testing (NDT) methods, acceptance levels are required for any flaws that might be revealed. These often already exist as quality control levels (for example in a construction code); however, in this British Standard the derivation of acceptance levels for flaws is based upon the principle of fitness-for-service. The ‘fitness-for-service’ principle is that a structure is considered to be adequate for its purpose, provided the conditions to cause failure are not reached. BS 7910 [13] states: ‘Decisions on whether rejection, down rating and/ or repairs are required [for these flaws which are more se- vere than the quality control levels] may be based on fit- ness-for-service, either in the light of previously documented experience with similar material, stress and environmental Excavation damage (damage to the external coating of the pipe, or dents, scrapes, cuts, punctures, etc.). • • Material/Equipment failure (pumps, valves, welds, laminations and inclusions, blisters, etc.). • Most failures were of equipment. Incorrect operations (human error/mistakes such as directing the flow of fluid, draining, or filling a vessel or tank, performing routine maintenance, etc.). • Other outside force (vehicle or equipment contact not related to excavation, vandalism, sabotage, terrorism, etc.). • Natural force (earth movement, landslides, subsidence, earthquakes, high winds. etc.). Figure 2: Causes of Pipeline Failure in USA (2002 - 2021)

Pipeline Technology Journal - 1/2024 PTJ Insights 13 combinations or on the basis of an engineering critical as- sessment (ECA) …’. The USA fitness-for-service standard, API 579 [14], also gives definitions and guidance on ECAs and fitness-for-service. The U.S. Department of Transportation (DOT)’s Pipeline and Hazardous Materials Safety Administration (PHMSA) [15] states that an ECA is a documented ana- lytical procedure to determine the maximum tolerable sizes for imperfections. 2.1 We use Fracture Mechanics The fitness-for-service principle allows the assessment of defects. All structures will contain defects, but what methods are used in fitness-for-service? ‘Fracture mechanics’ is the study of the effect of defects (primarily sharp defects such as cracks) on structures subjected to forces. Fracture mechanics explains how materials behave when they contain defects, and gives the methodologies and equations we need to assess the significance of the defects. The theoretical studies began with A.A. Griffith (1893–1963), and its modern application was developed by G. R. Irwin (1907 – 1998), A. A. Wells (1924 – 2005), and J. R. Rice (1940 -). Organisations, such as the American Petroleum Institute (API) and British Standards Institute (BSI) have produced documents (BS 7910 [13], and API 579 [14]) that give a full fracture mechanics methodology applicable to all structures. They give the necessary equations, procedures, etc., and help with the neces- sary assumptions and safety factors. In summary, fracture mechanics gives the equations needed to determine if a defect might fail the structure, but it also needs information on (Figure 3): • the defect (e.g., its size); • material properties (e.g., strength and ‘toughness’); and, • the applied stresses on the structure. We need a measure of the material’s resistance to these defects. This resistance is provided by the material’s ‘toughness’: the higher the material’s toughness, the more resistance to the presence of a defect. If we do not know, or cannot measure, the material’s toughness, we have a problem: its absence is equivalent to calculating if a structure will fail under certain loading conditions, but the structure’s strength is not known. It should be noted that the toughness required by fracture mechanics is the ‘fracture toughness’: this is a quantitative measure, and is usually measured in terms of ‘stress intensity factor’ (K), from a laboratory test. The pipeline industry does not, and has not, meas- ured the fracture toughness of its pipeline material. The industry does measure a material parameter called the ‘Charpy energy’, from a notched impact specimen test. Charpy energy is not a measure of a quantitative fracture toughness; therefore, this energy must be cor- related with quantitative fracture toughness measures (the stress intensity factor toughness, Kc). This correla- tion can introduce large errors in estimating fracture toughness, and the Charpy energy can only be viewed as a proxy toughness value. API 579 and BS 7910 con- tain correlations. We have measured this Charpy energy value of materi- als for over 100 years – Charpy values in line pipe steels have increased from about 20 J in the 1950s, to over 100 J from the 1990s [16]. These data, qualitatively, indicate an increase in fracture toughness over the decades. Figure 3: Inputs needed when applying Fracture Mechanics, and Effect of Thickness.

14 Pipeline Technology Journal - 1/2024 ptj Insights This indication of increasing toughness with time will be one of the reasons why pipelines are not fail- ing today – they have increased resistance to defects, particularly sharp defects such as cracks. Additionally, a material’s fracture toughness is affected by other parameters such as temperature (a pipeline steel’s toughness increases with temperature) and thickness (toughness decreases with increasing wall thickness, Figure 3). The latter means that our thin-walled pipe- lines (most pipelines are below 20mm wall thickness) have inherently higher toughness, and consequently can tolerate large defects. The improved material properties, with the inher- ent improved toughness of the thin-walled pipe- lines, along with the improvements in pipeline integ- rity management, all contribute to controlling failure levels. 3. Assessing Defect and Damage in Pipelines 3.1 The Early Days Most oil and gas pipelines were built between the 1950s and 1960s, and this was a period when fracture mechanics was still developing, and defect assessment was relatively new. There was little need for defect as- sessment: the pipelines were relatively new, and de- fect-free, and there was no easy way to detect the de- fects, should they be present. Some pipelines were showing signs of age in the late 1960s (e.g., corrosion), particularly in the USA where most the pipeline system was installed well before 1970, so the industry needed guidance on defects in pipelines. The research organisation Battelle in Columbus, Ohio, USA did early fracture mechanics work on pipelines. Fracture mechanics methods had been available since the 1950s, but in the 1950s/60s they were still ‘new’ and not well-de- veloped. Methods did exist in the 1950s for brittle materi- als, and thick-walled structures (such as nuclear pressure vessels), but these methods were not directly applicable to thin-walled structures such as pipelines, which were made from relatively tough and ductile materials. Additionally, the pipeline industry had not, and did not, measure the fracture toughness of its materials – this toughness is needed in fracture mechanics’ analyses. Battelle and other workers conducted full scale tests on defective pipeline sections to overcome limitations in fracture mechanics for pipelines, and the absence of quantitative measures of toughness. They developed ‘semi-empirical’ (a combination of theory and exper- iments) methods to predict the failure pressure of de- fects such as corrosion and cracks in pipelines. Battelle produced fracture mechanics equations to predict how defects would behave, but they had to use the Charpy energy as a proxy value of toughness [17, 18]. 3.2 Assessment Today The pipeline industry has developed its own meth- ods for assessing a variety of defects, and also uses BS 7910 and API 579; for example, the benchmark stand- ard for assessing corrosion and grinding areas in pipe- lines is ASME B31G [19]. Equivalent guidelines exist for dents, dents and gouges [20], and cracks [8]. Crack as- sessment needs knowledge of a material’s fracture tough- ness, but, as noted above, a correlation with Charpy en- ergy will be necessary (assuming the Charpy energy value is known). The use of this correlation is a particular problem with crack assessment, as it introduces uncer- tainty and inaccuracies. The correlations are not a prob- lem when we assess corrosion: corrosion is a blunt defect and is not sensitive to toughness in most pipeline steels. Corrosion failure is mainly governed by the strength of the pipe: the strength of a pipe is known from manufac- ture. This means that corrosion assessment is not a prob- lem: the fracture mechanics models we use are reliable. 4. Concluding Remarks Defects, such as corrosion and dents, in pipelines, can be assessed using accepted, reliable, published methods [e.g., 19, 20]. Similarly, cracks detected in pipelines can be assessed using both international fracture mechanics’ standards [13, 14] and industry guidelines [9]. The absence of material properties (fracture toughness) does lead to uncertainties in crack assessment, but this absence does not affect the reliability of methods used on corrosion and dents. Nevertheless, the absence of toughness data in the pipeline industry has been a long, on-going problem. 4.1 We Rely on Inspection Vehicles An important point to make is that we rarely directly as- sess a defect – we usually rely on the results of a pipeline inspection by an in-line inspection vehicle, and the as- sessment is of the reported defects. Consequently, our

Pipeline Technology Journal - 1/2024 PTJ Insights 15 assessment is heavily dependent on the accuracy and reliability of the inspection vehicle. These vehicles have tolerances; therefore, defects can be, and will be, under/ oversized, and can be missed completely. These un- certainties must be accommodated in the assessment, with suitable safety factors, verification digs, in-depth knowledge of the vehicle’s capabilities, knowledge of the pipeline and its defects, etc. 4.2 Follow the Rules… It is important to understand the defect being assessed (type, position, size, and origin), and it is useful to have some basic rules on defect assessment; for example: • • check calculations, assumptions; inputs, outputs, and always appreciate the consequences of any failure of the defect (this will affect your safety factor). 4.3 Defect Assessment is a Process, directed by Qualiﬁed People Any defect assessment is a process – it is not simply a calculation. It requires (and relies on) [9]: • a pipeline/product/configuration suitable for inspection/testing; • use competent staff [9]; • pipeline records (e.g., material properties); • always understand the type and cause of any defect you are assessing before an assessment (this will dictate the type of inspection, the assessment method, and any growth of the defect); • an accurate and reliable detection method (e.g., in-line inspection (ILI)), followed by robust data analysis); • understand and use the best assessment practices; • use all relevant data (e.g., inspection data, opera- tions records, maps, etc.); • engineering critical assessment of the defect; and, • field verification and repair, mitigation, or re-assessment. Figure 4: Defect Assessment Process.

16 Pipeline Technology Journal - 1/2024 ptj Insights Each stage of the process can introduce errors, Figure 4 [19]. Indeed, API 1176 [9] says: ‘When managing cracks, a lack of adequate data for making critical integ- rity decisions can make the use of assumptions necessary’. Additionally, API 1176 emphasises the need for competent, qualified people to perform defect assessments: ‘Effective integrity management of cracks relies on qualified people using defined and appropriate processes to operate well maintained and reliable facilities’. Finally, we usually use software to assess defects, as some of the calculations are complex. Be careful – you need to know the strengths and weaknesses (i.e., their underlying assumptions) of any software used. Do not fly blind…. Author Phil Hopkins Phil Hopkins Learning Ltd. Director phil.hopkins.work@gmail.com References 1. Anon., ‘Onshore Pipelines: The Road to Success’, An IPLOCA Document. 3rd Edition. September, 2013. https://vebuka.com/ print/140121193900-61e2e0827bcb6c4d6b45d1b5a0b3cc37/ Onshore_Pipelines_The_Road_to_Success_Vol_1 2. Anon., Observatory of Economic Complexity (OEC) data. https://oec.world/en/profile/hs/crude-petroleum. 3. Anon., https://www.phmsa.dot.gov/data-and-statistics/pipeline/ annual-report-mileage-natural-gas-transmission-gathering-sys- tems. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ annual-report-mileage-hazardous-liquid-or-carbon-dioxide-systems. 4. Anon., ‘Building Safe Communities: Pipeline Risk and its Application to Local Development Decisions’, PHMSA Office of Pipeline Safety. October, 2010. 5. Anon., ‘Gas Pipeline Incidents: 11th Report of the (period 1970 – 2019)’. Doc. number VA 20.0432. European Gas Pipeline Incident Data Group (EGIG). 2020. https://www.egig.eu/reports. 6. Anon., ‘Pipeline Incident 20 Year Trends’, U.S. Department of Transportation (DOT). Pipeline and Hazardous Materials Safety Administration. 2022. https://www.phmsa.dot.gov/ data-and-statistics/pipeline/pipeline-incident-20-year-trends. 7. M. Cech et al, ‘Performance of European cross-country oil pi- pelines – Statistical summary of reported spillages in 2021 and since 1971’, CONCAWE (conservation of clean air and water in eu- rope). Report 6/23. Belgium: CONCAWE. May, 2023. https:// www.concawe.eu/wp-content/uploads/Report_23-6.pdf. 8. Anon., ‘Petroleum and natural gas industries — Pipeline transportation systems — Recommended practice for pi- peline life extension’. ISO/TS 12747:2011. International Organization for Standardization. Switzerland. 2011. 9. Anon., ‘Recommended Practice for Assessment and Management of Cracking in Pipelines’, API 1176. American Petroleum Institute. July, 2016. 10. Anon., ‘FAQs’, The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). 2017. https://www.phmsa.dot.gov/faqs/phmsa-and-pipelines-faqs. 11. Anon., PHMSA, USA. https://portal.phmsa. dot.gov/analytics/saw.dll?Go. 12. P Hopkins, ‘Learning from Failures: Moving from ‘Failure’ Cause to ‘Root’ Cause’, Pipeline Technology Conference. Berlin, Germany, March 2019, and Pipeline Technology Journal. Issue 2. 2019. 13. Anon., ‘Guide to Methods for Assessing the Acceptability of Flaws in Metallic Structures’. BS 7910:2019. British Standards Institution. UK. 13 December, 2019. 14. Anon., ‘Fitness-for-Service’, API 579-1/ASME FFS-1. American Petroleum Institute. USA. 2021 Edition, December 2021. 15. Anon., ‘Transportation of Natural and other Gas by Pipeline: Minimum Federal Safety Standards’, USA Regulations. CFR Part 192.3. 2019. 16. B N Leis, T A Bubenik, ‘Draft Topical Report Periodic Re- Verification Intervals for High-Consequence Areas’, Gas Research Institute Report GRI-00/0230, January 2001. 17. W A Maxey, J F Kiefner, R J Eiber, A R Duffy, ‘Ductile Fracture Initiation, Propagation and Arrest in Cylindrical Vessels’, ASTM STP 514, American Society for Testing and Materials, Philadelphia, 1972, pp. 70-81. 1972. 18. J F Kiefner, W A Maxey, R J Eiber, A R Duffy, ‘Failure Stress Levels of Flaws in Pressurised Cylinders', American Society for Testing and Materials, Philadelphia, ASTM STP 536, pp 461-481. 1973. 19. Anon., ‘Manual for Determining the Remaining Strength of Corroded Pipelines’, American Society of Mechanical Engineers. ASME B31G: 2023. 2023. 20. Anon., ‘Assessment and Management of Dents’, American Petroleum Institute. API Recommended Practice 1183. November, 2020.

18 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY The Challenge of an All-In-One Inspection - First Results and Benefits S. Benichou, C. Senah, B. Marquis, D. Le Friant & H. Ez Zaki > TRAPIL Abstract For more than 5 years TRAPIL, a pipeline operator has researched an inspection tool that would allow, in a single run, the detection, loca- tion, identification and sizing of dents, metal losses and crack anoma- lies (axial and circumferential) affecting liquid product pipelines. The search for an “all-in-one” tool would generate gains in terms of pipeline operations. The runs are done at significantly reduced speeds, an “all in one” tool would therefore make it possible to limit the runs number, and thus the flow reductions, and the operational losses. Phased Array UT technology is a disruptive technology that allows a wide range of adjustments. TRAPIL therefore turned to this technol- ogy to try to achieve this all-in-one run. TRAPIL relied on its existing tool XTRASONIC NEO®, its test bench, reg- ulatory obligations, its experience, and its buried pipes to establish its specifications. The objective of this paper is to show how TRAPIL managed to develop this tool, the successes and points for improvement generated during this process, as well as the first encouraging results obtained.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 19 1. Introduction As discussed in the 2023 Concawe Report N°6/23 [1], pipeline operators are confronted with multiple sources of risk to pipeline integrity, including spillage incidents caused, for example, by mechanical failure, operational activities, corrosion, natural causes, third party-activities, or other factors. Over the years, technically advanced devices and non-destructive testing methodologies have been de- veloped to reduce these risks. However, until recently, operators have been using individual inspection tools or very large size combined tools to detect and meas- ure specific defects, such as lamination, corrosion, dent with or without metal loss or cracks. This means that operators around the world must manage multi- ple inspection runs or alter facilities, requiring subse- quent correlation of separate sets of inspection data. TRAPIL has designed and produced a new in-line in- spection tool, XTRASONICNEO® to avoid these unnec- essary processes, to minimise costs, sources of error, operational conflicts and, overall to improve safety. To monitor and maintain the integrity of pipeline net- works using the very high measurement resolution of this new ILI tool (in longitudinal, circumferential, and radial directions), high POD (probability of detec- tion) and sizing accuracy are required. These capabili- ties are crucial for any long-term pipeline assessment activities, e.g. corrosion, lamination and crack growth analysis, maintenance planning, repair work and in- spection intervals. 2. XTRASONIC NEO® technology and advantages Since 1978, Trapil has built and operated several ILI tools and technologies, including MFL, UT, Caliper, and the latest XTRASONIC NEO®, with Phased Array Technology UT probes. Trapil’s pipeline network is 65 years old and exhibits several of the types of defects referred to in the May 2023 Concawe (Report 6/23) and shown in the figure below. In recent years, Trapil has focused on UT technology, which allows for: • Detection/discrimination of inner/external/mid wall thickness • Good reproducibility and accuracy • High speed inspection • Sizing accuracy • Inspection of large range of wall thicknesses or di- ameters (WT 2,5-25mm; Ø 8-32’’) Trapil has identified all the advantages of Phased Array Technology over conventional UT and has launched a new development schedule. Figure 1 : 2023 Concawe Report [1]

20 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 2 : Beam steering (longitudinal wave 0° and shear wave 45° on left hand side) and defect mapping (corrosion and crack on right hand side) Why Phased Array technology is better than conven- tional transducer: Improvement of worksite safety and limitation of op- erating costs through use of very small and compact tools with detection of dent, metal loss, axial and cir- cumferential cracks in a single run. - The cost of phased array tool’s construction is lower than a conventional transducer tool for an equiv- alent resolution, inspection’s speed in a single run. Parameter flexibility by setting delay laws - (search for specific defects, incidence angle deviation, focusing, welded areas, degraded surface condition), Configurable circumferential resolution with - the switching step (finding of small area defects) With this kind of UT probe multiple features can be used to steer, focus, and scan beams with a single transducer assembly. Beam steering can be used for mapping components at appropriate angles (Figure 2). This can greatly simplify the inspection of components and defects with complex geometry. Electronic focus- ing enables optimisation of the beam shape and size at the expected defect location, as well as further optimi- sation of probability of detection. The capability of fo- cusing on multiple depths also improves sizing of crit- ical defects for volumetric inspections (Figure 3). Figure 3 : Electronic focusing Focusing can significantly improve signal-to-noise ratio in challenging applications, and electronic scan- ning across many groups of elements means that C-Scan images can be produced very rapidly. This technology combines a certain number of sensors and non-destructive ultrasonic control techniques which aim to detect, identify, and size as many types of defects as possible. To control the thickness and ge- ometry, the use of multi-element probes produces a longitudinal line which will travel through the liquid

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 21 Figure 4: Different constraints on a pipeline [2] medium and the steel wall thickness. The analogue signals corresponding to the different echoes are digi- tized and stored in the device's memories. 3. Introduction to the principle of SCC and fatigue crack in pipelines • The manufacturing of the pipeline induces resid- ual stresses. • Internal pressure acting on a geometric deforma- tion (ovalization, dents…) on pipe generates bend- ing stress. This configuration can accelerate the fa- tigue failure phenomenon. In a pipeline, constraints are exerted in all directions. Besides that, main constraints (Figure 4) are circum- ferential (referred to circumferential stress) and longi- tudinal (referred to longitudinal or axial stress) • At welds or in conjunction with grooves, corro- sion pitting, scratches, stress concentrations may develop. Fatigue cracks appear perpendicular to the direction of the principal tensile stress. More often, we find lon- gitudinal cracks because the hoop stress is the highest. • Settling and ground movements induce second- ary stresses. • Temperature changes along the pipeline axis. It is important to differentiate fatigue cracks from stress corrosion cracking (SCC). These two types of de- fects do not occur under the exact same conditions. 3.1 Fatigue Axial cracks The occurrence of axial cracks in pipelines is primar- ily explained by fatigue. Fatigue is a phenomenon in which materials or structures undergo damage and de- terioration over time due to the repeated application of cyclic or fluctuating loads. The different sources of cir- cumferential stresses (induced by loads) are as follows: • The internal operating pressure is the most signif- icant stress component and at the origin of fatigue phenomenon. Figure 5 : Fatigue longitudinal crack [7]

22 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 3.2 Circumferential cracks Circumferential cracks are the result of longitudinal stresses induced by: • Internal operating pressure results. • Landslides and soil settlements. • Temperature variation along the pipeline axis. • Near girth weld with pipeline misalignment. Figure 6: circumferential fatigue crack in a CO2 transport pipeline due to ground movements [6] 3.3 Stress corrosion cracking Stress Corrosion Cracking is a type of corrosion-related damage that can occur in pipelines and other mate- rials. SCC typically appears in crack field form when three main factors are present: • Corrosive Environment: SCC occurs when a ma- terial is exposed to a corrosive environment, such as high chloride levels, sulfide compounds, other aggressive chemicals, near neutral PH (Exposure to water can occur when the pipeline’s coating is damaged). • Tensile Stress: SCC is often associated with the presence of tensile stress on the material. This stress is mostly due to internal pressure generated by the fluid. It also can be from external factors, such as mechanical loads, or internal factors, such as residual stresses from welding or manufactur- ing processes. This condition is explained with de- tails in 1.1 and 1.2. • Material Susceptibility: Some materials are more susceptible to SCC than others. Certain alloys and materials are more resistant to stress corrosion cracking, while others are more prone to it. When these three factors combine, stress corrosion cracking can occur in pipelines, leading to the forma- tion of cracks and potential structural integrity issues. SCC can be axial or circumferential, when considering stresses described earlier. Figure 7: Circumferential and axial crack field SCC from TRAPIL field investigation 3.4 « Spider cracks » “Spider cracks” are SCC crack fields with both longitu- dinal and transversal components. Their formation is characterized by a high local longitudinal stress and conditions. Figure 8: "Spider cracks" from TRAPIL field investigation

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 23 Figure 9: Overview of Three Levels of ILI Validation from API-1163 [3] Detecting and identifying such defects on a pipeline would allow the implementation of an appropriate in- tegrity management policy. Additionally, there are different levels of verifica- tion processes (Figure 12) that allow for calculating POD (Probability of Detection) and POI (Probability of Identification) and POs (Probability of Sizing). 4. How to adapt the ILI analysis process to check and improve detection, identification, and sizing of cracks? Assessing the success of an ILI process involves eval- uating accuracy. Non-destructive inspection accuracy is typically stated in terms of detection, identification, and sizing: • Detection is evaluated with the POD (Probability of Detection): the probability of a feature being de- tected by an ILI tool [3]. Identification is evaluated with the POI (Probability of Identification): The probability that the type of anomaly or another feature, once detected, will be correctly classified (e.g. as metal loss, dent, etc.) [3] 4.1 Having access to known ﬁeld data The ILI tool analysis process verification and improvement starts with a carefully chosen population of defects, which include: • Real defects to evaluate Probability of Detection (POD) and identification (POI). The use of these de- fects for sizing evaluation can distort the results as they are evolving. • Artificial defects to replicate real cracks or metal loss. These defects are useful for assessing the Probability of Detection (POD) as well as Probability of Sizing (POs). Evaluating the Probability of Identification (POI) on these anomalies is less rel- evant due to their differences (especially profiles and morphology) from real defects. • • Sizing is evaluated with POs (Probability of Sizing): The accuracy with which an anomaly dimension or characteristic is reported. [3] ‘Pull Through’ tests are carried out with the ILI XTRASONIC NEO® tool on defects listed in Table 1 to give comprehensive coverage of all defect shapes. Those probabilities are defined by API-1163 [3] and POF [4]. Experimental tests were conducted throughout TRAPIL’s hydraulic test spool (12"-14’’x70m) to estab- lish POD and POs

24 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Table 1 : Types and number of defects on Trapil's spool earlier, the most interesting aspect of those defects is to compare the sizing ILI tool process and the sizing field data. This is done to evaluate ILI tool POs. This also allows for adjusting the tool calibration or process by modifying parameters such as: • Depth sizing chart • Algorithmic tools for sizing models • Data analysts training In this case the target was +/-0.4mm for metal loss and +/-1 mm for notch like/cracks with 90% certainty. Results Figure 14 proved that the ILI tool analysis pro- cess reached this target. Artificial defects will serve as reference points. It would be interesting to have more of these calibration refer- ence points to improve our depth sizing chart. Figure 10: Trapil's 12 and 20'' test spools 4.2 Evaluating and improve sizing of artiﬁcial defects. During the data analysis, all artificial defects listed in Table 1 had been detected. However, as explained Figure 11: Sizing depth comparison between ILI tool process and excavated data on artificial defects.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 25 4.3 Evaluating and improve POD of real defects. 4.3.1. Evaluating POD As explained earlier, the pipeline sections containing defects are collected from the field. The aim is to assess the ILI (In-Line Inspection) process's ability to detect actual longitudinal and circumferential crack fields. • Initially, the defects were detected, identified, and sized in the field by a non-destructive testing com- pany. The detection was performed by magnetic testing, on the other hand crack fields were sized using TOFD (Time-of-Flight Diffraction) technique. • Then, we performed a run with the XTRASONIC NEO® ILI tool on the bench. • The analysis of defects was conducted by a Level 3 data analyst [4]: • One the one hand, longitudinal crack view was analyzed and compared to field data. • On the second hand, circumferential crack view was analyzed and compared to field data. The amount of defect detected by the non-destructive test- ing method is shown on Figure 14 whereas the amount de- tected by the ILI tool process is exposed on Figure 15. Figure 12: Circumferential artificial notch-like on data analysis software Figure 13 : Crack field pipeline section on Trapil's spool test Figure 14 : Crack field detected by the non-destructive testing method.

26 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 15: Crack field signals on the ILI tool data analysis software (Longitudinal cracks view) Figure 16: Longitudinal and circumferential cracks POD after independent analysis Comparisons between field data and ILI tool analysis have allowed us to plot the POD curves. Results of this inde- pendent analysis between longitudinal and circumferen- tial cracks are exposed on Figure 16. In this case the results proved that the ILI tool XTRASONIC NEO® process: • Exceeded the POD target of 90% for longitudinal crack depth ≥ 1mm. • Reach the POD of 78% for circumferential crack depth ≥ 1mm. These results illustrate the challenges that are often as- sociated with the detection of circumferential cracks, in opposition to longitudinal cracks. This could be partly explained by several factors, including the ori- entation of a significant portion of circumferential cracks (skew). Crack skew describes how the crack de- viates from being perfectly perpendicular or parallel to a particular direction. Understanding the skew of a crack is important in non-destructive testing, as it can impact the way cracks propagate or how they are de- tected and analyzed. 3.3.2. Improve POD To improve POD of circumferential cracks, ILI tool XTRASONIC NEO® offers the possibility to cross lon- gitudinal and circumferential data. This enables us to:

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 27 Figure 17 : Longitudinal and circumferential cracks POD after cross referencing analysis. Figure 18 : Example of « Spider crack » visible on both data analysis software views (Longitudinal and circumferential) • • Improve POD of circumferential cracks with a skew. Some circumferential cracks might be more visible on longitudinal analysis software views due to their skew. It can also work for longitudi- nal cracks. Indeed, we achieve a POD of 85% for circumferential crack depth ≥ 1mm (Figure 16). This information rein- forces our belief that an all-in-one inspection would enhance the POD for cracks. Identify “spider cracks” which represents a chal- lenge for the ILI tool XTRASONIC NEO® (chapter 3.4). Examining the cracks pictures from field, we note that cracks responsible for the improvement of circumfer- ential POD are “spider cracks”. They have longitudinal and circumferential components. After cross-referencing the data from circumferential and longitudinal crack views on the data analysis soft- ware, POD results were enhanced for circumferential cracks. The new POD results for circumferential cracks are represented by the red curve on Figure 17. 5. Conclusion and perspectives The validation of the performance of an ILI tool is an it- erative process, which requires a lot of field data.

28 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY The performance shown in this article was produced as part of a standard calibration. The use of Phased Array Technology significantly improves detection thresh- olds and measurement accuracies, while offering ad- vantages in terms of compactness, modularity, and cost of use. This type of tool will improve pipeline in- tegrity management. As a result, the cross-referenc- ing analysis between circumferential and longitudinal crack data enhances POD and POI, highlighting the in- terest of developing an all-in-one inspection tool. References 1. Performance of European cross-country oil pipeli- nes – Statistical summary of reported spillages in 2021 and since 1971 M. Cech J. Armstrong W. Guijt A. Haskamp I. Huidobro Barrio Concawe Report N°6/23. May 2023 2. Thèse de doctorat Bellahcene Tassadit. Etude de la noci- vité des défauts dans les canalisations sous environne- ment hydrogène.Université Mouloud Mammeri. 2012 3. API STD 1163 In-line Inspection Systems Qualification. 2013 4. POF 100 Specifications and requirements for IL. Pipeline Operators Forum. 2021 5. ASNT ILI-PQ-2017 In-line inspection person- nel qualification and certification. 2017 6. Failure Investigation Report. Denbury Gulf Coast Pipelines LLC.Wesley Mathews. Pipeline Rupture/Natural Force Damage. May 26, 2022 7. The effect of pipe material on the behavior of water leakage through longitudinal cracks under pressure. Tshinyengelu Didier Ilunga M.Ing. University of Johannesburg 2016 Authors Stéphane Benichou TRAPIL Head of R&D ILI Department sbenichou@trapil.com Chloé Senah TRAPIL Head of Analysis ILI Department csenah@trapil.com Bertrand Marquis TRAPIL Head of Quality and Measurement Department bmarquis@trapil.com David Le Friant TRAPIL Technical Manager dlefriant@trapil.com Hamza Ez Zaki TRAPIL Project Manager hezzaki@trapil.com

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30 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Small Diameter Pipeline Inspection J. Phipps, N. Bettley & C. Peyton > Cokebusters Ltd. Abstract Conventional tools for inspecting pipelines have historically been de- signed for long length, larger diameter transmission lines, typically up to 48 inches. Correspondingly, pipeline inspection gauges (PIGs) designed to inspect these pipelines have comparable diameters and consist of multiple carriages equipped with diverse inspection tools, logic, onboard power and odometry. There is an increasing require- ment to examine and assure integrity of smaller diameter pipelines, particularly those traditionally considered ‘unpiggable’. Intelligent (often termed smart) pigs developed for these pipelines do not have the luxury of size to house the necessary technologies. The means of entry into the pipeline is often a key limitation, along with navigation chal- lenges and inspection economics. This paper introduces and investigates the challenges associated with in- specting smaller diameter pipelines, typically with diameters less than 12 inches. It details the advantages offered by single bodied intelligent pigs in overcoming these challenges, emphasising enhanced navigation and compatibility with in-line valves. Additionally, the article provides an overview of their efficacy in conducting wall thickness measurements, verifying cleanliness, and detecting a range of different defects (size and morphologies). The paper also explores a more extreme and innovative instance of further miniaturising ultrasonic intelligent pigs. It highlights the performance of the 4th Generation single bodied intelligent pig, which has the capability to inspect pipes with diameters as small as 1.5 inches. The topic within the paper is a discussion on anticipated future trends in the inspection of smaller diameter pipelines, empha- sising the need to diversify the inspection technologies to satisfy the requirements of sustainability and energy transition.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 31 1. Introduction Pipelines are seen as the most reliable and safest infra- structure for transporting fluids (water, natural gas and oil etc.) [1], however, to assure the integrity of pipelines, there requires to be a robust program of inspection and analysis. A significant threat to the transportation of fluids is a failure occurring within the pipeline wall, the im- pact of which can result in life threatening injuries, environmental contamination, social and economic harm. There are a range of credible failure threats to be considered including, pitting, cracking, fatigue, erosion and third part interference [2]. Inspection tools which can detect defects and provide in- formation on the condition of a pipe are thus critical. This has been widely acknowledged across the industry and it is why there is a significant interest in non-destructive testing (NDT), structural health monitoring (SHM), and asset integrity management (AIM). It is necessary to un- derstand the failure modes, degradation mechanisms and minimum tolerances to create a robust inspection and integrity regime. pipelines that cannot easily be inspected by a tradi- tional tooling. There are several factors that can cause a pipeline to be considered unpiggable: bend geometry, significant diametric change (or the diameter is out of scope), variation in pipe material, the product that the pipeline is carrying and the economic expectations for short length pipelines. The service life of unpiggable pipelines maybe based on predictive or empirical models. Solutions to inspect such pipelines, serve to inform and to de-risk through the determination and assurance of integrity. The intelligent pig can carry a range of different sensor technologies dependant upon the NDT requirements. Magnetic flux leakage (MFL), and ultrasound (UT) are the most widely used NDT technologies [9, 10]. MFL is a technology that utilises strong magnets ac- tion on the pipe wall, a magnetic sensor is positioned between the magnetic poles and detects any magnetic field leaking from the pipe wall. The leakage field de- tects changes when there are anomalies in the pipe wall, and this can be interpreted to identify regions of defects. The most common method of inspecting pipelines is via intelligent pig. Such a tooling is inserted (launched) into the pipeline and travels along the pipework facili- tated by the pressure differential of the pipeline product, or other pumped fluid. There are two primary categories of pigs [3, 4, 5]. Mechanical pigs are predominantly used for cleaning and purging operations and do not typically provide any information on the condition of the pipe. The second type, and the focus of this article, is the intelligent pig. These contain sensors and logic that detect and measure to give an insight to the condition of the pipe structure. Unlike hand-held inspection approaches, the intelligent pig has the benefit of free flowing through the pipeline and continually measuring across a broad surface grid in a short amount of time. The axial resolution of the in- spection campaign is influenced by the speed at which the pig travels through the pipeline. Major challenges present within certain pipeline in- ventories are the so called ‘unpiggable’ pipelines [6, 7, 8]. Unpiggable is a phrase commonly used to describe Ultrasound is an elastic wave that is transmitted into the pipe wall, the wave then propagates through the pipe wall reflecting from the boundaries, internal and external wall. The reflection from the external wall provides information on the wall thickness, and the reflection from the internal wall provides information on the internal diameter of the pipe (Figure 1). If anom- alies are present, the ultrasound will reflect off these allowing for them to be detected and sized accordingly. The most common type of ultrasound transducers are piezoelectric transducers. These require the pipe to be filled with a couplant, normally water, so that the ul- trasound can propagate from the transducers into the pipe wall and back again. This therefore limits their application in gaseous mediums. Another common transducer type is an EMAT (elec- tromagnetic acoustic transducer). These require the pipe to be electrically conductive and ultrasound is generated in the pipe wall. No couplant is required, allowing for their use in gaseous, liquid, and mul- ti-phase pipelines. EMAT intelligent pigs are often used for crack detection as they can transmit the

ensuring that decoking and descaling operations have been performed effectively. As the inspection technol- ogy matured, this transitioned from cleanliness ver- ification to wall thickness measurements and recent developments in data analysis allowed defect detec- tion to be refined. The principles that are employed by a single body intelligent pigs used for heater inspec- tions are the same as a traditional ultrasound pipeline inspection tool. The single body intelligent pig described here is a piezo- electric UT tooling which performs wall thickness and defect detection measurements. The centre of the intel- ligent pig contains the array of piezoelectric transduc- ers, as shown in Figure 2, one end of the tool containing the controlling electronics and memory, the other end contains the power source. The pig is untethered and is propelled through the pass by water pressure. Typical inspection speeds sit between 0.3 and 0.8 ms-1, and a minimum of 15,000 internal radius and wall thickness measurements are gathered every linear metre. This range of single body intelligent pigs are suitable for in- specting tubes and pipes with diameters from 2.5 inches to 12 inches. 32 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 1: Schematic of a pipe cross section containing an intelligent pig. The ultrasonic paths taken to provided information on a pipe’s internal dimensions and the wall thickness are shown. ultrasound along the length of the pipe, increasing their sensitivity towards small defects. These are not the only type of intelligent pigs used but are the most common. Examples of other technologies implemented include eddy current and calliper [11]. The intelligent pigs of interest in this article are pie- zoelectric ultrasound based in which the ultrasound is transmitted perpendicular to the internal diameter wall (Figure 1) allowing for accurate wall thickness and diameter measurements. In larger diameter pipelines, which are generally straight and do not present significant navigation challenges, the intelligent pig benefits from ample space to accommodate a high density of sensors and the necessary electronics. This is often achieved through the utilisation of multi-carriage tools implementing a variety of inspection technologies[12]. In contrast, smaller diameter pipelines pose a significant challenge in housing the required sensors. Multi-carriage devices can also be utilised but the effectiveness of a solu- tion becomes somewhat moot if the tool cannot enter or successful navigate through the pipeline. It is in these cir- cumstances that a bespoke and effectively designed single bodied intelligent pig becomes the optimal solution. 2. Single Body Intelligent Pigs Figure 2: Image showing the different sizes of single body ultrasonic intelligent pigs. Single bodied intelligent pigs are often deployed for the inspection of fired heaters where complex 1D bends and variations in pipe diameters are present. These are the most onerous of circuits, often contain- ing box section geometries. The requirement to inspect furnaces, heaters, and steam generation units, initially derived from a need to Measurements rely on pulse-echo ultrasonic test- ing, where a single transducer both transmits and re- ceives ultrasound (as illustrated in Figure 1). The ini- tial reflection corresponds to the internal pipe wall, and the subsequent signals are caused by reverbera- tions of the ultrasound within the pipe wall. The time difference between the arrivals equates to two times the wall thickness. The use of multiple reflections, as

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 33 in orientation and acceleration that occur as the pig moves through bends and other complex geometries. An axial location accuracy of ±50 mm is achieved when using known features as reference markers. Figure 4: Image showing the wall thickness results presented in a 3D map. Figure 16: Longitudinal and circumferential cracks POD after independent analysis seen in Figure 3, enhance the measurement accuracy. Additionally, multiple measurements at a single po- sition are averaged for precision. The intelligent pigs exhibit a typical wall thickness static accuracy of ±0.1 mm and dynamic accuracy of ±0.3 mm. Measurements require accurate speed of sound values for the liquid couplant, and for the pipe wall initial calibrations are performed. The gathered measurements provide for an accurate indication of the condition of the pipe structure. For example, if an increase in internal radius is detected at the same position as a reduction in wall thickness, this is a sign of internal metal loss. Similarly, if the internal radius remains consistent and the wall thickness de- creases, this would indication of metal loss from the external wall. Due to the volume of data gathered, a 3D map of the wall thickness measurement, internal diameter and external diameter can be generated, Figure 4. This il- lustrates areas of concern eg. a loss of wall thickness. Areas of remaining internal fouling are shown in the data by a reduction in the internal diameter and a loss of wall thickness measurements, cause by ultrasound scattering. Location accuracy is achieved by utilising a 6-axis gyro- scope, which compensates for any rotation that occurs in the pig during the inspection and detects changes

34 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY To understand the performance of the single body intel- ligent pig for detecting small defects, a bespoke defect tube was manufactured containing a series of different size machined defects, Figure 5. Six different diameter clusters of flat bottom hole (FBH) defects were tested, ranging from 7-30mm. Each size of FBH had various depths introducing an additional variable to the results. Figure 5: CAD model of artifical defect tube used to assess the performance of the single body ultrasoninc intelligent pig. When the defect size becomes comparable to the beam width of the ultrasonic signal, it is unlikely that that ultrasound will interact entirely with the defect and therefore the received signal will consist of both the defect and the full thickness of the pipe wall. If the am- plitude of the pipe wall signal is greater than that from the defect, then the defect signal can be masked and detection compromised. This effect is minimised by multiple inspection runs which serve to increase the probability of detection on smaller defects. The results also showed how the single body intelligent pig was capable of detecting defects of all depths, with the shallowest defect protruding 2mm into the pipe wall. The depth resolution of the tool is not a limiting factor in the tools performance as the temporal resolution of the results combined with repeat measurements through averaging and multiple reflections provide highly accu- rate measurements. Whilst FBHs approximate defects in pipes, real defects differ with textured surfaces and sit- ting at angles to the ultrasonic propagation direction. This can result in the ultrasound scattering, increasing the difficulty of detection. The C-scan shown in Figure 6 gives an indication of the defects that were able to be detected. In total, the sin- gle bodied pig was able to detect all defect diameters around the entire 360 degrees of the pipe. At the very small range, not all defects in the cluster were com- pletely resolved. Advancements in the single body ultrasonic intelligent pig involve ongoing research to increase transducer density and improving data science / post processing routines. This will improve the probability of detecting smaller features. In addition, improvements to signal Figure 6: C-scan showing the identification of the flat bottom hole defects present in the test component.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 35 processing routines will help distinguish smaller de- fect reflections from larger external wall reflections. Whilst the current generation of single body intelligent pigs performs very well and is capable of identifying small diameter and shallow defects, their suitability for deployment using inline valves is a greater advantage, especially for inspecting traditionally unpiggable pipe- lines. In contrast, multi-carriage intelligent pigs cannot typically be deployed via inline valves. The overall aim of the single body intelligent pig is to match, or indeed exceed the performance of the multi carriage alternative, resulting in an inspection solution that is superior technically and more economically viable. 3. Ultra Small Intelligent Pig Recent advancements in the single bodied ultrasonic intelligent pigs have been concentrated on further downsizing the tool to enable inspection of even smaller diameter inventories. As a result, a 4th gen- eration single body intelligent pig, referred to as the ultra small intelligent pig (USP), has been created. The USP was developed to inspect a solar steam gener- ation plant, which used parabolic trough collector. The parabolic trough collector had a 2 inch diameter Sch 80 and Sch 160 circuit and was therefore out of scope for the current intelligent pigs available on the mar- ket at the time. Figure 7: The miniaturised intelligent pig. This is the 4th generation of single body ultrasonic intelligent pigs. glass tube. This glass tube made it difficult to perform any handheld NDT inspections. It was determined that the only viable solution for inspection was to develop a miniaturised intelligent pig. The 4th generation intelligent pig is believed to be the world’s smallest untethered intelligent pig of its kind. The final design can be seen in Figure 7 and operates using the same inspection routines as introduced already in the article. The piezoelectric transducers around the central circumference of the pig, allows for wall thick- ness, internal and external diameters, and localised de- fect measurements to be determined. The miniaturised intelligent pig can operate in pipe diameters as small as 1.5 inches (38 mm internal diameter). Inline inspection was the only feasible option for in- spection due to the pipes being encapsulated within a Following the development of the USP, a successful inspection trial was conducted. A summary of se- lected results is presented in Figure 8, illustrating Figure 8: 3D map of the small diameter pipeline inspected using the miniaturised intelligent PIG.

36 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY wall thickness values. The outcomes reveal areas of localised external wall loss. These sections of wall loss, occurring at semi-regular intervals, indicated in the 3D map (Figure 8) by the red bands. They signify a wall loss of approximately 1.5 mm. Upon further ex- amination, it was noted that these instances of wall loss coincide with tube section welds and specifically the locations of support structures around the pipe that neighboured the welds. PIGs include solar thermal energy plants and parabolic trough collectors, which are becoming more common with the transition to greener energy sources. Solar thermal energy solutions depend on small diameter pipes to ensure that the solar energy can be sufficiently focussed. These pipes are often encapsulated making conventional handheld inspection techniques unsuit- able. The most appropriate solution is inline inspec- tion using miniaturised intelligent pigs. In summary the development of a miniaturised intelli- gent pig (USP) allowed for the inspection of a parabolic trough collector, previously unpiggable. In addition, the results from the subsequent inspection highlighted areas of wall loss that will need to be monitored over time to ensure that they do not result in a contributory failure mode. The results highlight the importance of inline inspection and necessity for companies to pur- sue viable solutions, even within inventory where it is not deemed possible. 4. Future Direction of Small Diameter Pipeline Inspections The single body intelligent pig can address the access and navigation challenges frequently encountered in small diameter pipelines. Through the use of inline valves, the single body intelligent pig can inspect pipelines that were not originally designed for pigging. Inline valves are rela- tively non-intrusive and can be left in place as permanent fixtures within the pipeline, facilitating easy repetition of inspections. The single body intelligent pig is designed to fit within the chamber of the inline valve, simplifying both launch and retrieval processes for these pipelines, whilst still providing a high quality inspection capable of detecting small defects. There is an increasing desire for detecting smaller defects with greater accuracy and achieving more comprehensive coverage of the pipe wall. Ongoing research aims to meet these objectives, exploring various avenues, such as in- creasing transducer density, optimising logic, enhancing data interrogation and implementing hybrid solutions, all within a single bodied tool. Furthermore, current technology enables the devel- opment of miniature intelligent pigs, allowing for the inspection of new, previously unpiggable pipework. Emerging markets for these miniaturised intelligent 5. Conclusion This paper has provided an overview into the performance of single bodied intelligent pigs, specifically highlighting their suitability for inline inspection of small diameter, un- piggable pipelines, where economics, access and navigation are key challenges. The benefit of the single body intelligent pigs is their compact design allowing for easy deployment whilst maintaining inspections capabilities associated with traditional pipeline pigs. The single body tools pre- sented use piezoelectric transducers to generated ul- trasonic signals. These signals can measure the pipe diameters and wall thickness but require the pipe to be filled with a liquid to allow for the transmission of the ultrasound into the pipe wall. A 4th generation intelligent pig has been presented, with results from a trial performed at a solar powered steam generation unit demonstrating the performance of the miniaturised ultrasonic intelligent pig. This min- iaturised pig shows with technological developments and intelligent designs how conventionally unpiggable pipes can now be inspected. A brief discussion on future directions for small diame- ter pipeline inspections, and how miniaturised intelligent pigs can provide solutions to ultra small tubing networks often associated with alternative energy systems. Finally, the progressive maturity and weight of suc- cessful deployment evidence serves to illustrate that the ability of such single bodied tooling has overcome the challenges of uninspectable inventory. The ability to measure, assess and assure integrity is now within the reach of operators who are able to credibly and eco- nomically de-risk their assets.

References 1. Q. Ma et al., ‘Pipeline in-line inspection method, instru- mentation and data management’, Sensors, vol. 21, no. 11. MDPI AG, Jun. 01, 2021. doi: 10.3390/s21113862. 2. K. Zakikhani, F. Nasiri, and T. Zayed, ‘A Review of Failure Prediction Models for Oil and Gas Pipelines’, J Pipeline Syst Eng Pract, vol. 11, no. 1, Feb. 2020, doi: 10.1061/(asce)ps.1949-1204.0000407. 3. J. Quarini and S. Shire, ‘A review of fluid-driven pipeline pigs and their applications’, Proceedings of the Institution of Mechanical Engineers, Part E: Journal of Process Mechanical Engineering, vol. 221, no. 1. Professional Engineering Publishing, pp. 1–10, 2007. doi: 10.1243/0954408JPME108. 4. F. Varela, M. Y. Tan, and M. Forsyth, ‘An overview of major methods for inspecting and monitoring external corrosion of on-shore transpor- tation pipelines’, Corrosion Engineering Science and Technology, vol. 50, no. 3, pp. 226–235, 2015, doi: 10.1179/1743278215Y.0000000013. 5. M. Coramik and Y. Ege, ‘Discontinuity inspection in pipelines: A comparison review’, Measurement: Journal of the International Measurement Confederation, vol. 111. Elsevier B.V., pp. 359– 373, Dec. 01, 2017. doi: 10.1016/j.measurement.2017.07.058. 6. J. A. Phipps, ‘Technology for Assuring Integrity of Uninspectable Small Diameter Pipeline Systems’, in ADIPEC, Abu Dhabi, UAE, October 2022, SPE, Oct. 2022. doi: 10.2118/211200-MS. 7. K. Taylor, S. Turner, and G. Goodfellow, ‘A CASE STUDY ON THE APPLICATION OF STRUCTURAL RELIABILITY ANALYSIS TO ASSESS INTEGRITY FOR INTERNAL CORROSION OF UNPIGGABLE PIPELINES’, 2016. [Online]. Available: http://asme- digitalcollection.asme.org/IPC/proceedings-pdf/IPC2016/50266/ V002T07A010/6491327/v002t07a010-ipc2016-64341.pdf 8. M. Beller, C. Sabido, D. Schaller, T. Steinvoorte, S. Vages, and K. Zimmermanns, ‘Specialty Solutions for the Inspection of Challenging Pipelines’, in Rio Pipeline Conference and Exposition, 2015. 9. Y. Shi, C. Zhang, R. Li, M. Cai, and G. Jia, ‘Theory and application of mag- netic flux leakage pipeline detection’, Sensors (Switzerland), vol. 15, no. 12. MDPI AG, pp. 31036–31055, Dec. 10, 2015. doi: 10.3390/s151229845. 10. W. M. Alobaidi, E. A. Alkuam, H. M. Al-Rizzo, and E. Sandgren, ‘Applications of Ultrasonic Techniques in Oil and Gas Pipeline Industries: A Review’, American Journal of Operations Research, vol. 05, no. 04, pp. 274–287, 2015, doi: 10.4236/ajor.2015.54021. 11. A. Teitsma, S. Takach, J. Maupin, J. Fox, P. Shuttleworth, and P. Seger, ‘Small diameter remote field eddy current inspection for unpiggable pipelines’, in Journal of Pressure Vessel Technology, Transactions of the ASME, Aug. 2005, pp. 269–273. doi: 10.1115/1.1991878. 12. Yu. V. Banakhevych, ‘Technologies of cleaning and in-line inspection of gas mains’, JOURNAL OF HYDROCARBON POWER ENGINEERING, vol. 7, no. 1, pp. 16–25, Jun. 2020, doi: 10.31471/2311-1399-2020-1(13)-16-25. Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 37 Authors James Phipps Cokebusters Ltd Managing Director japhipps@cokebusters.com Nick Bettley Cokebusters Ltd Technical Director nbettley@cokebusters.com Chris Peyton Cokebusters Ltd NDT Consultant cpeyton@cokebusters.com

38 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Robust Ultrasonic Transducers for Pipeline Inspection A. Mück > SONOTEC Abstract Pipeline inspection for cracks and corrosion through intelligent inline tools relies on ultrasonic probes, demanding a 100% first-run success rate to mini- mize costs. These probes face harsh environmental conditions within pipelines, necessitating utmost stability for optimal functionality. Material selection and rigorous testing during development contribute to achieving high stability, yet not every application is anticipated. Conducting individual tests, considering factors like medium, pressure, and temperature, becomes crucial to assess in- spection feasibility beforehand. The text outlines this testing process, detailing realistic conditions the ultrasonic probes encounter. Criteria for evaluating probe stability and integrity are elucidated, with practical examples. This approach ensures effective ultrasonic inspection while maintaining cost efficiency.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 39 1. ROBUST ULTRASONIC TRANSDUCERS FOR PIPELINE INSPECTION The inspection of pipelines is important to detect damages such as corrosion and cracks that can lead to accidents. Ultrasonic testing is an inspection method that allows for precise assessment. The design of a probe as well as the quality of the tests are crucial for the results of subsequent testing with smart pigs and their analysis. 2. APPLICATIONS: PIPELINE TESTING Pipelines are an essential component of our modern world’s infrastructure. They transport oil, gas, and a va- riety of other products over long distances, contribut- ing to energy supply and prosperity. Worldwide, there are more than 3 million kilometers of pipelines, and the market continues to grow. However, pipeline operation also poses risks. Damage such as corrosion and cracks can lead to accidents and endanger human lives. That is why it is essential to regularly inspect pipelines to detect risks early and ensure efficient use. Ultrasonic testing is used for this purpose, which offers many advantages over other testing methods because it is a very precise measure- ment method. In ultrasonic testing with intelligent pigs, pipes are non-destructively tested for their leak tightness, stability, and structural integrity from the inside. Many probes are used to obtain an accurate and complete image of the pipe. The probes are designed to have low variability among themselves and undergo minimal changes during the run. The measurement results of the probes are similar, enabling precise evaluation of the pipeline. Some factors, such as the temperature and pressure in the pipeline, affect the sound field presentation and ultrasonic signals. They affect all probes equally and can only be partially controlled. Other factors are more controllable. For example, the frequency, sensitivity, and sound field presentation of the probes should be adapted to the task and made as identical as possible to achieve accurate measurement results. 3. COMPOSITION OF A PROBE The probe is an important component of ultrasonic testing systems used for non-destructive testing of materials. It is used to send ultrasonic waves into the material and capture the reflected waves to obtain in- formation about the inner structure of the material. Therefore, the composition of a probe is crucial for the quality and reliability of the test results. It consists of several components (Figure 1), which must be carefully selected and assembled according to the requirements for performance and stability. The basic composition of the probe is very similar. Figure 1: Composition of a probe

40 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY However, the environment in which the probe is used can compromise its stability: • High thermal loads can alter the geometry of the probe and damage the sensitive components • Heat can accelerate the aging of materials in the probe and impair sensitivity and reliability • Reactions with the environment can compromise the stability of the probe and alter or destroy the materials high pressure. This tests whether it can withstand the conditions. DMA analysis is also a useful tool for ana- lyzing the interaction between the medium and the layer. Different media have different acoustic properties that affect the resulting sound field presentation. Some media are confidential or not available for procurement, making tests under real conditions impossible. To check the performance of the sensor in such a scenario, tests must be simulated in the appropriate medium. • Heat and chemistry can affect the connections be- tween the individual components While all forms of testing cannot guarantee 100% op- timal inspection results, they significantly increase reliability. 4. TESTS 5. EVALUATION CRITERIA It is essential to test ultrasonic probes for their prop- erties and stability. The requirements can vary greatly depending on the application and depend on various factors. Some of the most important requirements are: To evaluate the characteristics of an ultrasonic probe, a complete determination of its acoustic properties is necessary. The ISO 22232-2 can serve as a guideline for the procedure. For this purpose, an ultrasonic labora- tory testing system (Figure 2) is used. • Duration of use • Temperature during transport and during use • Pressure in the pipeline • Transport medium in contact with the probe The duration depends on how long a pig run will be and how often the probe is intended to be used. Life cycle tests can only be accelerated to a certain extent. Longer durations may be required to ensure that the properties remain stable over the desired time period. Temperature tests are necessary to ensure that the probe works properly under various temperature conditions, including both transport and operation. A shock load due to a rapid change in temperature represents a par- ticularly high challenge. Pressure tests are another important factor in test- ing ultrasonic probes. Ingressing medium should not cause any damage. In many applications, the probe also serves as a sealing element, with leaks generally being avoided. In pressure tests, the probe is placed in an autoclave with a holding fixture and exposed to Relevant parameters include: • The high-frequency echo signal: sensitivity, center frequency, and bandwidth can be derived from this signal. • The sound field presentation, i.e., the sound pres- sure distribution in space when the probe is ex- cited. In this process, a probe and a spherical re- flector are situated within the medium. The latter is moved and the position-dependent echo is re- corded depending on the position. It is usually dis- played in diagrams which show the maximum am- plitude in color-coded form. During the development of new probes or in the case of fault analysis, such investigations are carried out completely. However, for series production, this is too time-con- suming, so the echo signal of a fixed reflector in a suitable fixture is usually used for 100% testing. In addition to determining the acoustic properties of the probe, it is essential to characterize the state of its

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 41 Figure 2: Typical test setup of a series production components and the influence of the environment on it non-destructively. It is a reliable early indicator of aging and alteration and helps to evaluate the condition be- fore the probe fails. In this process the probe is exam- ined in a test system using high-frequency ultrasound (Figure 3). This allows the dimension, parallelism and homogeneity of layers to be determined. In particular, the quality of the connection between the individual components can be examined in this way. 6. PRACTICAL EXAMPLE The task was to develop a probe for permanent use in water. Although water is essential for our lives and we take it for granted, it is a very complex substance for a materials scientist and aggressive to plastics. The acoustic parameters were typical for this application: • Frequency 5 MHz • Relative bandwidth 80% • Aperture 10 mm • High echo sensitivity In a risk analysis, the protective layer (matching layer) was identified as a critical point. To achieve optimal ul- trasound properties, epoxy resins are typically used as material because they can be cast and processed further and are robust. It had to be clarified to what extent they are stable to water and what lifetime can be assumed. Figure 3: Ultrasonic scan presentation of an integrated circuit. It shows the inner structure and reveals deviations like voids, cracks or deformations.

42 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Several corresponding probes were built, characterized, stressed, and re-measured with different materials. The following tests were defined to assess the stability: Storage at -20° C does not significantly alter this condition. Only the slight change in color indicates deformation due to different coefficients of thermal expansion. a) Storage in air, -20 °C, 4 hours b) Storage in water, 50 °C, 3 days c) Storage in water, 50 °C, additional 7 days d) Storage in water, 50 °C, additional 7 days The characterization was performed according to the aforementioned procedure. The results are shown in the following figures (Figures 4 to 5): After completion, the probe exhibits a typical echo signal. The amplitude is approximately -600 mV. A non-destructive scan of the boundary layer between the matching layer and the piezoelectric element shows a very uniform image, indicating a parallel layer and homogeneous material. The storage in water led to a slight decrease in echo amplitude (approximately -1 dB) with essentially identical signal shape. However, significant changes in the protective layer were visible during testing. Based on the information, it can be concluded that water infiltrates the protective layer and changes its structure. Continuing the tests is expected to lead to a progression of the effect, potentially resulting in destruction. The tests were also carried out with other materials (Figure 5). The results are shown in Figure 6. The change in the protective layer is more severe here. Delamination is already visible at the edge. The am- plitude of the echo signal has already decreased by 3 dB. Such a probe would have significantly lower stability and lifespan. Figure 4: Initial situation, echo pulse, and scan of the protective layer-piezoelectric element connection Figure 5: After (d) storage for 17 days in water

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 43 Figure 6: Reference with a different material, before the tests Figure 7: Reference with a different material, after the tests 7. CONCLUSION Ultrasonic probes are indispensable tools for non-de- structive material testing. To ensure that these probes actually function reliably and correctly, regular tests to check their quality are essential. There are various investigation options depending on the requirement. If the probes do not provide accurate results, optimi- zation of the design is possible. Despite harsh environmental requirements, whose effect on the probe component could be observed, the acoustical parameters could be stated stable. Using these results, it was possible to ensure the operation during the expected lifetime. Andreas Mück emphasizes: “Robust ultrasonic probes are crucial for precise pipeline inspections. Regular, in- tensive tests are essential to ensure quality and stability and to detect potential risks early on.” Author Andreas Mück SONOTEC Business Unit Director Ultrasonic Transducers andreas.mueck@sonotec.de

44 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY How to see what cannot be seen within a Disastrous, Highly Corroded Subsea Gas Pipeline during Repair and Pre- Commissioning Process P. Gholami1 & M. Nouri2 > 1Nargan-Amitis Energy Development & 2IPEC Pipeline & Process Services Abstract Repairing a subsea pipeline has its own special challenges. It goes from level- ling the pipeline inner pressure with seabed pressure at depth of damage, to cutting the line, installation of smart flanges and spool pieces, and finally going through pre-commissioning steps and miscellaneous pigging operations. During all these steps, it is inevitable to look for a way to find out what is going on inside the pipeline. This happens to be quite challenging due to the fact that there is no easy access to the pipeline through its total length and also it would be almost difficult yet definitely expensive to follow and track each train of pigs. In this paper, a case study has been investigated on a subsea gas pipeline re- pair. The pipeline had a disastrous operating history and has been damaged and wet-buckled again recently. The process and challenges of pipeline repair and pigging operations are fully explained in this paper. The practical data and calculations during pigging operations are also summarized. Finally, the paper focuses on dewatering operation of the pipeline where it is not easily possible to clearly see what is going through the pipeline and one should investigate the pigging situation based on numerical calculations and comparing them with available indications. Technical challenges along with different aspects of sub- sea operation concerns and offshore facility requirements will be discussed.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 45 1. Introduction Offshore pipelines have always their own special chal- lenges in comparison with onshore pipelines. The challenges start with designing and construction phase where one have to consider special materials for pipes, concrete coating for laying at seabed, and pipeline laying with heavy pipe-laying vessels with different methods according to different water depths. Usually J-Lay is used in deep water areas and S-Lay is used in less water depths. Subsea pipelines challenges keep going on during operation phase where the op- erator cannot have regular patrolling surveys which show pipeline weakness areas and prevent sudden damages before happening. These challenges come to the most when a pipeline is damaged and needs to be repaired. The subsea pipeline cannot be easily isolated and cut unless the pipeline inner pressure is leveled with the seabed pressure at damage location. Thus, repair team is forced to be mobilized with an additional pre-com- missioning equipment comprising of a full fleet of pumps, compressors, pigs and pre-commissioning procedure in order to support the repair process. In addition to that, repair process itself includes a professional subsea diving team to work at required depth and perform cutting, leveling, flange installa- tion, aligning and adjusting the spool piece and fi- nally tightening the bolts and nuts. Furthermore, during pigging operations and specially while working with compressed air (i.e. dewatering operation), it is not easily possible to track the pig(s) like onshore pipelines. This usually leads to a vague situation where pre-commissioning operator has to evaluate some indications and symptoms for interpre- tation of complicated conditions. All these challenges and complexities lead to a special repair process in each subsea pipeline and making it an exciting experience to share. 2. Pipeline Specifications The pipeline in this paper is a 147km 30” subsea gas pipeline which starts from an offshore gas produc- tion platform in Persian Gulf and reaches to onshore gas facility in an island. The pipeline characteristics are summarized in following table. The depth of water through pipeline length is presented in Figure 1. Table 1: Pipeline Characteristics [5] Figure 1: Pipeline Profile at Seabed [5]

46 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 2: Side View of Ruptured Area [5] Figure 3: Plan View of Ruptured Area [5] 3. Pipeline Damage History The pipeline has a long history of improper commis- sioning and maloperation. It was initially laid around 2005, yet during pipe laying a buckle situation oc- curred and due to unknown reasons, the pipeline was kept flooded with water for almost two years. This was the main cause of severe corrosion and later damages in the pipeline. Since then, the pipeline has experienced several leaks, repairs, spool installation and numerous clamp installations. The current damage in the pipeline happened suddenly in October 2021 when the pipeline operator witnessed a sudden operating pressure drop to zero. A prompt survey by helicopter was done and huge bub- bles were observed. Later, a subsea survey was performed and a rupture damage was reported around KP70 from platform. Based on survey details, pipeline has to be cut for repairing and spool installation and approximate length will be 72m. The following figure shows the damage condition at seabed. 4. Repair Process The considered process for pipeline repair is summa- rized as below. 1. Subsea Survey, Metrology and Manufacturing Spool Pieces 2. Degassing and Cleaning from Offshore Platform to Rupture Point 3. Degassing and Cleaning from Onshore Facility to Rupture Point 4. Cutting and Installation of Smart Flanges and Spool Pieces 5. Leak Testing 6. Dewatering Operation 7. Swabbing, Drying and Commissioning 5. Initial Degassing and Cleaning Before the damaged sections of the pipeline are to be cut, the pipeline shall be evacuated from any remain- ing flammable gases. Although the pipeline is already flooded due to big wet-damage, it was suspicious that some remaining gas might endanger the operation. Thus, for the purpose of safety improvement, a Poly Coated High Density Foam Pig was considered to be propelled through the pipeline in order to evacuate the pipeline from remaining products. This pig run- ning operation was performed from both sides of the pipeline (i.e. launching one pig from platform to rup- ture point and launching another pig from onshore to

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 47 rupture point). This operation was performed by in- jecting filtered sea water (treated with corrosion in- hibitor) behind the pigs. This operation was entitled Degassing operation. After degassing operation, it was decided to clean the pipeline by running metal body pigs. Since the pipe- line required appropriate cleaning, this was an op- portunistically decision to be made due to following reasons: • The pipeline was expected to contain a huge amount of debris and corrosion product due to its mentioned history; • Since the 147km pipeline was already divided into two almost half sections, it was easier to clean each section separately; • The risk of debris accumulation and pig stuck would largely be decreased in shorter sections of the pipeline; • If the cleaning operation was to be performed after integrating the pipeline, it was almost not possible to receive the huge amount of debris and corrosion products in either offshore platform or onshore fa- cility. So, discharging the debris at seabed was the only solution to this problem. Due to abovementioned reasons, two separate cleaning pig runs was performed on each section of the pipeline. These pig running operations were also performed by injecting filtered seawater which was treated by corro- sion inhibitor and biocide. The selected pig type was an especially designed pig which was a combination of cup and Bi-Di pigs which is here called a combination pig. This pig is shown in following figure. As it can be seen, it consists of both sealing disks (for sealing pur- poses, water displacement and bi-directional applica- tion) and cup disks (for high resistance against abra- sion and long distance application). The guide disks, as always, provide pig stability, alignment and, more importantly, displacement of debris. An important decision made here was to avoid running brush pigs in this pipeline. The reason why is that it was believed the pipeline with its disastrous operat- ing history is severely corroded and has a large deal of loose debris and high roughness inner wall. It means no matter how many runs of brush pigs are propelled through the pipeline, receiving corrosion products will not finish. That is because in a highly corroded pipe- line the more you scrap the inner wall, the more debris will be produced and there is no end to it. Hence, it is very important to treat these kinds of pipelines gently. During all pig running operations, accurate data meas- uring was performed and required data for evaluation of the situation were collected. This includes both pipeline pressure and volume of injected water. These information help the pigging operator to estimate the pig location based on injected volume of water and also evaluate the pigging condition based on pipeline pres- sure so that he can adjust the equipment accordingly. The summary of recorded data during degassing and Figure 4: Drawing of Bi-Di/Cup Combination Pig [5]

48 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY cleaning operations are illustrated in following figures. It should be noted that since water is incompressible, the pig location in these graphs is calculated according to the measured water volume behind the pigs divided by the cross sectional area of the pipeline. As it can be seen in both above figures, the more clean- ing pigs have been propelled through the pipeline sec- tions, the softer has become the running of next pigs. Each pig is being run with lesser pressure requirement than its previous pig. As it can be seen in above diagram, during first clean- ing operation, a pig stuck condition occurred around KP35 from platform leading to pressure increase up to maximum available pressure of flooding pumps. In this case, a plunger pump (so called as test pump) was utilized in order to pressurize the pig back pressure up to 40 bar. At this pressure, the pig was released and the rest of the operation was continued. When performing pig running operations in such a challenging pipeline, reliable pumping equipment are vital. Usually, multi-stage centrifugal pumps are utilized for running the pigs with water. Proper pumps shall be selected carefully, and more importantly in offshore op- erations, it is recommended that diesel engine driven pumps be mobilized. In addition to that, it is very cru- cial that one should always consider spare pumps when working on offshore platforms and vessels. Figure 5: Pipeline Pressure vs. Estimated Pig Location during Pigging Operations from Offshore Platform to Rupture Point [5] Figure 6: Pipeline Pressure vs. Estimated Pig Location during Pigging Operations from Onshore Facility to Rupture Point [5]

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 49 Figure 7: Schematic Arrangement of Water Injection Equipment Furthermore, when such an operation is required to be performed from platform side, a suitable ves- sel shall be selected. A vessel that not only provides enough deck space for placing the pumping equip- ment and consumable materials, but also has the ability to withstand its stability during weather conditions in order to maintain the continuity of pigging operations besides platform. The utilized equipment in this project are described and illustrated in Figure 7 and Table 2. All below equipment along with all consumables (pigs and chemical barrels) and all operating personnel were mobilized onboard an offshore vessel during the pigging operations from platform which is shown in following Figure 8. 6. Smart Flange and Spool Piece Installation After completion of cleaning operations, the two sections of the pipeline are ready to be integrated. The selected method here for this purpose is installation of smart flanges. Among different techniques to mitigate Table 2: Technical Specifications of Suction Pumps and Flooding Pumps [5]

50 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY pieces shall be manufactured based on metrology which has been performed earlier at seabed. Once the smart flanges and spool pieces are aligned and ad- justed, all bolts shall be tightened so that the smart flanges are activated. Another critical challenge that happened during this project was presence and troubles of Sulphuric con- tents at seabed. To be more specific, once the pipeline contaminations were expelled by pigging operations at seabed and due to high Sulphur content of the gas reservoir, Sulphuric contaminations were spread at seabed around the rupture area. This led to huge trou- bles for divers working on smart flange and spool in- stallation. The contamination caused the divers with body burns and scalds on their feet due to acidity of the expelled debris. Finally, the divers had to use high resisting clothing to clean the whole area by means of mud lift operation. Approximately 5000 m² of seabed was cleared by mud lift before starting the smart flange and spool installation job. 7. Leak Test Figure 8: All Equipment onboard Offshore Vessel besides the Platform [5] the damaged section of pipeline, using smart flanges is a fast and applicable approach which is of interest for offshore industry. The product offers pipeline and riser repairs without the need for hyperbaric welding and can be installed in driverless applications. It should be noted that subsea smart flange installation and pipe- line repair is fast and easy if performed right. On the other hand, special cares have to be paid during instal- lation and operation to put the integrity of pipeline in safe side [3]. After installation of two sets of smart flanges at both pipeline ends at rupture point which are already cut, spool piece(s) shall be installed. Here, the 72 meter spool which consists of two spool pieces, has been manufactured earlier at onshore factory and trans- ferred to the offshore installation location. The spool Any pipeline repair process includes a kind of testing in order to make sure there are no other leaks or dam- ages present and the pipeline integrity is ensured. Most importantly, here and in such subsea repair projects, it is essential to make sure that smart flanges and spool pieces (which are new objects recently installed on the Figure 9: Left: A Typical Smart Flange, Right: (a) Internal mechanism of smart flange, (b) Sealing energized and (c) Gripping activated [3]

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 51 pipeline system) are free from leaks. For this purpose, a leak test operation was considered. Yet, the major issue was how to select a proper test pressure. As it was men- tioned earlier, the pipeline had a catastrophic back- ground and since no In-Line inspection operation had been performed on the pipeline recently, and thus, no FFS or FFP was available, selecting a proper test pressure was quite challenging. Normally, what goes through these situations is as follows [4]: 1. A Fitness-For-Service report be prepared accord- ing to the latest ILI operation; 2. Pipeline MAOP be adjusted according to FFS report; 3. Leak test pressure be selected according to MAOP. Despite the mentioned steps, since no late ILI report had been available on this pipeline and also due to the fact that the pipeline rupture had been occurred at a pressure lower than pipeline MAOP, rather conserva- tive considerations led to selecting of 60 bar pressure value as leak test pressure. The leak test operation was completed successfully and the pipeline proved its integrity for withstanding the pressure of 60 bar and was ready for dewatering operation which was expected to be the most challeng- ing operation in whole project. 8. Dewatering As it was mentioned earlier, the dewatering operation in this project was expected to be the most challeng- ing step of the job. The reasons for that can be summa- rized as follows: 1. According to pipeline history, the pipeline inner wall is believed to have high roughness; 2. The long length of pipeline (150km) along with its roughness provides a severe abrasive circum- stance for pigs` polyurethane disks; 3. The pipeline profile (figure 1) includes intensive high and low fluctuations which impose addi- tional risks to the pigging operation; 4. The pipeline after integration (150km) has not been pigged and earlier pigging operations were performed in shorter lengths (70km and 77km). It means that the piggability of the pipeline is not en- sured yet. According to pipeline condition, it was decided to run four pigs in dewatering train. The first two pigs carry a batch of fresh water to desalt the inner wall of the pipeline which has been in full contact with sea water. The amount of fresh water equals to 2% pipeline length [1]. The next pigs push the train and remain- ing water after the first pig to be expelled out of the pipeline. The selected type of pigs were the same Bi-Di/ Cup Combination pig (figure 4) which proved to be suc- cessful during the previous pigging steps. The Figure 10 shows the arrangement of the dewatering train. The pigs were propelled by means of oil free compres- sor station with capacity of maximum 4190 cfm which were mobilized on the vessel deck alongside of the platform. In order to estimate the pig train location, a theoretical calculation was being done. Since air is compressible, the pig location is calculated according to the following equation. Figure 10: Arrangement of the Dewatering train as performed [5]

52 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Where: P1: Atmospheric pressure V1: Injected volume of air at atmospheric pressure (compressor station intake) T1: Ambient air temperature P2: Pipeline pigging pressure V2: Injected volume of air at pipeline pressure (com- pressor station discharge) T2: Injected air temperature (compressor station discharge) Thus, the pig location will be calculated with dividing V2 by pipeline cross sectional area. During the dewatering operation, all above mentioned parameters were recorded and pig location calculation was being done continuously. Also, water discharge at receiving location at onshore was being simultane- ously monitored. Yet, some challenges came along Date and Time 2:10 on 7 Aug. to 20:30 on 7 Aug. 22:30 on 7 Aug. to 4:00 on 10 Aug. 4:00 on 10 Aug. to 16:00 on 10 Aug. 16:00 on 10 Aug. to 14:30 on 11 Aug. 14:30 on 11 Aug. to 15:30 on 11 Aug. 15:30 on 11 Aug. to 9:00 on 12 Aug. 9:00 on 12 Aug. to 15:40 on 12 Aug. 15:40 on 12 Aug. to 15:30 on 15 Aug. 15:30 on 15 Aug. to 18:45 on 15 Aug. 18:45 on 15 Aug. to 11:30 on 16 Aug. 11:30 on 16 Aug. to 12:00 on 16 Aug. 12:00 on 16 Aug. to 23:00 on 16 Aug. 23:00 on 16 Aug. to 23:59 on 16 Aug. 00:01 on 17 Aug. to 14:00 on 17 Aug. 14:00 on 17 Aug. to 12:00 on 18 Aug. 12:00 on 18 Aug. to 11:00 on 20 Aug. Pressure Range at Platform (bar) Remarks / Outlet Condition at Onshore 1.5 ~ 9.0 Launching the four pigs one by one Fluctuating from 7.5 ~ 8.7 Continuous water discharge through 2 x 6” pipes. Pressure range: 1 ~ 2 bar Flow Rate (cfm) 1600 2240 2240 Pressure rise from 8.5 to 10 Pressure 2240 decrease from 10 2240 to 9.1 Small pressure rise 9.1 to 9.2 Pressure 4:00 ~ 8:40, no water discharge 8:40 ~ 10:15, full discharge 2 x 6” 10:15 ~ 11:30, small discharge 2” 11:30 ~ 16:00, no water discharge 16:00 ~ 2:00, 1 x 6” discharge 2:00 ~ 14:30, full discharge 2 x 6” 14:30 ~ 15:30, no water discharge 15:30 ~ 9:00, full discharge 2 x 6” No water discharge. 2240 decrease from 9.2 Full water discharge 2 x 6” 4190 (Compressors Added) 4190 4190 4190 4190 4190 4190 4190 4190 4190 ~ 8.6 Slight pressure increase 8.6 ~ 9 Pressure rise from 9.0 ~ 16.5 Pressure drop from 16.5 ~ 15.7 Pressure rise from 15.7 ~ 16.9 Pressure steady at 16.9 Pressure rise from 16.9 ~ 17.5 Pressure steady at 17.5 Pressure rise from 17.5 ~ 18.3 Pressure rise from 18.3 ~ 19.4 Full water discharge 2 x 6” Sudden discharge stoppage. No water discharge. Sudden water discharge 2 x 6” full. Sudden pressure rise to 10 bar. Pressure range: 7 ~ 6 bar. At 18:45, discharge stoppage. No water discharge. Sudden water discharge 2 x 6” full. Decrease in water discharge. At 12:00, discharge stoppage. No water discharge. Full water discharge 2 x 6” for 10 minutes. Then, 1 x 6” water discharge. At 23:59, discharge stoppage. 00:45 ~ 2:45, small discharge 3” 3:30 ~ 6:20, small discharge 3” No water discharge. Pressure rise from 19.4 ~ 22.0 Inserting shocks. Stopping all compressors. Table 3: The pressure recordings during hours of the dewatering operation

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 53 Figure 11: Pressure Recordings during Hours of the Dewatering Operation [5] Figure 12: Calculated Location of the First Pig of Dewatering Operation [5] which faced the operation with critical problems. The water discharge was stopped and it was perceived that the pig train is stuck. The pipeline pressure (which was around 8 to 10 bar during the operation) started to rise sharply and increased up to 22 bar. Several observa- tions were made during all undesirable happenings which can be seen in related graphs. The pressure recordings during hours of the dewater- ing operation listed in Table 3 is illustrated in Figure 11. Based on earlier-explained equations, the hours of air injection can be correlated to pig location. It means that by multiplying air injection rate by hours of in- jection, one can obtain the accumulated amount of in- jected air which will be used to calculate an estimated location for the pig train. It should be noted that since air is compressible, the calculated location of the pigs is highly dependent to pipeline pressure. This fact adds some miscalculations and contradictions in illus- trated graph which might be incoherent and not real. Yet, the total perspective and big picture shall be taken into view. As it can be seen in Figure 12, the water discharge stop- page and pipeline pressure increase has been occurred at around KP 102 of the pipeline. It can be concluded that from that moment (water discharge stoppage) the pig train has not moved. Thus, the calculated location after that point is calculation error due to compressi- ble nature of air. In addition to that, once the pigs get stuck, some bypass flow forms around their disks. The amount of this bypass flow cannot be known with- out knowing the geometrical position of the pigs. But, since it is known that pigs` location is fixed and pigs are not moving, the amount of this bypass flow may be guessingly calculated by performing some numerical adjustments on the above graph. Also, it can be pre- sumed that the amount of hypothetical bypass flow may differ at different stages with different diagram slope. After performing some numerical calculations for adjusting the diagram, following results were derived. The indicated areas in the above figure are to be described Figure 13: Calculated Location of the First Pig of Dewatering Operation after Numerical Adjustments and Reduction of Hypothetical Bypass Flow [5] as below: A. Sharp pressure rise once the first pig gets stuck at KP 102 and water discharge at onshore is stopped. B. Pressure decrease as the first and second pigs are released temporarily and water discharge is being received at onshore. C. Sharp pressure rise once the third and fourth pigs are stuck at KP 102 and water discharge is stopped again. D. This area still includes numerical error which

54 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY makes the diagram not very clear. It is known that the pig is not moving since no water is discharged at onshore. The amount of bypass flow which had to be deducted in this area is numerically calcu- lated to be around 1100 m³/hr. E. This area still includes numerical error which makes the diagram not very clear. It is known that the pig is not moving since no water is discharged at onshore. The amount of bypass flow which had to be deducted in this area is numerically calcu- lated to be around 2500 m³/hr. After the pigs got stuck, different actions were made leading to inserting shocks from receiving side. This was not finally successful since the pipeline pres- sure at launcher side reached to 22 bar which was the maximum available pressure of compressor station. Inserting shocks from receiving end did not result in any more water discharge and pigs movement. Thus, the operation was held on standby so that further de- cisions will be made accordingly. Nevertheless, an un- expected event occurred. 9. Second Damage On 23 August, the pipeline pressure at platform (launcher side) unexpectedly started to drop sharply. It dropped from 22 bar down to 6.7 bar without any actions being made on the pipeline and stayed steady even with compressor station working. This event was concluded to be a new damage on the pipeline due to two major reasons: 1. This amount of sharp pressure drop could not be correlated to any other phenomena. 2. The 6.7 bar steady pressure could easily be corre- lated to the depth of pipeline at KP 102 (pig stuck location). Consequently, an ROV survey was planned to be per- formed around suspicious area. The result is presented in Figure 14 which shows a wide rupture at KP 102 with stuck pigs being visible. Figure 14: ROV Result on Second Damage of the Pipeline [5] Figure 15: Recovered Stuck Pigs from Damaged Location (Third and Fourth pigs of first Dewatering Operation) [5] flange and spool piece installation. The strange witnessing during the second repair was when the cut section of the pipeline was recovered and the stuck pigs were removed. As it was mentioned in earlier sections, the third and fourth pigs of dewater- ing operation were remaining stuck at damage loca- tion. These pigs were recovered after cutting the dam- age area of the pipeline are shown in Figure 15. The imposed damages on the pigs are extraordinary. There were no disks left on the pigs which was such a rare thing to be observed in any pigging operation. Thus, the pipeline is going through another flooding, repair and dewatering operation accordingly. 10. Conclusion Just like the repair process for the first damage, the sec- ond damage was also went under similar repair pro- cess. Cleaning from both sides, pipeline cutting, smart Based on the discussed matters in this paper, following conclusions and recommendations can be presented.

1. Historical bad operating of the pipeline and un- necessary keeping of water inside pipeline has made it highly corroded and almost un-repairable. 2. Huge amount of Sulphur content has severely made corrosion process faster and more disas- trous, making it hardly operable. 3. During repairing process and pre-commissioning of such corroded pipelines: a. It is better to clean the pipeline before repair process and not after it. b. It is recommended to start cleaning process with softer pigs and progressing towards harder and metal body pigs. c. It is highly required that cleaning pigs be run one by one and not in a pig train. d. Using of brush pigs is not recommended in such corroded pipelines as it scrapes the pipe wall to its end. e. It is easier to expel the pipeline debris at sea- bed, yet consideration on acidity content at sea- bed shall be made. f. Before starting the repair process of such rup- tured pipeline, it is recommended to perform a full ROV survey on the pipeline in order to look for further probable and potential damages. g. During all steps of the project, fast access to ROV survey is an important privilege for appro- priate decision makings. h. For dewatering operation, it is recommended that pig train be divided into smaller trains and even better to run pigs one by one. All in all, in such offshore projects and subsea pipeline repair and pre-commissioning operations, all neces- sary arrangements and equipment shall be provided and all possible probabilities shall be taken into con- siderations before starting the job. The repair team shall be ready for any possible and undesirable events. Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 55 11. Acknowledgment The authors would like to thank IPEC for permission to publish this paper. The authors also express their sincere appreciation to Client for cooperation and full support during operation of this project in Persian Gulf. References 1. DNV-OS-F101, Submarine Pipeline Systems. 2. DNV-RP-F113, Pipeline Subsea Repair 3. Shaghaghi, A.M. and Mohammadnia, S. (2014), “Three dimen- sional finite element analysis of 4 inch smart flange on offs- hore pipeline”, Ocean Syst. Eng., Vol. 4, No. 4, 279-291. 4. ASME B31G, Manual for Determining the Remaining Strength of Corroded Pipelines 5. IPEC Confidential Documents of Projects` Histories, 2021-2023 Authors Pooya Gholami Nargan-Amitis Energy Development Senior Offshore Project Engineer pooyagholami@gmail.com Mahdi Nouri IPEC Pipeline & Process Services CEO and Project Manager nouri@ipecgroup.net

56 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY In-pipe Ultrasonic Inspections of Mud and Tailing Lines: how to manage difficult to remove Scaling, provide quality and accurate Defect Assessments of steel and HDPE A. O’Neill1; H. Quakkelsteijn2 > 1Rio Tinto Yarwun Refinery; 2Intero Integrity Services Australia Abstract Rio Tinto Yarwun Aluminium Refinery (RTY) is expanding its pipe- line integrity assessment technologies. As part of this effort, RTY has been working with Intero Integrity Services (Intero) to introduce Intero’s Pipeline Surveyor services, a free-swimming pipe inspection tool. Rio Tinto is one of the world's largest mining companies, operating in 25 countries with a portfolio that includes iron ore, copper, alu- minum, lithium, and other materials needed for everyday life. The Yarwun Aluminum Refinery located in Gladstone, Australia is oper- ating since 2004. Australia is a country with very strict regulations and a tight social license to operate. There is a need to provide it’s owners with suitable technologies and methods to offer inspection technologies not only to detect pipeline defects, but also to evaluate the integrity and safety of their pipelines. RTY has been working since 2019 to introduce Intero’s Pipeline Surveyor as inspection technology for difficult-to-inspect mud, slurry, and caustic pipelines. In 2021 an inspection was carried out on an 8kms steel mud line of DN750. This paper will provide an overview of the Pipeline Surveyor tech- nology and information on the evaluation of inspections conducted for its application in Australia.

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 57 1. Introduction Matrix RTY’s has an in-house department for asset integrity with expertise in pipeline integrity assessment tech- nologies. This chapter presents the background of this initiative and the technologies that RTY currently possessed. 1.1 Background The total length of mud and slurry pipelines at Rio Tinto worldwide will be hundreds of kilometers. This can be broken down between steel and HDPE pipelines. All pipelines in Australia are constructed in accordance with AS2885 and take in consideration these lines can be in some very remote areas. Due to asset aging, environmental changes, as well as government regulations, emphasis is beginning to be placed on pipeline maintenance and management, and interest in integrity assessment technologies is growing. In response to these changes, Rio Tinto has begun to expand integrity assessment technologies. 1.2 Integrity Assessment methodology of RTY RTY has proprietary methodologies for pipeline main- tenance and integrity assessment. RTY did not have a technology to assess the integrity of the pipe body. Therefore, this aspect needed to be expanded. There are many mud and tailing pipelines in Australia. In addition, since there are many pipelines with complex alignments that weave through gaps in other infrastruc- ture, there are many “unpiggable” pipelines in Australia. Therefore, RTY has been working with Intero since 2019 to apply Intero’s free swimming, Pipeline Surveyor, in Australia. 1.3 Pipeline Surveyor For maximum flexibility, the system applies a con- tact-free ultrasonic measuring head that is able to scan the full surface of the pipe wall. Dual diameter, mitered bends, full-bore unbarred tee pieces, and sin- gle-entry configurations are well within the capabili- ties of our system and can be inspected utilizing reg- ular, high, and ultra-high resolutions. The pipeline Surveyor aims for unpiggable pipelines ranging from 2” to 64” and located from subsea offshore to remote areas anywhere in the world. • Multiple transducers evenly distributed over the tool’s circumference • High speed Helix • Rotating mirror covering entire pipe wall • Flexibility to increase resolution and/or measure- ment grid 2. Preparation Mud and tailing lines tend to have thick layers of scal- ing which requires a tailored cleaning program. 2.1 Selecting the right inspection method Although the pipe characteristics allowed for a Magnetic Flux Leakage (MFL) inspection, the anticipated amount of scaling had the potential to result in a blockage. A com- bination of pipe geometry factors, such as back-to-back bends, multiple wall thicknesses, as well as a very tight receiving area too small to receive an MFL tool, resulted in Intero’s Pipeline Surveyor being selected for the job. The biggest challenge using an UT ILI tool was getting the pipeline sufficiently clean. 2.2 Launching and receiving For launching the permanent installed equipment was to be used. The launcher was, however, likely designed for MFL operations. To launch the single body Surveyor correctly a special push rod was designed to safely push it into position. The mudlines are open ended during normal opera- tions. A challenge was the receiving area which has very limited space, hence a tailored receiver was built for the job with sufficient capacity to release scaling.

58 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 1: A combined effort Rio Tinto, Contract Resources and Intero Figure 2: Launcher location during launch of gauging bidi Figure 3: Tight receiver location 3. Execution In September 2021 the pipeline inspection was exe- cuted. The overview and results of the inspection are presented in this chapter. 3.1 Purpose of the Inspection RTY had indications, based on manual Ultrasonic Thickness Testing results, that areas of the pipeline were close to minimum allowable thickness. This was par- ticularly the case around the 6 o’clock position due to erosion corrosion. Since the pipeline had underground sections a fit for purpose inspection was required which meant a full 100% coverage inspection was required. Key pipeline characteristics: Diameter: DN750 Length: 7945m 3.2 Cleaning In consultation between RTY, Contract resources and Intero a progressive cleaning program was determined. The challenge was to remove the hard scaling, so it was clean enough for ultrasonic inspection and not too ag- gressive to damage the pipe wall. After a flush, a few foam poly pig runs and a few brush pig total wire runs, the line was isolated from the supply tank. Since the cleaning runs were executed with an open-end pipeline there was hard scale noted on the inner wall, most notably at the 06:00 position in the last few meters of the pipeline. The scale on the other clock positions was notably softer. It took some force from a shovel to remove the scale. It was estimated to be 5-7mm thick in spots. As a result of the initial assessment another 8 total wire cleaning runs were performed. Wall Thicknesses: 9.5 mm, 12.7 mm and 15.9 mm 3.3 Bidi Results The results of the cleaning runs were not entirely

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 59 Figure 4: Scaling at 6 o’clock position Figure 5: Scaling 5-7mm satisfactory as scaling remained visible. However, there was no guarantee this was the case over the en- tire pipeline. In consultation with all 3 parties, it was decided that more cleaning runs would not make a dif- ference in achieving perfect cleanliness. The bidi run had another important role of obtaining valuable data to prepare for the ILI. The pipeline geom- etry, elevation differences and enormous pump capacity was a challenge to run an ILI tool in the 20m/min range. The bidi run had two unexpected results. First one was that the receiver was seriously challenged to deal with a huge amount of scaling the bidi had removed and secondly be- cause the bidi gauging plate was damaged beyond what would have been acceptable. The other challenge was that it was very difficult to control the speed of the tool. The damage of the bidi was deemed to be a result of hitting an air pocket while navigating a section of back-to-back bends leading to an underground sec- tion. Consequently, based on the first run parameters it was decided to perform a second bidi run, with the aim to simulate the optimum for the ILI run. The re- sults of the second bidi were within the set conditions with no damage to the gauge plate. With some minor changes at the launching, it was also possible to con- trol the inspection speed. Finally, the amount of scal- ing was much less this second run. 3.4 Ultrasonic Results With two bidi runs to prepare the ILI tool ran around the calculated optimum speed of 19m/min. At evalu- ation of the UT data, it showed there were still areas where no UT data was obtained, but mostly outside the critical 6 o’clock area. Figure 6: Damaged gauging plate 3.5 RTY Remaining Life Assessment A remaining life assessment was completed in-house by Rio Tinto engineers. The ILI data clearly showed internal erosion along the bottom of the pipeline, this is consistent with sliding bed erosion, which is typical in slurry pipe- lines. Although the pipelines were not fully cleaned, there was sufficient data to obtain a very good assessment of the bottom section along the entire length of the pipeline. Continuous erosion along the bottom of the pipe in ef- fect creates a continuous groove along the pipeline. From a pipe design point of view, this is very similar to a global erosion case, and the assessment was based on basic hoop stress calculations. It is noted previous assessments had been completed on the pipeline in relation to self-weight, seismic and wind. These all showed that pressure was the governing design case. The ILI data had been provided in tabulated format, which included the minimum measured value in each pipe segment (approximately 12.5m lengths between each weld) and the chainage along the pipeline. This data was then overlayed with the pipeline elevation data. The inspection data showed erosion was present at the 6 o’clock positions over a multitude of standard pipe lengths, however not gradual over the entire pipeline length. In total following data was compiled and overlayed in a single chart which is shown in Figure 7:

60 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 7: UT data presentation showing effect of scaling presence • Pipeline elevation vs chainage • Original nominal pipe thickness perform a local area loss analysis. This calculation was completed 3 times with slight variations, the reason being to understand how sensitive the design is to some variable. • Measure thickness from ILI data • T(mm) 3 pumps • 3x Required thickness lines (see below for explanation) • Underground areas highlighted. Note that the pipeline flows from left to right on the graph. Pumps are located on the left and pump the slurry about 100 meters vertically over the 9km length of pipeline. The data showed significant loss of material along the entire pipeline. However, it also showed some areas with higher losses than others. These were in sec- tions of higher “up-hill” gradient. It is unknown why the up-hill gradients show much higher material loss than similar downhill gradients. Ultimately given that it is not practical to change the pipeline gradient, no further investigation was conducted. The minimum re- quired pipe thickness was calculated based on the original pipeline design standard B31.11. This is based on the basic hoop stress calculations provided in that standard. As dis- cussed earlier the nature of the material loss results in this being a suitable assessment method. There is no need to This is a basic hoops stress calculation form B31.11, using a fixed elevation at the discharge of the pumps, which is almost the lowest elevation along the pipe- line. This number is what was used to communicated to a wider audience when asked “what is the mini- mum required thickness”. Is much easier to people to understand a single number, rather than having to refer to a graph every time. • T(mm) 3 Pumps & Elevation The same calculation was performed again, this time using the specific pipeline elevation to modify the pres- sure. As a result higher elevation sections of the pipeline have a lower required thickness. This is the “true” mini- mum required thickness for any section of the pipeline. • T(mm) 3 Pumps & Elevation & Materials Certs The material certificates for the pipeline were reviewed, and the material with the lowest yield stress was selected. A method specified in AS1210 (Australian standard for

Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY 61 pressure vessel design) adapted and then used to calcu- late a new SMYS for the pipeline. Refer AS1210 Appendix A. The same hoops stress calculations were completed using this revised material yield strength data. This line represents the “absolute lowest” minimum required thick- ness, and is provided to give a feeling of the sensitivity of the analysis. It was not used for formal decision making. A second graph was produced based to show the “end of life” data along the pipeline. For each datapoint, the measured thickness was compared to the origi- nal thickness and a yearly wear rate determined based on linear trend. This was then used to calculated time to reach the required minimum thickness “t(mm) 3 Pumps + Elevation”. A further calculation was con- ducted to determine the date at which this would occur. The results of this are shown in Figure 9. The make the data a easier to comprehend, a line was manually drawn to the show the “lower bound life es- timate” on the data (shown as red-dashed). This graph is what was presented to the company manage- ment to allow for decisions to be made on a replacement / rectification schedule. The power of this approach is a simple graph shows at what date the given section of pipeline must be either rectified or removed from service. From a Pipeline Operators point of view this is the exact data they need to be able to make informed decisions. • Rectification Strategy The pipeline was re-designed in preparation for re- placed using a much high corrosion allowance based on the expected life of the facility and the more re- cent design standard B31.4. This resulted in DN750 Schedule 30 pipe being specified, with a corrosion al- lowance of 10mm. A combination of pipeline replacement and pipeline rotation is included in the rectification strategy, based on input from piping contractors of what is most fea- sible in each section of pipeline. The overall timing of the rectification is staggered based on the End-of-Life graph. This allows cost of rec- tification to the spread over several years, without cre- ating an increase in risk of pipeline failure. Figure 8: Graph with various overlay data showing minimum pipe thickness

62 Pipeline Technology Journal - 1/2024 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 9: Graph showing “End of Life” date 4. Conclusion data in a simple graph that showed a prediction of when each section of the pipeline would reach End of Life. Mud and tailing lines are critical assets for Rio Tinto. The inspection showed that although 100% cleanliness was not achieved the inspection data allowed Rio Tinto to make a well-informed assessment of the integrity of the pipeline. RTY, Contract Resources and Intero will continue to work for the expansion of these inspection technol- ogies for the integrity assessment of pipelines within the Rio Tinto organization. As a result of the ILI inspection and remaining life as- sessment RTY was able to make informed decision to spread the rectification work over several years without increasing the risk of pipeline failure occurring. A key mechanism for this to occur was the presentation of the References 1. B31.11 - Slurry Transportation Piping Systems 2. B31.4 – Pipeline Transportation Systems for Liquids and Slurries 3. AS1210 – Pressure Vessels AuthorS Andrew O’Neill Rio Tinto Yarwun Refinery Ltd Specialist Asset Engineer Herman Quakkelsteijn Intero Integrity Services Australia Pty Ltd Manager Australia, New Zealand and PNG herman.quakkelsteijn@intero-integrity.com

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64 Pipeline Technology Journal - 1/2024 ask the experts Ask the Experts Safety & Inspection Q1) What are the current best practices for managing and preventing corrosion in pipelines? Rodolphe: Preventing corrosion relies on establishing a set of prevention barriers. While significant progress has been made in the engineering domain (Corrosion coupons, ER Probes, Pigging, etc.), other crucial bar- riers, such as the human factor and the management system factor, play equally important roles. Some typical points for consideration include: • Is the system effectively consolidating corro- sion-related data to extract valuable insights? • Are corrosion and integrity teams collaborating ef- ficiently and effectively? • Is the sharing and integration of lessons learned effectively taking place within the organization? These questions underscore the multifaceted na- ture of corrosion prevention. Therefore, alongside ad- vancements in engineering, the current best practices for managing and preventing corrosion in pipelines include maintaining an efficient management sys- tem, competent personnel, and a robust safety culture within the organization. State-of-the-art pipeline integ- rity management software solutions, such as Synergi Pipeline, provide advanced analytics, such as corrosion growth modelling features, making it easier to moni- tor, manage and prevent corrosion growth. They also offer improved communication with their capability to seamlessly connect to Corrosion monitoring systems. Q2) How can the uncertainties and challenges associated with complex pipeline geometries, materials, and operating conditions be managed? Troy: Managing uncertainties and challenges associated with complex gas and oil pipeline geometries, materials, and operating conditions requires a combination of ef- fective monitoring, risk assessment, leak detection, and mitigation strategies. Operators can face a wide range of issues with these situations, including failures such as cracks, leaks, corrosion, and material failure. Re- mote Telemetry Units (RTUs) can be useful by contin- uously monitoring for changes in conditions and man- aging remote automation. Probabilistic risk models should be utilized where uncertainties can influence decision-making and drive continuous improvement in data collection, as they quantify the likelihood and con- sequences of various scenarios, aiding in informed deci- sion-making. Companies can better prepare for risks by identifying credible threats, assessing their impact, and developing a plan to mitigate them. Rodolphe: Effectively managing uncertainties requires the implementation of a comprehensive risk assessment, en- abling the prioritization of mitigation actions. The usual risk assessment approaches often fail when multiple threats interact (especially if some data is missing), and probabilistic approaches are able to account for data un- certainty but not modeling uncertainties. A new approach is using Bayesian Networks, a form of machine learning, to construct mechanistic and probabilistic risk models. These networks excel in handling both types of uncertain- ties and offer adaptability in scenarios with missing data. For over a decade, DNV has been using this approach to aggregate information from various sources to address threats like corrosion, stress corrosion cracking, third- party damage, illegal tapping etc. Just take a simple ex- ample: an external pipeline corrosion model should not depend only on corrosion but also on other mechanisms such as cathodic protection, coating degradation, vegeta- tion and even weather patterns. This approach allows the creation of truly comprehensive risk models.

Pipeline Technology Journal - 1/2024 ask the experts 65 Q3) In what scenarios is direct assessment preferable to inline inspection for pipeline safety, and what are the trade-offs between these two approaches? Troy: Industry and regulatory changes often favour ILI over Direct assessment (DA). That said, DA methods can be preferable to inline inspection (ILI) tools in cer- tain scenarios. DA is typically used when ILI is not fea- sible due to unpiggable pipeline parameters or condi- tions such as diameter, flow, and other restrictions or difficult to inspect. The trade-offs between these two approaches are: • Cost: DA is generally less expensive than ILI and even more so when internal resources are used. • Accuracy: ILI is more accurate than DA when high- er-resolution tools are used • Time: DA can take longer to complete than ILI when scheduling external vendors and multiple surveys are required. • Data Volume: DA generates a large amount of data, which can be difficult to manage and analyze. Rodolphe: While ILI offers unparalleled value by pro- viding vital information about the type, location, and size of anomalies, it falls short in explaining the un- derlying mechanism causing the defect. This is where the Direct Assessment process becomes invaluable as it addresses the "Why?" question, offering insights into the occurring mechanism and facilitating pre- ventive measures. Ideally, a synergistic approach is recommended where In-Line Inspection and direct assessment complement each other, ensuring a com- prehensive evaluation of pipeline safety. Q4) How can data from multiple sources and technologies be integrated to improve the accu- racy and reliability of pipeline defect detection and assessment? Troy: Data from multiple sources and technologies can eas- ily be integrated with proper software tools that support rich analytics from data managed in a standardized format in a common storage repository. Information crucial for pipeline defect integrity assessment is sourced from vari- ous channels like pipeline inspection tools, field measure- ments, sensors, testing, and GIS. However, the journey of data consolidation introduces challenges, such as issues with diverse formats, align- ment variations, and accuracy levels. Extracting mean- ingful insights from integrated datasets is complex, and ensuring the reliability of integrated data requires robust quality assurance processes. Fortunately, software solu- tions like DNV’s Synergi Pipeline can serve as a key ally in overcoming these challenges: • • Efficient Integration: The software seamlessly incor- porates diverse formats, overcomes alignment vari- ations, and ensures accuracy through standardized protocols. Insightful Analysis: Leveraging advanced data analyt- ics techniques becomes streamlined with software, employing machine learning algorithms, statistical analysis, and data visualization tools to extract mean- ingful insights from integrated datasets. This analyt- ical approach enhances defect detection and assess- ment accuracy. • Reliable Data Quality: Software plays a pivotal role in ensuring data reliability through robust quality as- surance processes. Procedures such as data cleansing, validation, and verification identify and rectify incon- sistencies and inaccuracies within datasets, maintain- ing high data quality standards. Q5) How can the frequency and scope of inline inspections be optimized to reduce costs and risks? Troy: The use of in-line inspection is expanding among pipeline operators. The development of new technolo- gies and innovative techniques has helped to improve accuracy, efficiency, and lower costs. The use of soft- ware which supports and integrates detailed defect assessment, anomaly lifecycle management, and risk/ condition-based inspection scheduling to understand and evaluate mitigation strategies will help reduce costs and risks. Rodolphe: To optimize inline inspection (ILI) frequency and scope for cost and risk reduction, it's crucial to design a tai- lored ILI system following API 1163 recommendations for each pipeline's unique challenges. Clearly defining inspec- tion objectives is essential—answering questions like cred- ible mechanisms and expected defects aids in selecting appropriate technologies for valuable results, ultimately leading to cost savings and risk reduction. A comprehensive Threat Assessment is crucial in fine-tuning the ILI system to target and mitigate specific risks, enhancing the efficiency and cost-effectiveness of the inline inspection strategy.

66 Pipeline Technology Journal - 1/2024 ask the experts Q6) How have recent innovations in pipeline inspection techniques improved the detection and management of potential safety hazards? Troy: Recent innovations in natural gas and oil pipeline inspection techniques have significantly improved the detection and management of potential safety hazards. Non-destructive testing (NDT) technologies are helping oil and gas producers across all market sectors. Some of the most effective techniques include: • Ultrasonic Testing (UT): UT instruments facilitate faster setup, reduce inspection time, have none of the health risks associated with radiation, and ensure the full volume of a weld is covered. • UAVs and Drones: UAVs equipped with sensors are more efficient and cost-effective than traditional methods, simultaneously reducing the risk of human injury. • Sensors: Optical and other sensors play a pivotal role in detecting leaks, strain, fatigue, and ground movement. These techniques have enhanced the accuracy, efficiency, cost-effectiveness and safety of pipeline inspections. Rodolphe: Historically, corrosion was the main focus of the industry's innovations, which explains the current matu- rity levels of Metal Loss inspection techniques. Now, other damage mechanisms, such as Stress Corrosion Cracking (SCC) and Geohazards, are responsible for many high-con- sequence failures. As outlined by Troy, the industry has di- versified its focus and implemented advanced techniques, with notable advances in: • Crack Anomalies: The detection of cracks in gas pipe- lines has substantially advanced with the recent de- velopments in EMAT (Electromagnetic Acoustic Transducer) ILI technology. Ultrasonic tools have also considerably evolved, making these innovations in- dispensable for the accurate detection, identification, and sizing of crack anomalies in liquid & gas pipelines. • Material Properties: Challenges like lost pipeline records, non-compliance with as-built records, and changes during the pipeline's lifespan can now be addressed through advancements in ILI tools in identifying hard spots and Pipe Grades, allowing accurate fitness for service of pipelines. • Pipeline Strain and Movement: Real-time Strain Gauges and High-Resolution ILI Geometry tools provide cru- cial insights into bending strains and pipeline move- ment, allowing for proactive measures to mitigate po- tential risks. As the industry continues to advance in pipeline inspec- tion, questions arise regarding other critical aspects of pipeline integrity management. Addressing issues such as data errors, overcomplex processes, lack of safety cul- ture, and potential loss of competencies may hold the key to making a more impactful change in reducing pipeline incidents. Q7) What are the key challenges in assessing and mitigating risks associated with pipeline integrity? Troy: Some of the challenges in assessing and mitigating risks associated with natural gas and oil pipeline integrity include accurate prediction and assessment of internal and external corrosion, construction issues, operational practices, and third-party damage. Many companies also struggle with data quality and the impact that unknown and incorrect data have on risk assessment accuracy. The US regulatory body, PHMSA, has conducted mul- tiple risk workshops with pipeline operators and has identified general weaknesses in some of the more basic risk models used in the industry. The report pro- vides an overview of methods and tools for improved pipeline risk modelling, including the use of more ad- vanced quantitative and probabilistic models with monetized risk, consideration for data uncertainty, and the identification of mitigative measures. Rodolphe: Addressing and mitigating risks associated with pipeline integrity involves navigating several significant challenges: 1. Tailoring the right model for your system: Tailoring models to the specific characteristics of the pipeline operators' system and data enhances the accuracy of risk predictions beyond ‘off the shelf’ models. 2. Data Quality Issues: Inconsistent, incomplete, or inaccurate data is a major obstacle to conducting reliable risk assessments. Robust data quality as- surance processes, including thorough validation and cleansing procedures, are vital. 3. Dealing with Missing Data: The absence of data often has a significant impact on the final risk re- sults. Employing effective strategies to address

Pipeline Technology Journal - 1/2024 ask the experts 67 Find more of your questions answered here: www.pipeline-journal.net/ news/ask-experts This issue's experts Troy Weyant, Product Manager - Pipeline Product Line, DNV Troy joined DNV in 1994 and is currently responsible for the pipe- line risk & integrity management software strategy and roadmap to meet the needs of the global integrity management market. Before this role, Troy held the position of Principal Integrity Solutions Consultant responsible for the implementation of projects based upon DNV's Asset Integrity Management suite of products. He has also been responsible for the development of DNV's MAOP man- agement solution and has served as a Synergi Pipeline technical lead for large integrity and GIS implementation projects in the US and abroad. Rodolphe Jamo, Regional Sales Manager - Digital Solutions, DNV Rodolphe joined DNV in 2022 and has 15 years of experience in the Pipeline Integrity Management field. He holds an MSc in GIS and started his career as a Pipeline Risk Engineer and then moved to Project Management responsible for the implementation of multiple PIM Solutions across the globe. In his role as Senior Key Account Manager, he was also responsible for the provision of tailored integrity and inspection solutions to major gas opera- tors. Rodolphe’s current focus is on supporting operators in their Digital journey via DNV’s suite of Digital Solutions. With each issue of the journal, the "Ask the Experts" section focuses on a new topic of particular relevance to the pipeline industry. People from the international pipeline community are invited to send in their questions which will afterwards be answered publicly by selected experts from the respective ﬁeld. This issue's partner missing data, such as probabilistic approaches like DNV's PRA model or tapping into alternative data sources, is crucial for conducting comprehensive risk evaluations. 4. Black Box Models: Black box models, where it is un- clear why a certain risk is high, present challenges in identifying targeted risk mitigation strategies. It is crucial to ensure a transparent understanding of risk factors and facilitate effective risk mitigation. 5. Understanding Risk Results (Aggregation): Aggre- gating risk results necessitates careful consider- ation, as overlooking nuances in aggregated data may lead to inaccurate risk prioritization. Defining clear Risk acceptance criteria helps avoid oversights in the evaluation process. In what ways does digital transformation en- Q8) hance the effectiveness of integrity management? Rodolphe: In contrast to traditional approaches, dig- ital platforms introduce capabilities that were previ- ously unattainable. They elevate integrity manage- ment across multiple dimensions: • Control: Provide greater control over the integrity of pipelines, empowering operators to stay on top of their priorities. • Accessibility: Offer a single source of truth, mak- ing information and resources easily accessible to all stakeholders, thereby improving transparency and collaboration. • Efficiency: Streamline processes, speed up com- modity tasks and reduce redundant actions, re- sulting in significant time and cost savings across the organization. • Intelligence: Harness advanced data analytics to derive valuable insights, enabling data-driven de- cision-making and predicting future trends and opportunities. • Communication: Enhance internal and external communication through integrated tools and reg- ular updates, fostering better collaboration and in- formation sharing. • Judgment: Enable better-informed decision-mak- ing by providing stakeholders with comprehen- sive data and analysis, allowing for more accurate and well-considered judgments.

68 Pipeline Technology Journal - 1/2024 company directory Company Directory Association Construction Automation Construction Machinery Certification Engineering Coating visit www.pipeline-journal.net/company-directory for more details

Inspection G R O U P Integrity Management Pipeline Technology Journal - 1/2024 company directory 69 Leak Detection Pump and Compressor Stations Qualification & Recruitment Repair G R O U P visit www.pipeline-journal.net/company-directory for more details

70 Pipeline Technology Journal - 1/2024 company directory Materials Safety Monitoring G R O U P Signage Operators Trenchless Technologies Research & Development visit www.pipeline-journal.net/company-directory for more details

Cover

Preface

Table of Content

Editorial Board

ptj Insights - Defects in Pipelines and their Assessment

The Challenge of an All-In-One Inspection - First Results and Benefits

Small Diameter Pipeline Inspection

Robust Ultrasonic Transducers for Pipeline Inspection

How to see what cannot be seen within a Disastrous, Highly Corroded Subsea Gas Pipeline during Repair and Pre- Commissioning Process

In-pipe Ultrasonic Inspections of Mud and Tailing Lines: how to manage difficult to remove Scaling, provide quality and accurate Defect Assessments of steel and HDPE

Ask the Experts

Company Directory