1/2023 Offshore & Subsea Technologies Innovation Brings Pipeline Back to Normal Intelligent Solutions for Inspection of Challenging Pipelines An Innovative Approach to Optimize Trunkline Cladding Requirements Offshore pipelines and stability assessment of submerged slopes Numerical prediction of material properties and structural response of JCO-E offshore pipes Repurposing Hydro carbon Pipelines to Transport CO2 10th Anniversary of the ptj www.pipeline-journal.net e-ISSN 2196-4300 / p-ISSN 2751-1189
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Pipeline Technology Journal - 1/2023 editorial Mohd Nazmi bin Mohd Ali Napiah Custodian/Head/GTA (Pipeline) Engineering Department, Group Technical Solutions Project Delivery & Technology Division PETRONAS Offshore Pipeline & Subsea Technologies Apart from typical technical and operational challenges of onshore pipelines i.e. 3rd party, corrosions, geohazards; offshore pipelines and subsea facilities have additional challenges i.e. logistics and weather-related, ultra-high pres- sure/temperature for ultra-deep/deep water. Thus, that’s the reason why the front-end loading (FEL)/design stages are very crucial for offshore pipelines and subsea systems so that all challenges/issues are taken into consideration that the pipelines and subsea facilities can be operated and maintained with utmost reliability and integrity. Not to mention that comparatively higher cost of installation/construction, hook-up, pre-commissioning, commissioning and abandonment for offshore pipelines and sub- sea facilities require continuous innovations and emerging tech- nologies so to maintain that any greenfield and brownfield project/ development will be feasible throughout its entire operating life. Having said, the role of Industrial Revolution 4.0 (IR4.0) could be the ‘game changer’ in the offshore field development that also include pipelines and subsea technologies. The IR4.0 elements of robotic, automation, sensors/IOTs, data analytics, advance material and ad- vance engineering will help O&G companies or operators reduce or optimise the project/development and operation and maintenance (O&M) cost. For instance, the use of innovative pipeline joining method of mechanical interference fit connector has been used in PETRONAS and several other companies to replace conventional welding method; and the method could provide similar reliability and integrity as required by common pipeline codes and standards. The other example would be the use of fully autonomous robotic in- line inspection to inspect the condition of O&G pipelines that could provide a cost-optimization alternative. It needs to be noted that cur- rent available technologies including the innovations from IR4.0 have their limitations and operating boundaries; and it is believed that there are innovators out there that continuously challenging the status-quo so that we, the O&G companies and its stakeholders could reap the benefits of any emerging and pacing technologies, moving forward. Your sincerely, Mohd Nazmi bin Mohd Ali Napiah Custodian/Head/GTA (Pipeline) Engineering Department, Group Technical Solutions Project Delivery & Technology Division PETRONAS
Pipeline Technology Journal - 1/2023 This Issue’s COMPLETE CONTENT 10 Innovation Brings Pipeline Back to Normal R.G. Lie 18 26 Intelligent Solutions for In- spection of Challenging Pipe- lines- Case Study: 10” Rigid Offshore Oil Riser Inspection for Wall Thickness and Cracks A. Enters, T. S. Kristiansen, U. Schneider An Innovative Approach to Optimize Trunkline Cladding Requirements for an Offshore Gas Field Development Q. Saleem, R. Al-Shiban, M. Al-Mansour, L.Seong Teh Pipeline Technology Journal - ptj www.pipeline-journal.net # @pipelinejournal #pipelinejournal
Pipeline Technology Journal - 1/2023 32 42 Offshore pipelines and stability assessment of submerged slopes under seismic conditions P. N. Psarropoulos, Y. Tsompanakis, N. Makrakis Numerical prediction of mate- rial properties and structural response of JCO-E offshore pipes A. Stamou, I. Gavriilidis, C. Palagas, E. Dourdounis, N. Voudouris, A. Tazedakis, S. A. Karamanos1 50 Repurposing Hydrocarbon Pipelines to Transport CO2: PETRONAS' Study F. Aziz, K. A. Karim, Ir. H. Hussien Company Directory Page 62 60 Ask the Experts
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Pipeline Technology Journal - 1/2023 9 ptc 2023 promotes the development of young talent in the pipeline industry The 18th Pipeline Technology Conference (ptc) is set to take place in Berlin from May 8-11, 2023. Europe's premier address for pipeline industry professionals will offer a look into the pipeline future, with a broad range of 1-day seminars, panel discussions, technical sessions, operator round-tables, award ceremonies and social events. ptc 2023 will bring together the industry elite – pipeline opera- tors, industry leaders, experts, and young talent – to discuss the latest developments and advancements in pipeline technology. Key topics for 2023 will include hydrogen, methane emissions, safety & security, climate adaption, geo-hazards, CO2 transpor- tation and a regional focus on the booming African continent. The gathering will also offer a multitude of technical presenta- tions, including 6 concurrent technical tracks with more than 120 speakers. Participants will have an opportunity to learn from industry experts, network with peers, and form first-hand im- pressions of the latest trends and developments in the interna- tional pipeline industry. All papers will again be published on an open access basis. Indeed, a special focus will again be devoted to the area of pro- moting young talent. ptc 2023 will feature a variety of opportu- nities for young people to get involved into the organization of the event and it will host different awards ceremonies for both students and young professionals. The EITEP Institute is com- mitted to fostering the next generation of pipeline professionals and cooperates with different young pipeline professional com- munities from around the world. The exhibition will showcase the latest products and services from leading pipeline operators and service companies. More than 85% of the exhibition stands are already booked. Read more pipeline news: www.pipeline-journal.net
10 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Innovation Brings Pipeline Back to Normal Bespoke Technology Solutions Free Stuck Pig and Enable Valve Replacement, Allowing Production to Resume R. G. Lie > T.D.Williamson Abstract Before the operator of a gas export pipeline offshore Asia could isolate the line and replace leaking pig trap valves on their platform and per- form in-line inspection (ILI), they had to remove a serious obstacle: a cleaning pig that had stalled just beyond the pig launcher. Because there is no standard tool for recovering a stalled pig, at least not without blowing down the pipeline, the operator contracted T.D. Williamson (TDW), who engineered, tested and deployed a bespoke re- covery tool. The pig was removed in an operation that resulted in only five hours of downtime. TDW then used in-line technology to isolate the pipeline and create a safe work zone for the valve replacement. TDW also developed a cus- tomized cleaning pig and a progressive pigging program to ensure the pipeline was sufficiently clean for both normal operation and ILI.
1. Introduction Day in and day out, year after year, technology keeps up its end of the pipeline integrity bargain, enabling safe and efficient operation. Valves open and close effortlessly, cleaning pigs dispatch wax, water and contaminants, and the sensors of in-line inspection tools capture real-time data about cracks, dents and other anomalies. It all works like a well-oiled machine. Of course, nothing in this world is infallible, and the occasional technical hiccup is not uncommon. In most cases, though, these problems can be resolved rela- tively quickly and with customary intervention. But when a third-party service provider launched a 28-inch, bi-directional cleaning pig into a gas ex- port line offshore Asia, they experienced more than a simple “technical hiccup.” Their pig stalled just be- yond the launcher isolation valve, stopping halfway into the barred production tee that prevents the pig from traveling down a branch connection. Although the pipeline wasn’t completely obstructed, running a pipeline with a pig stopped inside is hardly a realis- tic operating scenario, even in the short term. In fact, the operator was rightly concerned that pressure and flow around the pig could eventually make a bad thing even worse, pushing the pig in far enough to block the pipeline entirely and shut down production. Because there’s no plug-and-play solution for a stalled pipeline pig — at least not without blowing down the Figure 1: Bi-directional pig stuck in the barred production tee. Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 11 entire pipeline, a financially and environmentally costly process — it would take engineered-to-order technology to recover the pig. And that would be just the first step to bring production back to normal. 2. Avoiding Shutdown Regular pigging activities are essential to integrity management. For gas export pipelines (GEP), though, the need is amplified. GEPs transport the entire pro- duction between the offshore field and the onshore processing terminal — in this case, hundreds of mil- lions of standard cubic feet (MMSCF) per day. If an- ything causes the pipeline to go offline, the revenue stream dries up. That’s an enormous risk no operator wants to take. To avoid the possibility of shutdown, GEP operators run cleaning pigs daily, weekly or monthly, depending on production conditions. Pigging requires fully func- tional and well-maintained pipeline components at both the launching and receiving end of the pipeline, including pig traps, pig trap valves, and emergency shut down valves (ESDV). If any of them malfunction it can make pigging very difficult, if not impossible. In this case, two pig trap valves located on the platform were not sealing completely, causing pressure buildup of the pig launcher during service and preventing reg- ular pigging from being carried out. The operator had planned for their replacement and T.D. Williamson (TDW) was scheduled to deploy its in-line SmartPlug® isolation technology to create a safe offshore work zone while the pipeline remained in service. Obviously, though, TDW couldn’t launch the SmartPlug tool with a pig in the way. With one challenge stacked on top of another, the oper- ator needed to take action to make the pipeline pigga- ble. That would allow them to resume normal pigging operations and perform a long overdue in-line inspec- tion to check the pipeline’s integrity. They turned the entire project over to TDW, whose multi-phase re- sponse began with the development of a bespoke pig recovery tool.
12 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Ultimately, TDW • Created and deployed a specially designed tool to recover the stalled pig by pulling it back to the launcher. • Isolated the offshore section with SmartPlug® technology so the operator could replace the leak- ing valves, restore the integrity of the gas export line at the platform, and safely resume normal production. • Developed a tailor-made cleaning pig and progres- sive pigging plan to prepare the pipeline for the in- telligent pig run. But before they could do any of that, TDW had to fig- ure out why the other provider’s pig stalled in the first place. 3. Hanging in the Balance Pigging service providers know that a pig can stall dur- ing operation when a considerable amount of debris collects in front of it. To prevent this, they build “by- pass” into the pig by drilling holes into the body or discs. Bypass allows product to flow through and ahead of the pig as it travels through the pipeline, creating turbu- lence that flushes the debris or holds it in suspension. Designing a pig with bypass requires striking a bal- ance. Too little bypass and the pig won’t create enough turbulent flow. Too much bypass and there won’t be enough differential pressure behind the pig to drive it forward. Most of the time, engineers find the middle ground. Unfortunately, in this case, the usual yin and yang of pig bypass design was slightly off. The (somewhat ironic) result: The bypass became the obstruction. TDW engineers discovered that the pigging service provider had modified their bi-directional pig to allow a relatively large portion of gas to flow through it. On the face of it, this was not necessarily a negative: It was intended to allow for optimal turbulence ahead of the pig. However, because of the pig’s heavy polyurethane (PU) disc stack-up, more differential pressure was required to move it compared to a conventional bi-directional pig. The imbalance was evident almost as soon as the pig was launched. Once the pig entered the barred produc- tion tee, the combination of large bypass and high dif- ferential pressure created even more bypass around the perimeter of the discs. This meant there was no longer enough differential pressure to push the pig through the tee. When a portion of the front disc pack- age partly disengaged, creating even more bypass, in- sufficient drive on the discs caused the pig to stall. 4. Considering the Alternatives With so much on the line in terms of both integrity management and throughput, the operator wasted no time considering various recovery strategies. It seemed like it might be possible to use another bi-di- rectional pig to push the stalled pig back to the on- shore receiver. However, this would increase the risk of the pig getting stuck farther into the pipeline. For example, if it became caught in one of the many bends in the subsea tie-in spool connection between the sub- sea pipeline and platform riser, a challenging subsea rescue would be required. That left the project team with only one viable alter- native: pulling the stalled bidirectional pig back to the launcher. While this would eliminate the risks associ- ated with pushing the pig to the receiver, it was still no quick or simple fix. There’s no standard rescue equip- ment to do the job. Figure 2: Lance with support and wheel assembly attached to gripping tool.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 13 Instead, TDW engineered, designed, manufactured and tested an application-specific recovery tool at its Global Solutions Center in Stavanger, Norway. 5. First Things First Engineers envisioned the pulling tool being a wire and hydraulic cylinder that would attach to a strong hold in the pig body on one end and a strong hold behind the launcher on the other. • which was closest to the launcher, did not. When a hydraulic cylinder was used to push the pig from the test rig, every disc flipped but they were par- tially torn due to high stress and rear disc pack damage. Finally, during the third recovery test, the first of the four polyurethane discs stretched over the next three, reducing friction. All four discs flipped at a recovery force of 13 tons without touching the pipeline wall or becoming damaged. One of the earliest steps in the tool design process was determining how much recovery force would be required to pull the pig back safely and successfully. The calculation was complicated by the fact that dur- ing pigging, the pig’s polyurethane sealing discs fold backwards. To reverse the pig out of the pipeline would require enough pressure to flip and fold the discs in the opposite direction. If the discs failed to flip, the pig would remain stuck, unless an extreme force was ex- erted upon it, with potentially catastrophic results. To conduct recovery force testing, TDW built a replica of the offshore pipeline launcher, including the barred production tee. To make the replica as authentic as possible, TDW also acquired a pig from the operator that was identical to one stalled in the pipeline. Each test provided a better understanding of how to achieve a successful recovery. • For the first test, technicians loaded the opera- tor’s pig into a straight section of the replica pipe- line that was pressurized to the expected offshore level of approximately 3 bar (43 psi) then propelled it using water as the pigging medium. Once again, this pig stalled when it entered the barred tee. At a recovery force of 3.5 bar to 4 bar (50.7 psi to 58 psi) the discs partially burst instead of flipping, the pig didn’t move and there was water leakage across the outer disc parameter. • After inspecting the front disc pack, technicians repressurized the test pipe to 3.5 bar to 4 bar (50.7 psi to 58 psi) then reloaded and relaunched the pig. This time it moved a short distance before stall- ing — about a meter, or 3.2 feet — and water once again leaked across the disc perimeter. However, the front seal disc pack flipped; the rear disc pack, With the optimal recovery force a known quantity, TDW engineers could move beyond their vision to a fully realized design. 6. Building on the Strong Points Engineering a tool to pull a pig out of a pipeline in- volves making countless decisions, not the least of which is figuring out what part of the pig the recovery tool will grasp and how it will grip it. After all, unless the tool has a firm hold on the pig, there’s no way any- thing will budge. The TDW team agreed that the strongest gripping points for the recovery tool were the bypass holes, meaning the same elements that had contributed in this case to the pig stalling in the first place would be integral to the recovery process. As for the tool itself, engineers designed it so spring- loaded pulling arms would engage or click in place in- side the bypass holes then a locking mechanism lance would install the recovery tool onto the pig body. The tool configuration also included: • Lance support wheel assemblies to centralize the locking lance in the pipe. • A pulling wire arrangement. • A hydraulic pulling cylinder furnished by TDW that included a “strong hold” anchor point ar- rangement supplied by the operator. TDW also decided to use the pinger receptacle inside the stalled pig as a guidepost for inserting the grip- ping tool into the bypass holes. And to overcome poor
14 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY visibility inside the pipeline, they incorporated a cam- era system into the recovery tool. This would help tech- nicians “see” when the gripping tool successfully en- gaged inside the pig every hour the pipeline would be shut down for the re- covery costing the operator valuable production, this test provided ample confidence that the pig could be rescued on an acceptable timeline. 7. Tested: Technology and Timelines In fact, once onsite, it took only five hours for TDW crews to: Engineers returned to the test rig, this time with the manufactured recovery tool in hand. Their goal was to assess the performance and efficacy of the entire tool, down to estimating how long the onsite procedure would take. Figures 3-4: Recovery operation offshore. TDW performed the recovery test using the opera- tor-furnished bidirectional pig, now equipped with new discs. The engineering team monitored the amount of force required for the recovery tool to over- come inertia — the maximum encountered pulling force on the pig was measured at 15.4 tons or 360 bar (5221 psi) of hydraulic pressure in the pulling cylinder — and visually inspected the recovery tool and pig body post-test to ensure integrity. The dry run also enabled TDW to optimize procedures and to record the time it took to assemble the lance, engage the tool and re- trieve the pig under nearly real-world conditions. With • Open the quick-opening closure on the launcher. • Assemble the lance and gripping tool and insert them into the pipeline. • Lock the pig gripping tools into the pig bypass holes. • Hook up the pulling wire. • Begin the recovery operation. • Retrieve the pig from the launcher. All the planning, preparation and innovation had paid off. Now, with an obstacle literally no longer in their way, the SmartPlug team could take the project reins and prepare the line for valve replacement. 8. Creating a Safe Work Zone Over time, normal wear and tear can take a toll on valves’ internal seals and seat rings, causing them to leak. As a result, valve repair or replacement is consid- ered somewhat routine. But before any repair or replacement project can take place, operators first have to choose how they’ll cre- ate a hydrocarbon-free work zone. The options are to depressurize the entire line or isolate just the affected section, which is done either by hot tapping and plug- ging or by using in-line technology. Considering the enormous product volumes that gas export lines transport, it’s no wonder operators try to avoid depressurizing them. A prolonged shutdown can run into the millions of dollars and require flar- ing off several hundred million cubic feet of gas, which is highly undesirable, especially when the world is watching its emissions. In this case, around 300 MMSCFS of inventory loss would incur if the pipeline
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 15 was depressurized and, compared to in-line isolation, it would take an additional six or seven turnaround days, including the time involved to re-pressurize the pipeline. consequence used to determine risk (risk = probabil- ity x consequence). More than 60 action items were identified for risk mitigation. Selecting the TDW SmartPlug in-line isolation system Figure 5: SmartPlug® isolation tool. helped the operator avoid those losses. Bidirectionally piggable, SmartPlug technology is intro- duced into the pipeline via the pig launcher then pro- pelled by pipeline product or pumps and compressors to the isolation point, where it is remotely activated. Internal hydraulics engage the gripping elements and the sealing element on the pipe wall then downstream pressure is reduced to create differential pressure across each plugging module, maintaining a fail-safe isolation. 9. Nothing Left to Chance Safety is always a top priority during pipeline isola- tions. Personnel injuries, loss of life or asset damage are all unacceptable. Before any SmartPlug operation, it’s standard prac- tice and a DNV Type Approval requirement to collect technical information about the pipeline and to pre- pare engineering documents, including design prem- ises, pipe stress calculations, isolation operation pro- cedures and a piggability study that assesses the tool’s ability to negotiate the pipeline safely and be retrieved from it. Following factory acceptance testing in Stavanger, TDW mobilized the SmartPlug tool to the worksite. Technicians lifted and loaded the tool into the pig trap then used a treated seawater pumping service to pig it 47 meters (154 feet) to the predetermined location. A safe isolation was established against the shut-in pres- sure of approximately 110 bar (1595 psi). Monitoring the annulus pressure between the two plug modules for four hours verified each was sealing properly. That gave the operator and project team the confidence they needed to begin the valve replacement. Figure 6: Loading the SmartPlug into the launcher. After a leak test verified the integrity of the new seal rings and valves, TDW equalized the pressure differen- tial across the SmartPlug tool, unset the plug modules and pigged the tool back to the launcher using pipe- line gas pressure. Figure 7: Retrieval of the SmartPlug tool from the launcher barrel. To ensure the risk management of this project, TDW conducted hazard identification (HAZID) and hazard and operability analysis (HAZOP) studies. Engineers identified and uploaded potential areas of risk into a risk matrix, with probability of occurrence and With the stalled pig removed from the pipeline and the pig trap valves replaced, just one step remained in this multi-faceted project: making sure the operator could put the stuck pig incident firmly behind them forever.
16 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 10. Custom Cleanliness Reduces Risk While an unusual confluence of technical difficul- ties led to the stalled pig, the operational and finan- cial implications were just too great to risk a repeat occurrence. Figure 8: First Vantage pig at launcher To minimize the possibility of the scenario happening again, TDW developed a customized cleaning pig to fit the requirements of the offshore pipeline system. Based on the proven technology of the VANTAGE® multipurpose cleaning pig, the bespoke pig incorpo- rated adjustable bypass, with jetting nozzles to pre- vent debris from building up during operation. TDW further boosted its cleaning capabilities by adding spring-loaded, angled polyurethane blades. Because the blades also cause the pig to rotate while it trav- els through the pipeline, the pigging discs experience more uniform wear, meaning they require only rou- tine maintenance. TDW also designed a progressive pigging program – with the customized pig at the centerpiece – to ensure the offshore section of the GEP was sufficiently clean for both normal operation and an upcoming in-line in- spection (ILI). If any dirt or debris interferes with ILI tool sensors contacting the interior pipe wall, the data they return can be inaccurate or incomplete. In progressive pigging, cleaning begins with a less ag- gressive pig then works its way up. Because this pipe- line had not been pigged in more than two years and the last run had returned significant amounts of de- bris, the progressive pigging program was particularly conservative: if any single pig run removed too much debris, it would increase the risk of the pig stalling. After five runs, the pigging program met the operator’s cleanliness specifications. The operator resumed nor- mal production and normal pigging, with fully func- tional valves and sound pipeline components. Like every other aspect of modern life, technology plays a major role in the everyday operation of the world’s pipelines. It’s reassuring to know that when technical problems occur, innovative, customized tools and techniques can be put into place to solve them. In other words, while we all know technology can save time, money and other assets, there are times it can also save other technology. Author Rolf Gunnar Lie T.D. Williamson Director Sales, Eastern Hemisphere, East Rolf.Gunnar.Lie@tdwilliamson.com
18 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Intelligent Solutions for Inspection of Challenging Pipelines- Case Study: 10” Rigid Offshore Oil Riser Inspection for Wall Thickness and Cracks A. Enters, T. S. Kristiansen, U. Schneider > ROSEN Norway Abstract Since the introduction of in-line inspection tools (ILI) more than 50 years ago, there have always been pipelines that were considered unpiggable. Typically, it is a combination of various circumstances relating to pipeline design, operating conditions, and/or characteristics of the medium that prevents a success- ful in-line inspection using traditional methods. Today however, solutions are available which allow the internal inspection of pipelines formerly deemed “unpiggable”. Special ILI tools can inspect these challenging or difficult to inspect pipelines. The system introduced here is capable to measure crack depth and profile quantitatively, whereby data is collected on the way in and out, and results are visible in real time. Tethered technologies are capable of inspecting pipelines with a 6" or larger diameter, and up to 24 km in length. This paper will explain the technologies used and the specifica- tions achieved. Furthermore, the unique ability of the system to navigate complex pipeline geometry will be explained through a case study of a 10" offshore oil riser. During this inspection, the tethered tool safely negotiated a total accumulated bend angle of 1,188° (17 bends) whilst successfully inspecting the pipeline for wall thickness and cracks.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 19 1. Introduction The pipeline network world worldwide is ageing, there- fore, it needs to be maintained and its integrity as- sessed. This is done since more than 50 years with so- called in-line inspection tools or inspection pigs (ILI) for different kind of defects. However, there have al- ways been pipelines that were considered unpiggable. Typically, it is a combination of various circumstances relating to pipeline design, operating conditions, and/ or characteristics of the medium that prevents a suc- cessful in-line inspection using traditional methods. However, often there are solutions possible with very special ILI tools for these challenging pipelines. The system introduced here is capable to measure crack depth and profile quantitatively, whereby data is collected on the way in and out, and results are visible in real time. Tethered technologies are capable of in- specting pipelines with a 6" or larger diameter, and up to 24 km in length. • One or two crawlers/tractors in the front – depend- ing on the pull forces required – will pull the com- plete tool into the pipeline and push it back on the return run. • The pulling/pushing modules are followed by pro- ject-specific modules: ◊ For UT geometry and wall thickness with pulse echo vertical beam technology, ◊ For geometrical anomalies as dents, ovalities and further restrictions, and for metal loss and wall thickness defects as pittings, all kind of metal loss, wall thinning and lamination, ◊ For crack detection with shear wave technology, ◊ And/or for crack detection and seizing with TOFD (Time of Flight Diffraction), ◊ For corrosion inspection with eddy current 2. Principle of Tethered Tool technologies. Although the TUM, which stands for Tethered Ultrasonic Measurement, is typically tailor-made for a special project, the typical composition consists of the following: • Modules for data storage are also part of the tool train. • If the tool is inspecting a pipeline within a clear product as water or naphtha, a camera can also be Figure 1: TUM principle
20 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 2: Conventional ILI tool Figure 3: TUM module installed in the front of the tool. • For very special tasks even a grinding tool was added for grinding out internal girth weld pene- trations and internal cracks. • The tool is connected via a cable coming from a winch with the control unit. The cable has four functions: to bring the energy to the tool (the tool does not have a battery pack), to transfer the data in real time to the control unit, to control the movement of the crawler, and last but not least as a safety line. If the crawler cannot move anymore and the tool would get stuck, it can be pulled back with up to, for example, 2 tons. The main differences between a conventional, free-swimming, unidirectional pumped tool and a tethered bi-directional self-propelled tool are the fol- lowing: Conventional tools go from A to B and get their driving pressure via its cups and/or discs. The sensor carrier is typically flexible. The ROSEN TUM tool has no cups or discs and a lot of bypass. It is extremely lightweight, made of titanium and runs on wheels. The sensor carrier is a stiff ring. The main purpose of the lightweight tool and wheels is to require only very little pulling forces and almost no friction in order to be able to inspect longer sections even through many bends. Another differentiation against conventional tools is that we need big winches to do the job. The picture shows winches for different lengths, so far successfully completed up to 12 km, up to 24 km possible depending on the amount of bends, bend angles and pipeline con- figuration (two- or three-dimensional). A series of different crawlers and tractors are available for all diameters and forces up to 500 kg pulling force each; 6" to 48" has been done already, up to 56" can be easily prepared. The technologies used as ultrasonic pulse echo in liquid lines for geometry, wall thickness and crack detection, ultrasonic pitch and catch TOFD for crack detection, as well as seizing and eddy current technologies for corrosion/metal loss in dry/gas pipe- lines were all explained many times before. Therefore, we will start straight with the case study. Figure 4 and 5: Winches of different lengths
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 21 Figure 6 and 7: Crawler and tractor 3. CaseStudy: 10" Rigid Offshore Oil Riser Inspection for Wall Thickness and Cracks The picture above shows a typical challenging pipe- line – a riser from platform to subsea – which makes the use of a conventional tool extremely expensive, be- cause the pig receiver would need to be fabricated and installed subsea. Thus, the pipeline inspection would have to be operated with the assistance of a diving sup- port vessel. However, there was a better solution. It is much easier and cheaper to use the ROSEN TUM tethered self-propelled bi-directional UT tool which can perform geometry, wall thickness and crack in- spection in one go. This tool can be launched and re- ceived from a trap at that platform without the need for a diving support vessel and a subsea trap, making it the right choice for this project. The above-mentioned pipeline was chosen by the operator during a risk assessment of all unpiggable pipelines they had at this platform. After the assess- ment, it was categorized as high risk for the operation. Therefore, an inspection solution needed to be devel- oped. Different vendors were invited, however, the ROSEN solution was chosen for further validation. The special challenge with this pipeline was the amount of bends (and the total angle). If somebody would like to try for themselves how the required pulling forces increase when pulling a thick cable or a garden hose through a combination of bends, they will notice that every additional bend adds friction. Therefore, the amount and angle of bends are in most cases the lim- iting factor for a tethered inspection. Other vendors can typically handle between three and four 90° bends. During the first discussions, the target was to inspect a section of nearly 200 m including up to eleven 90° bends and as well as two 2.4° vertical miter bends. Figure 8: Offshore platform Figure 9: Platform with riser Figure 10: Challenging offshore riser with many bends
22 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY For this riser inspection, the main issue was the pull- back force of the tool. In case a tethered crawler tool is losing power, the tool needs to be pulled back via the winch. The pulling force of the 10" tractors are approximately 200 kg each and not the limiting factor for the inspec- tion of this riser. In order to confirm that the passage and retrieval through eleven 90° bends is feasible, a tool was devel- oped and tested successfully in a test loop in our facil- ity in Bergen, Norway. The main purpose of the tests was to demonstrate that the tool could be retrieved by the umbilical. Based on the friction profile from the test loop (the pullback forces as function of tool position in the loop), we could correlate the figures with the riser configura- tion. This way, we were able to obtain a figure for the required pullback forces in case the tool lost power within the riser system. After extensive testing, the in- spection with UT wall thickness and TOFD for cracks was conducted successfully and showed good results. Figure 12: Riser test Here are some pipeline details: • Nom. OD 10.75", length ~17km • Inspection length >300m • Max. depth ~150m • Wall thickness 16-18 mm 4. The Reinspection Project • Medium during production/inspection: crude oil/ diesel A few years later, our company received the contract for re-inspection. This time, the challenge was to crawl a bit further (+130 m total length >300 m) into the hori- zontal subsea section including another six bends. • No flow rate during inspection Again, there has been done a lot of crawler testing prior to mobilization at the ROSEN Norway premises Figure 11: Test loop in Bergen
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 23 in Bergen, including measuring: • • Pull and pullback forces with different tandem crawler configurations in water filled pipe. Pull and pullback forces for eight different tool train configurations in water filled pipe. Finally, equipment and team were mobilized, and a temporary trap was installed with stuffing box (cable penetration) as well as guide wheels for routing the cable. Further, the winch was placed, the computer equipment was positioned in a habitat and the func- tion tests were done. A special stuffing box with cable feeder and hydraulic seal closing clamp was designed, manufactured and tested to 100 bars for these inspec- tions. The cable feeder was designed in order to reduce cable friction at the stuffing box location and the hy- draulic seal closing clamp was made in order to make the stuffing box “water tight” in case of a sudden pres- sure surge in the pipeline. The winch used had a 1.2 km umbilical with breaking load of 2,000 kg and nor- mal pulling force of 1,000 kg. The winch was certified for ATEX zone 2. Two different tool train configurations were used: 1) For wall thickness measurements and sonar (UTWM + Sonar) 2) For wall thickness measurements and time-of- flight crack measurement of the corroded areas (UTWM + TOFD) Figure 13: Trap door with stuffing box and cable feeder pulling force to ensure that the tool can negotiate through difficult to pass pipeline components like slippery valves, tees etc. An ultrasonic sensor carrier with 160 UT probes was used along with two odome- ters measuring the travelled distance and tool veloc- ity. The movement of the odometers triggers the data collection. Therefore, if the tool train stands still, data is not col- lected. However, the inspection can be carried out with only one odometer working. Moreover, a pur- pose-made scanner equipped with TOFD probes is used to scan any features. Straight beam PE probes are installed to position the scanner correctly against girth welds to be assessed. When deploying TOFD sensors at corroded features in parent material, the TUM-WT tool position will be used to determine correct positioning of the TOFD tool. In order to see a blocked pipeline (closed valve or simi- lar), a sonar was mounted in the front of the tool. Sonar is used as a method for locating objects in space and under water by means of emitted sound pulses. Two electrical crawlers were run in tandem configuration. This configuration has been designed for increased Finally, the pipeline was shut down, the tool made its way into the pipeline for approximately 300 m collect- ing wall thickness data on the forward and return run. After that, the tool was modified from TUM-Sonar to TUM-TOFD configuration, tested and re-launched again. Figure 14: Inspection tool train – TUM-WT-Sonar, the tool with WT + TOFD had one module more
24 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 15: Experts control tool movement and recorded data During the run many pull- and pull-back force meas- urements were done on preselected distance in order to calculate the friction coefficient of the riser and to be sure to be able to return in even the worst case. Furthermore, during testing and the actual inspec- tion activities, two operators were on deck operating the umbilical winch, tool train and umbilical etc. and two operators in the habitat were in charge or operat- ing the computers: Propulsion & UT/Sonar. During the second run, the tool stopped at some pre-selected girth welds to make full circumferential TOFD scans. Scans were also conducted in any areas that appeared con- spicuous (like splash zones) from the wall thickness data collected during the first run. After presenting a site report which typically shows the most severe detected defects, the equipment and the team were demobilized and the detailed analysis could be started. The data evaluation team were now able to work with four data sets for wall thickness (two times forward and two return runs) and two data sets for the TOFD crack analysis. The full length and cir- cumference of the targeted pipe section was success- fully inspected and the collected data were of very good quality, meeting the required specification. 5. Summary and Benefits As a result of a risk assessment of some offshore un- piggable pipelines, the riser has been categorized as ‘high risk’ for the operation. Therefore, an inspection solution needed to be developed. Different vendors were invited, the ROSEN tethered solution was cho- sen for further validation. Extensive testing (especially crawler testing) in a test loop was performed already prior to the first inspection. The successful inspec- tion was repeated some years later with longer inspec- tion distance and more bends to pass (record of totally 1,188°), 17 bends in total. The benefits of the tethered solution were the following: • The tethered approach avoided the need for sub- sea launching and associated cost, risk and pro- duction downtime. • The unique flexibility of the tethered system al- lowed for the safe negotiation of complex bend configuration (total accumulated bend angle of 1,188° where others are restricted to maximum three and four times 90°) • A tethered system allowed for in-line TOFD inspec- tion, which enhanced the accuracy of WT readings and additionally provided crack inspection. The final report was delivered and the service was performed to the full satisfaction of the operator, on schedule and without any incidents or accidents. Highly accurate UT and TOFD data allowed for a fit- ness-for-purpose evaluation, specific decision making and the continued safe operation of the riser.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 25 Authors Abco Enters ROSEN Norway Senior Sales Manager email@example.com Thor Ståle Kristiansen ROSEN Norway Managing Director firstname.lastname@example.org Ulrich Schneider ROSEN Norway Business Development Manager Region World-Wide email@example.com
26 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY An Innovative Approach to Optimize Trunkline Cladding Requirements for an Offshore Gas Field Development Q. Saleem, R. Al-Shiban, M. Al-Mansour, L. Seong Teh > Saudi Aramco Abstract Subsea pipelines such as flowlines, trunklines etc. are an integral part of all off- shore field developments. Sour service conditions as encountered by production pipelines of gas fields require CRA clad pipe due to high risk of localized corrosion initiation and penetration rate in carbon steel. This paper presents an innovative approach to optimize cladding requirements of trunklines of an offshore gas field development. This approach involves removal of concrete coating from flowlines as well as from cladded section of trunklines for enhancing fluid cooling. The cladding length of each subsea trunkline was significantly reduced as compared to concrete coated case. The impact of removal of concrete coating on other disciplines required minor modifications which were outweighed by the reduction in trunkline clad- ding. The proposed approach was successfully applied to reduce cladding length of two subsea trunklines by more than 70% which resulted in significant cost sav- ings and project schedule improvement.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 27 1. Introduction considering the maximum service temperature. Subsea pipelines such as in-field flowlines, trunklines, test lines etc. are an integral part of all offshore field developments. Sour service conditions as encountered by production pipelines of gas fields require CRA clad pipe due to high risk of localized corrosion initiation and penetration rate in carbon steel. Production fluid is a wet sour natural gas, containing high concentra- tion of carbon dioxide and hydrogen sulphide. Oxygen, sand or bacteria is not envisaged. Liquid formation water production is expected, increasing the bicarbo- nates, TDS and chlorides content of the aqueous phase. Organic acid and their salts formation is expected as well as elemental sulphur. Corrosion simulation indicated accelerated corrosion rates with high pitting risks in the water-wetted car- bon steel pipeline bottom section due to H2S-CO2 cor- rosion. Laboratory testing for top-of-the-line corrosion (TLC) showed that the TLC risk was high for carbon steel [1-6]. As a result, the risks of H2S-CO2 corrosion and TLC should be mitigated by the combination in ef- fective selection of corrosion resistant alloy (CRA) and/ or internally coated carbon steel coupled with corro- sion inhibition batch treatment. In correspondence of the higher temperature sections of the production lines and at trunkline inlet, the integrity of coating sys- tem is doubtful and CRA cladding is used to prevent corrosion. Further downstream, where temperature decreases, coating should provide corrosion mitiga- tion as intended. This is supplemented by batch cor- rosion inhibitor treatment to account for protection of the internal pipeline metal surface that is exposed due to any coating defect and in case of any internal coat- ing integrity issues. Consequently, the in-field flowlines are required to be cladded as they are exposed to high temperature which prohibits the use of internally fusion bonded epoxy (FBE) coated pipe. The production from the offshore gas fields are transported to land via subsea trunklines or export lines which see lower temper- atures than those experienced by in-field flowlines. This allows a major length of the trunkline, seeing low temperature, to be internally FBE coated whereas the remaining length is required to be cladded due to high temperature exposure. Hence, two different types of internal protection are used in one subsea trunkline The means to optimize the cladding requirements of subsea trunklines are very attractive as they can offer significant reduction in project capex costs. This is at- tributed to the fact that the cost of cladded pipe can be three to five times the bare carbon steel depending on the pipe size. On the other hand, the cost of inter- nally FBE coated pipe is only 10-15% higher than that of bare carbon steel option. The other benefits include significant schedule improvement resulting from the clad length reduction and welding time associated with cladded pipe. From operation and integrity man- agement point of view, cladding optimization results in uncomplicated maintenance which leads to reduc- tion in opex costs as well as schedule improvement. Furthermore, the cladding optimization will also re- sult in less environmental impact. 2. Innovative Approach This paper presents an innovative approach to optimize cladding requirements of subsea trunklines of off- shore gas field developments. This approach involves removal of concrete coating from the in-field flow- lines as well as from the cladded section of trunklines for enhancing the fluid cooling. Concrete coating ap- plied to subsea pipelines has low thermal conductivity which prohibits the heat transfer to sea water and sub- sequent temperature drop along the pipeline length. However, the removal of concrete coating can accel- erate the cooling of the fluid resulting in significant temperature drop along a shorter length of the pipe- line which is highly desirable for the optimization of cladding requirements of subsea trunklines. Flow as- surance analyses with and without the concrete coat- ing are required to establish the trunkline temperature profiles to identify the transition point from internal cladding to internal coating. This approach requires re-assessment of subsea pipe- line on-bottom stability [7-11] and protection require- ments due to removal of concrete weight coating. The exclusion of concrete coating may require either in- crease in steel wall thickness or use of alternative stabi- lization measures to meet the requirements of on-bot- tom stability. Furthermore, pipeline protection is required to be ensured under impact scenario resulting from for example due to dropped objects and pull over/
28 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY hooking scenario. In addition, the impact of removal of concrete coating on other mechanical design activi- ties such as free span analysis, bottom roughness anal- ysis, subsea crossings design, pipeline end expansion & spool analyses and in-service buckling assessment is also evaluated. The approach used for optimization of trunkline cladding requirements also requires as- sessing the effect of concrete coating removal on other disciplines including materials, welding, internal cor- rosion, cathodic protection system, pipeline external coatings and field joint coatings. 3. Application of Innovative Approach The proposed approach was successfully applied to re- duce the cladding length of two subsea trunklines of an offshore gas field development as shown in Figure 1. The sour gas from wellhead platforms (WHP) is gathered at two tie-in platforms (TP). From each Tie-In Platform the gas is conveyed to the onshore facility through a dedicated trunkline. For Hydrate preven- tion, a dedicated MEG system is provided and MEG is blended with corrosion inhibitor. For sulphur depo- sition prevention heavy diesel oil (HDO) is injected at each wellhead platform. The innovative approach presented in this paper was applied in two phases. In the first phase, concrete weight coating was removed from in-field flowlines shown in Figure 1. Consequently, flow assurance anal- yses indicated a faster temperature drop along the trunkline length and subsequent significant reduc- tion in cladding length of both trunklines as shown in Table 1. The on-bottom stability analysis as per DNV-RP-F109  of in-field flowlines required increase in steel wall thickness from 16.66mm to 19.05mm to compensate the removal of concrete coating. Furthermore, pipeline protection assessment as per DNV-RP-F107  indi- cated that the increased wall thickness provides higher level of protection than concrete coating. This is attrib- uted to lower permanent dent depth during dropped object impact scenario and higher bending stiffness Figure 1: Layout of Offshore Gas Field and Onshore Facility (WHP: Wellhead Platform, TP: Tie-in Platform)
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 29 Table 1: Cladding Length Reduction from Phase I during anchor dragging scenario. Along flowline corri- dor spool sections, concrete weight coating was main- tained as per the recommendations from dropped ob- ject study. Along closure and tie-in spools, the concrete weight coating was removed since this pipeline section (i.e. externally FBE coated with 19.05mm wall thick- ness) is already stable against environmental loads and buoyancy without the need of additional stabilization weight. As part of cathodic protection system design, re-design of flowline bracelet anodes was required due to removal of concrete coating. In the second phase, concrete weight coating was re- moved from the cladded section of both trunklines shown in Figure 1. Flow assurance analyses showed even faster temperature drop along the trunkline length and subsequent further reduction in cladding length of both trunklines as shown in Table 2. The on-bottom stability analysis as per DNV-RP-F109  of trunklines required increase in steel wall thick- ness from 28.58mm to 31.75mm to compensate the re- moval of concrete coating. Furthermore, pipeline pro- tection assessment as per DNV-RP-F107  indicated that the increased wall thickness provides higher level of protection than concrete coating. This is attributed to lower permanent dent depth during dropped object impact scenario and higher bending stiffness during anchor dragging scenario. Along trunkline corridor spool sections, concrete weight coating was main- tained as per the recommendations from dropped ob- ject study. Along closure and tie-in spools, the concrete weight coating was removed since this pipeline section (i.e. externally FBE coated with 31.75mm wall thick- ness) is already stable against environmental loads and buoyancy without the need of additional stabili- zation weight. Free span analyses of trunklines indicated an increase in allowable free span length in both as-laid (tempo- rary) and operating conditions. The increase in allow- able span length during temporary condition is attrib- uted to increase in steel wall thickness and reduction in total outside diameter. Whereas, the reduction in axial compression along the cladded sections dur- ing operation resulted in higher allowable free span length. On-bottom roughness analyses of trunklines showed significant reduction in intervention works in terms of post-lay mattresses and grout bags. The in- crease in allowable free span length and reduction of pipeline vertical uplift contributed to fewer interven- tion works. Crossing design of trunklines identified re- duction of pre-lay and post-lay intervention works for crossing configurations. Trunkline end expansion analyses showed slight in- crease of end expansion during hydrotest condition due to the reduction of pipe weight from removal of concrete coating. On the other hand, the decrease in end expansion was seen for operating case, which im- plies that reduction in temperature has more domi- nant effect on end expansion than the decrease in pipe weight. Trunkline spool assessment indicated lower spool stress levels for the operating condition whereas Table 2: Cladding Length Reduction from Phase II
30 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY insignificant stress variation was observed for the hy- drotest condition. The removal of concrete coating led to an increase in carbon steel wall thickness, how- ever, it does not have any impact on line pipe manu- facturing, welding and non-destructive testing (NDT). From internal corrosion perspective, the temperature drop in internally coated sections of trunklines helps with potential slight mitigation of the fluid corrosive- ness and potential increase of the corrosion inhibitor efficiency. As part of cathodic protection (CP) system design, re-design of trunkline bracelet anodes for cladded sections was required due to removal of concrete coat- ing. The modifications to anode geometry ensured a smother passage over rollers and inside the tension- ers during installation thereby reducing any risk of slippage or damage. Furthermore, the anode gap was filled with solid PU which ensured further mechani- cal protection to anodes cables and will also increase the anode resistance to slippage force. Following the modifications, anodes can still be preinstalled in coat- ing yard and pass through tensioner and roller with- out any problem. CP system design calculations re- quired anode spacing to be decreased to one anode every three joints. The removal of concrete coating from trunkline clad- ded section has no impact on pipeline external coat- ing which remains the same i.e. fusion bonded epoxy (FBE). Due to the removal of concrete coating, in- creased coating break down factor was considered for the cathodic protection design. The viscoelastic mul- ti-layer coating on the clad section field joint was re- quired to be replaced by FBE field joint coating sys- tem to mitigate any potential coating damage during pipe laying. Furthermore, the FBE coating thickness at the field joint was required to be modified to 625-1125 microns from the standard requirement of 625-1000 microns. 4. Implementation The innovative approach for optimizing the cladding length of subsea trunklines was implemented in com- pany standards and procedures by mandating the methodology presented in this paper to be employed. This ensured that the removal of concrete weight coat- ing (if feasible e.g. by slight increase in wall thickness) is always explored given that it can lead to significant benefits such as cooling of production fluid and con- sequent reduction in costly cladding requirements. Furthermore, it can also increase the pipeline allow- able free span length and can lead to significant re- duction in intervention works required for free span corrections, stress hot spots as well as crossing con- figurations. As a final step, the effect of concrete coat- ing removal on other disciplines including materials, welding, internal corrosion, cathodic protection sys- tem, pipeline external coatings and field joint coat- ings shall also be assessed and approval should be obtained from engineering department. As demon- strated in section 3, the alternative approach for op- timizing the cladding length significantly reduced the final cladding requirements of subsea trunklines which resulted in: • Less environmental impact • Significant cost savings (Capex and Opex) • Schedule improvement • Uncomplicated maintenance • Reduced downtime 5. Concluding Remarks This paper presents an innovative approach to optimize cladding requirements of subsea trunklines of off- shore gas field developments. This approach involves removal of concrete coating from the in-field flowlines as well as from the cladded section of trunklines for enhancing the fluid cooling. As trunklines were re- quired to be cladded only up to the length where fluid temperature was above 120 ºF (and internally FBE coated elsewhere), the cladding length of each sub- sea trunkline was significantly reduced as compared to concrete coated case. The impact of removal of con- crete coating on flow assurance, pipeline mechanical design, cathodic protection and field joint coating sys- tems was also evaluated. Although some of these ac- tivities required minor modifications, however, they were outweighed by the reduction in trunkline clad- ding requirements. The proposed approach was suc- cessfully applied to reduce the cladding length of two subsea trunklines by more than 70% which resulted
in significant cost savings and project schedule im- provement. The innovative approach presented in this paper can be used to significantly reduce the cladding requirements of subsea trunklines of offshore gas field developments. The optimization of trunkline cladding will result in reduction of capex costs as well as sched- ule improvement will lead to early start up. 6. Acknowledgement The authors would like to thank Saudi Aramco man- agement for permission to publish this paper. References 1. Nyborg R. and A. Dugstad, “Top of Line Corrosion and Water Condensation Rates in Wet Gas Pipelines”, Corrosion 2007. 2. Pugh D. V., S. L. Asher and J. Cai, W. J. Sisak, “Top-of-Line Corrosion Mechanism for Sour Wet Gas Pipelines”, Corrosion 2009. 3. Schmitt G., M. Scheepers and G. Siegmund, “Inhibition of The Top- of-The-Line Corrosion Under Stratified Flow”, Corrosion 2001. 4. Gunaltun Y. M., T. Elf and A. Belghazi, “Control of Top of Line Corrosion by Chemical Treatment”, Corrosion 2001. 5. Martin R., “Control of Top-Of-Line Corrosion in A Sour Gas Gathering Pipeline with Corrosion Inhibitors”, Corrosion 2009. 6. Gunaltun, Y. M. and Larrey, D., "Correlation of Cases of Top of Line Corrosion with Calculated Water Condensation Rates", Corrosion/2000, paper # 00071. 7. Andrew C. Palmer, Roger A. King “Subsea Pipeline Engineering,” 2004. 8. EfereboNtubodia, Ibiba Emmanuel Douglas and EzebuchiAkandu “Comparison of On-Bottom Stability of a Subsea Pipeline under Different Wave Spectra and Currents,” American Journal of Engineering Research, 2019. 9. F. Van den Abeele and J. Vande Voorde “Stability of Offshore Pipelines in Close Proximity to the Seabed,” 6th Pipeline Technology Conference, 2011. 10. Qiang Bai and Yong Bai “Subsea Pipeline Design, Analysis, and Installation,” 2014. 11. Scott Draper, Hongwei An, Liang Cheng, David J. White and Terry Griffiths “Stability of subsea pipelines during large storms,” Philos Trans A Math Phys Eng Sci., 2015. 12. DNV-RP-F109 “On-Bottom Stability Design of Submarine Pipelines” Der Norske Veritas, 2010. 13. DNV-RP-F107 “Risk Assessment of Pipeline Protection” Der Norske Veritas, 2010. Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 31 Authors Qasim Saleem Saudi Aramco Engineering Specialist firstname.lastname@example.org Riyadh Al-Shiban Saudi Aramco Engineering Consultant email@example.com Mana Al-Mansour Saudi Aramco Engineering Consultant firstname.lastname@example.org Lay Seong Teh Saudi Aramco Engineering Specialist email@example.com
32 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Offshore Pipelines and stability assessment of Submerged Slopes under Seismic Conditions P. PSARROPOULOS1, Y. TSOMPANAKIS2, N. MAKRAKIS2 > 1National Technical University of Athens, 2Technical University of Crete Abstract Depending on the prevailing bathymetrical and geotechnical conditions, the integ- rity of offshore pipelines is threatened by potential slope instabilities that occur at the seabed or at the bottom of lakes. In addition, submarine slides are more frequent in seismic regions. The instability of onshore slopes under seismic conditions is un- doubtedly a challenging problem in geotechnical earthquake engineering, while the quantitative assessment of the seismic stability of submerged slopes is even more de- manding. Consequently, the current study investigates this complex phenomenon of offshore geotechnical earthquake engineering. After a brief overview of the recent related work of the authors’ group and the available pseudo-static methods of the lit- erature, an improved analytical method is proposed. An indicative parametric study demonstrates that the new approach estimates more accurately the factors of safety, leading thus to less conservative (i.e., more cost-effective) design of offshore pipelines near potentially unstable submarine slopes.
1. Intorduction During the last decades, various offshore structures have been designed and constructed worldwide, while many more are expected to be developed in the near future. Offshore structures can be characterized by rather limited dimensions (e.g., fixed platforms, wind turbines, etc.), while there exist offshore lifelines crossing hundreds of kilometers (i.e., gas pipelines, cables, etc.). Typically, such structures are designed to face various threatsthat depend on the seabed char- acteristics and the potential geohazards of the region (Dean, 2010). The main offshore geohazards are sub- marine slides, faults, strong ground shaking, liquefac- tion, salt diapirs, shallow gas and dissociation of gas hydrates, mud volcanoes and hydrodynamic forces from waves and currents. It is evident that the geo- technical engineers and engineering geologists must identify offshore geohazards with respect to potential triggers, event severity and frequency, potential failure modes and the probability, as well as the consequences of a failure (Randolph&Gourvenec, 2011). In areas that are characterized by moderate to high seismicity, such as the Mediterranean Sea, offshore earthquake-related geohazards may have a negative impact on offshore structures. The prevailing geomor- phological and geological conditions in a specific area (e.g., deep canyons which present slides or rockfalls or flat areas with very soft sediments), in conjunction with active tectonics, may lead to earthquake-related geohazards such as: strong ground motion, seismic fault rupture at the seabed, soil liquefaction phenom- ena, volcanic eruptions, and various types of slope in- stability at the seabed. Submarine slides are common and very effective mechanisms of sediment transfer from the shelf and upper slope to deep-sea basins, in which enormous volumes of sediments can be transported on very gen- tle slopes over distances exceeding tens of kilome- ters. Such events can severely damage various off- shore structures, such as fixed platforms, pipelines and cables. It is well known that due to excess pore pressure the risk of offshore landslides is high, even for slopes with very low inclination, i.e., slope angles ≤ 0.5°(Randolph& Gourvenec, 2011). Potential sources for excess pore pressure are: (a) the shear strain in- duced contraction with pore pressure generation and Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 33 softening during the slide process causing progressive failure and retrogressive sliding, (b) the rapid deposi- tion, (c) increase of the slope angles due to fault rup- ture of seabed erosion, (d) melting of gas hydrates re- leasing methane gas and water, (e) wave loading, (f) earthquake-induced shear strains generating excess pore pressures and (g) human activities such as drill- ing, and construction installation (Locat & Lee, 2002). For example, Kvalstad et al. in 2005 investigated the above phenomena for the case of the Storegga slide which occurred almost eight thousands years ago and affected an area of 90,000 km² (see Figure 1). Figure 1: Location of the Storegga slide offshore Norway (after Kvalstad et al., 2005) Research on understanding the mechanisms and the related risks due to submarine slides has been inten- sified in the past decades, mainly due to the increas- ing number of deep-water oil and gas fields that have been discovered and exploited. The impact of subma- rine slides on offshore pipelines has been thoroughly investigated (Zakeri, 2009).In recent years, elaborate numerical models have been utilized for the simula- tion of landslides (Dey et al. 2016).Moreover, different rheological models have been used to investigate the slide movement in analytical or numerical investiga- tions (Boukpeti et al. 2012). Useful conclusions can be drawn from data that are continuously collected from both recent and older submarine slides worldwide (Camargo et al. 2019). Factor of Safety (FS) against slope stability constitutes a useful engineering tool for structural integrity assess- ment of any structure in the examined region. With respect to seismic slope instability, the horizontal and
34 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY vertical inertial forces that are expected to be devel- oped on the soil mass during a seismic event may de- crease dramatically the factors of safety, leading thus to higher risk of failure (Psarropoulos & Antoniou, 2014). Usually, slope stability assessment is performed via pseudo-static limit equilibrium analyses, which es- timate the factors of safety under seismic conditions based on certain simplifications. Typically, they are based on the assumption that the induced seismic ac- celerations may be represented as equivalent external static forces. This "pseudo-static approach" is popular in engineering practice as it is relatively simple and straightforward to implement. Its similarity to the static limit-equilib- rium analyses usually conducted by geotechnical engi- neers makes computations easy to perform and under- stand. Nevertheless, the accuracy of the pseudo-static approach is governed by the accuracy with which the simple pseudo-static inertial forces represent the com- plex dynamic inertial forces that actually occur dur- ing an earthquake (Kramer, 1996). Despite the progres- sive development of more advanced analytical and/or numerical methods, the use of the pseudo-static ap- proach in seismic slope stability analyses and the in- terpretation of pseudo-static factors of safety are ex- tremely useful for offshore engineering and are used in the design of offshore structures. The current paper tries to shed some light to these cru- cial issues in the field of offshore geotechnical earth- quake engineering, emphasizing on planar slides under seismic conditions. After a brief overview of the recent related work of the authors’ group and a liter- ature review of the available solutions for static and pseudo-static slope stability assessment, an improved analytical expression is proposed for submerged soil slopes. Subsequently, a parametric study has been con- ducted taking into account the main parameters in- volved (i.e., the mechanical properties of the geoma- terials, the geometry of the slope, and the imposed seismic acceleration levels). 2. Offshore Gas Pipelines Subjected to Submarine Landslides depths. Kinematic distress due to submarine geohaz- ards is a critical and frequently unavoidable threat for such pipelines, especially in deep water, where they are laid directly on the seabed under adverse and un- certain conditions. More specifically, submarine land- slides and debris flows consist a critical geohazard for offshore pipelines. The investigation of pipe distress under the above phenomenon can be conducted uti- lizing analytical and/or numerical models. Previous studies of the authors’ group (e.g., Chatzidakis et al., 2019 & Chatzidakis et al., 2020) have focused on ana- lytical models which, although can be inferior in terms of accuracy compared to elaborate numerical models, exhibit the advantages of faster solution, automated calculations and compatibility with a wide range of software, while they can be easily implemented into guidelines and applied in practice. The response of offshore pipelines under lateral dis- tress due to a landslide has been investigated in a lim- ited number of studies so far through the development of analytical and numerical models. Yuan et al. (2012a & 2012b) proposed two analytical models for both sur- face-laid and buried offshore pipelines. These studies assumed bi-linear lateral soil resistance and constant axial tension. In the sequence, Yuan et al. (2015) and Chatzidakis et al. (2019) improved the above method- ology by introducing varying axial tension and tri-lin- ear lateral soil resistance, respectively. As shown in Figure 2, Chatzidakis et al. (2019) devel- oped an analytical methodology for the investigation of pipe response under lateral kinematic distress due to a submarine slide or a debris flow. The investigation focuses on deep water conditions where the pipeline is usually laid directly on the seabed. Extra emphasis is given on the soil resistance, where a tri-linear model is used in compliance with the recent DNV GL (2017) guideline. The proposed model was validated against both analytical and numerical models, based on the fi- nite-element (FE) method. Finally, a parametric study was carried out for different loading scenarios using realistic input data for the pipe and soil properties taken from the design and geotechnical survey of the Trans Adriatic Pipeline project (TAP, 2013a & 2013b). As aforementioned, offshore natural gas pipelines are large-scale infrastructures which may extend for hundreds of kilometers and reach hundreds of meters The main findings of this investigation can be summa- rized as follows:
a) • The difference between simulat- ing tri-linear and bi-linear lateral soil resistance is apparent, since bi-linear soil re- sistance overestimates lateral deflection and underestimates pipe axial strains for small de- flections. Moreover, the proposed model can in- vestigate the response of a pipe for a wider range of axial tensions. The computational cost is small for both models. • Larger drag force and landslide width result in big- ger displacements and in a longer part of the pipe- line that is exposed to lateral movement. b) Figure 2: Analytical model description (a) and soil resistance models (b) However, for constant drag force and increasing landslide width, the laterally dislocated part of the pipeline normalized with respect to the landslide width is constant. • The fact that tensile strains occur along the long- est part of the pipe in all cases, is considered bene- ficial, since such pipelines are vulnerable to com- pressive strains due to local buckling phenomena. Compressive strains appear for small drag forces and especially for small landslide widths; hence, it is recommended to avoid regions with potential narrow landslide areas. • In all examined cases, the pipeline material re- sponse remained elastic, i.e., no plastic strains oc- curred and compressive strains were lower than the critical limit for local buckling. A similar work has been presented by Chatzidakis et al. (2020),investigating the more general case of oblique loading conditions. Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 35 3. Optimal Route Selection with the Minimum Risk of Landslides Another recent work by the authors (Makrakis et al., 2022) has presented a smart decision-support tool which focuses on the optimal route selection of off- shore lifelines, and especially high-pressure gas pipe- lines, against the potential earthquake-related geo- hazard of submarine landslides. This investigation combines the advanced capabilities of GIS with effi- cient (semi-)analytical models, in order to realistically assess the response of offshore pipelines when sub- jected to axial or oblique loading due to submarine slides. In this case the pseudo-static slope stability analysis has been utilized which is widely used in engineer- ing practice in order to assess the seismic response of slopes. The calculated Factor of Safety under pseu- do-static conditions (FS PS) indicates whether the exam- ined slope is stable(i.e., FS PS< 1) under seismic conditions. The following analytical formula, that was firstly introduced by Morgenstern (1967) and further modified by Haneberg et al. (2013) among others, has been used: PS ≥ 1) or unstable (i.e., FS note the friction and slope inclination angles, respec- tively. Moreover, z represents the depth of the seabed wherec represents the soil cohesion, while φ and θ de- sediments, and γ΄ denotes the buoyant unit weight of the soil, which is equal to γ^'=γ-γw, where γ and γw are the unit weight of soil and water, respectively. Finally, k refers to the pseudo-static seismic coeffi- cient, which quantifies in a simplified manner the im- pact of horizontal inertial force due to horizontal seis- mic excitations. In reality, a vertical seismic excitation also exists, which leads to a vertical inertial force, but it is usually neglected as its impact is considered marginal (Kramer, 1996). To perform the seismic stability assessment of offshore slopes, a proper value for the pseudo-static horizontal seismic coefficient, k, has to be selected ac- cording to the acceleration levels of the examined re- gion that correspond to the selected seismic scenari- o(s). As reported by Melo & Sharma (2004), due to the
36 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY flexibility of soil slopes, the peak acceleration values that occur during an earthquake are instantaneous, thus, seismic coefficients used in common engineer- ing practice correspond to much lower acceleration values compared to the anticipated peak accelerations. Under this perspective, k, can take constant values ranging from 0.05 to 0.25, or it can be a ratio (1/3 to 1/2) of maximum accelerations. As shown in Figure 3, the application of the proposed smart tool in the Adriatic Sea results in five alternative pipeline routings, which are compared with the constructed route of TAP. The proposed routes differ in length, but also in the way they cross the seismically unstable slopes of the ex- amined region, as well as the areas characterized by steep inclination. Nevertheless, it should be stressed that the comparison with TAP route is indicative, due to the lack of all data and the resulting simplifications. • • of offshore pipelines should be performed for a se- vere seismic scenario (e.g., 2475-year return pe- riod) due to the high importance of such critical infrastructure. Larger axial force and landslide length result in greater compressive axial force for the pipeline routings which cross vertically the unstable slopes and are examined against axial distress. Pipeline routings which cross the hazardous areas under a certain angle are examined against oblique distress, and the maximum tensile and compressive strains for the examined crossing an- gles, landslide widths and impact forces, are below the acceptable limits. • The safest pipeline route has taken into account both the slopes with large inclination, as well as the slopes that are unstable for the 2475-year re- turn period scenario. The presented results highlight the capability of the smart tool to successfully support the engineers in quantifying both the geohazard and the pipeline re- sponse in order to design a route, considering the critical and non-critical areas that should be avoided or crossed under certain conditions/restrictions. Optimal route selection could noticeably reduce the length and the consequent cost of a lifeline, while in- creasing safety levels. In any case, in complex real-life projects the procedure of optimal route selection is not a straightforward task. Consequently, it should not be based on engineering judgment and design experi- ence, since it can be achieved in a more efficient man- ner via less subjective decision-support tools. 4. Slides on Infinite Planar Surfaces A translational slide is actually a movement of the upper mass of soil or sediments above a planar sur- face parallel to the surface of either the ground or the seabed, under the assumption that it has an infinite length. The movement of the soil may be represented in a simplified manner by a rigid block sliding on an in- clined planar surface. Considering a vertical segment of a soil slope inclined at an angle θ, characterized by height z, thickness h (=z·cosθ), and unit length in the third direction, four different cases can be examined: Figure 3: Application of the smart decision-support tool in the Adriatic Sea for the optimal routings of offshore pipeline subjected to axial or oblique loading The main findings of this study are the following: • The examined area in the southern Adriatic Sea is prone to offshore geohazards and especially sub- marine landslides, mainly at the eastern Adriatic Sea near Albania. • Under static conditions the submarine slopes are stable even at the steep inclination zones, in con- trast to seismic conditions, where the factor of safety significantly decreases, regardless of slope inclination. • The 475-year return period scenario is not criti- cal compared to the one for the 2475-year return period, which results in unstable slopes near the Albanian coastline. Hence, optimal route selection
(a) soil slope under static conditions, (b) submerged soil slope under static conditions (with a horizontal water table above the slope), (c) soil slope under seis- mic conditions, and (d) submerged soil slope under seismic conditions. In the general case of a soil slope under static conditions, the factor of safety is given by the following well-known expression: the angle of internal friction of the soil, respectively. ABCD will be: Assuming the unit weights of the soil above and below the water table (bulk and saturated unit weights) to be where γ, c and φare the unit weight, the cohesion and the same, γ, the weight W' of a submerged segment where γ^' (=γ-γ〗_W)is the effective unit weight, de- rived by subtracting the unit weight of water, γw, from γ. Repeating calculations, the overall factor of safety under static conditions and assuming a horizontal water table above the slope is given by: is derived. Assuming that the segment ABCD (with It is noted that if, apart from the weight W = α·z·γ, a vertical buoyancy force AW = α·z·γw exists, Eq. (4) weight W = γ·α·z) is subjected to a horizontal seismic E = k·W. Note that in reality a vertical seismic excita- excitation (which is represented via a pseudo-static seismic coefficient k), the aforementioned equations should include an additional horizontal inertial force tion also exists, which leads to a vertical inertial force. Nevertheless, its impact is considered to be less impor- tant, and therefore it is usually neglected. Under this perspective, the factor of safety under pseu- do-static conditions is given by: In the special case that k = 0 (i.e., static conditions), FSPS = FSST and Eq. (5) converges to Eq. (2).
38 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 4. Rotation of the model in order to change the orientation of the resultant force WE to vertical. a) b) Figure 5: Factor of Safety for a planar slide for submerged seismic conditions using (a) the conventional approach and (b) the proposed formula.
As aforementioned, the pseudo-static seismic coeffi- cient k is a fraction of peak acceleration at the surface of the seabed. The selection of the proper k value(s) should take into account the acceleration levels at the seismic bedrock, in conjunction with the potential ag- gravation due to the presence of soft sediments and/or topographic irregularities of the examined region. In addition, it is noted that offshore lifelines are designed for long-term conditions, i.e., a large return period is When the segment ABCD is submerged and subjected to a horizontal seismic excitation, the impact of ver- used, a fact that results in higher values of k. tical buoyancy and the horizontal inertial force Ε are taken into account. Note that E is equal to k·W, where W (= m·g) is the weight of the body. This hypothesis is undoubtedly valid, since the inertial forces are ap- plied to the mass of the body, regardless of the grav- itational field and the hydrostatic conditions. In the general case, the factor of safety under pseudo-static conditions of a submerged soil slope is given by: Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 39 In the general case the factor of safety under pseu- do-static conditions of a submerged soil slope is given by: Based on well-known trigonometric equations, and tak- ing into account that δis equal to arctan(k), the follow- ing equation is obtained for the factor of safety under pseudo-static conditions of a submerged soil slope: Note that Equation (8) is analogous to Equation (5) that corresponds to the case of an onshore dry slope under pseudo-static conditions, with γ in Equation (5) being replaced by γ’. Figure 5depicts the Factor of Safety (FS) properties (c and φ) and applied acceleration (k) have for a planar slide for submerged seismic conditions using: (a) the conventional approach and (b) the pro- posed formula. Various cases of geometry (h), soil been examined. It is evident that the new approach leads to higher FS, being thus less conservative. Note that Eq. (6) coincides with Eq.(1) which has been used in the aforementioned study of Makrakis et al. (2022). 5. Improving Seismic Stability Assessment of Submerged Slopes The aforementioned methodology was introduced in the '60s (e.g., see Morgenstern, 1967)in order to assess the stability of cohesive submarine slopes under seis- mic conditions and has been adopted in several sci- entific publications. Furthermore, several research- ers have used the above equations, while others have used them for pipeline routing (Haneberg et al., 2013). Nevertheless, this formula is erroneous since the pres- ence of a horizontal inertial force E can be combined with the vertical gravitational force W. As shown in Figure 4, the outcome of W and E is an inclined force WE, and therefore, an equivalent model can be devel- so that the force WE is vertical. The angle of the afore- mentioned rotation,δ , is equal to arctan(k).In this case, the equivalent weight W' is equal to the volume V (= α·z·γ'=l·cosθ·z·γ') multiplied with the corresponding modified unit weight γ' Ε=γ'∙√(1+k2 ). oped, in which the coordinate system has been rotated 6. Conclusions The instability of the seabed during earthquakes is a critical issue in offshore engineering, as it can threaten the safety and/or the serviceability of offshore and/ or near-shore structures. Typically, seismic slope sta- bility assessment is performed using pseudo-static methodologies based on certain simplifications that convert the dynamic problem to an equivalent static one. Under this perspective, the current study has fo- cused on the stability of submarine slopes under seis- mic conditions. More specifically, a thorough investigation of the avail- able analytical solutions of the literature has revealed that they do not include all forces caused by the applied horizontal acceleration. This fact can lead to inaccurate slope stability assessment. More specifically, the pre- sented results demonstrate that existing approaches substantially underestimate the factors of safety, espe- cially for moderate to high acceleration levels. In other words, the slopes that have been assessed in the past may not be so vulnerable as they are considered to be, leading thus to conservative and costly design solutions for offshore and/or near-shore structures and lifelines. For instance, in the case of a pipeline the obtained small
40 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY values of factors of safety would lead to increased de- sign requirements, expensive mitigation measures, or even rerouting. Conclusively, the proposed modification of factor of safety calculations can be considered as a significant improvement, while the parametric study has high- lighted the impact of various factors on the instabil- ity of a submarine slope from an engineering perspec- tive. Future extension could adopt more elaborate soil constitutive models and examine other failure types, e.g., planar slides of finite length and circular slides. In addition, apart from pseudo-static approaches, the in- clusion of all potential buoyancy forces should also be studied under real dynamic conditions, where all com- ponents of acceleration vary with time. References 1. E.T.R. Dean, Offshore geotechnical engineering: Principles and practice, Thomas Telford Limited, London, UK, 2010. 2. M. Randolph, S. Gourvenec, Offshore geotechnical engineering, 3. Spon Press, London, UK, 2011. doi:10.1201/9781315272474. J. Locat, H.J. Lee, “Submarine landslides: Advances and challen- ges,” Can. Geotech. J. 39 (2002) 193–212. doi:10.1139/t01-089. 4. T.J. Kvalstad, L. Andresen, C.F. Forsberg, K. Berg, P. Bryn, M. Wangen, “The Storegga slide: Evaluation of triggering sources and slide mechanics,” Mar. Pet. Geol. 22 (2005) 245–256. doi:10.1016/j.marpetgeo.2004.10.019. 5. A. Zakeri, “Submarine debris flow impact on suspended (free- span) pipelines: Normal and longitudinal drag forces,” Ocean Eng. 36 (2009) 489–499. doi:10.1016/j.oceaneng.2009.01.018. 6. R. Dey, B.C. Hawlader, R. Phillips, K. Soga, “Numerical mo- delling of submarine landslides with sensitive clay layers,” Geotechnique. 66 (2016) 454–468. doi:10.1680/jgeot.15.P.111. 7. N. Boukpeti, D.J. White, M.F. Randolph, “Analytical modelling of the steady flow of a submarine slide and consequent loading on a pi- peline,” Geotechnique, (2012). doi:10.1680/geot.10.P.001. J.M.R. Camargo, M.V.B. Silva, A.V.F. Júnior, T.C.M. Araújo, “Marine geohazards: A bibliometric-based review,” Geosci. 9 (2019) 100. doi:10.3390/geosciences9020100. 8. 9. P.N. Psarropoulos, A.A. Antoniou, “Designing onshore high-pres- sure gas pipelines against the geohazard of earthquake-induced slope instabilities,” Pipeline Technol. J. 2/2014 (2014) 66–85. 10. S.L. Kramer, Geotechnical earthquake enginee- ring, Prentice Hall, New Jersey, USA, 1996. 11. D. Chatzidakis, Y. Tsompanakis, and P. N. Psarropoulos, “An impro- ved analytical approach for simulating the lateral kinematic dist- ress of deepwater offshore pipelines,” Appl. Ocean Res., vol. 90, no. April, p. 101852, 2019, doi: 10.1016/j.apor.2019.101852. 12. D. Chatzidakis, Y. Tsompanakis, and P. N. Psarropoulos, “A semi-analy- tical approach for simulating oblique kinematic distress of offshore pi- pelines due to submarine landslides,” Appl. Ocean Res., vol. 98, no. February, p. 102111, 2020, doi: 10.1016/j.apor.2020.102111. 13. Yuan F, Li L, Guo Z, Wang L (2015). “Landslide impact on submarine pipeli- nes: Analytical and numerical analysis,”Journal of Eng. Mech. 141: 04014109. 14. Yuan F, Wang L, Guo Z, Shi R (2012a). “A refined analytical model for landslide or deb- ris flow impact on pipelines.Part I: Surface pipelines,”Appl. Ocean Res., 35: 95–104. 15. Yuan F, Wang L, Guo Z, Xie Y (2012b). “A refined analy- tical model for landslide or debris flow impact on pipelines.Part II: Embedded pipelines,”Appl. Ocean Res., 35: 105– 114. 16. DNV GL AS (2017). Pipe-soil interaction for submarine pi- pelines. Recommended practice DNVGL-RP-F114. 17. Trans Adriatic Pipeline (2013a). ESIA Albania Section 4 – Project Description. 18. Trans Adriatic Pipeline (2013b). ESIA Italy - Annex 7 Baseline data and maps: Appendix 11 Geotechnical report - Shallow geo- technical survey - Part A soil parameters for design. 2013. 19. N. Makrakis, P.N. Psarropoulos, D. Chatzidakis, Y. Tsompanakis, “Optimal route selection of offshore pipelines subjected to submarine lands- lides,” The Open Civil Engineering Journal, 16, e187414952209160, 2022. https://doi.org/10.2174/18743315-v16-e2208190. 20. N. R. Morgenstern, “Submarine slumping and the initiation of turbidity current,” in Marine Geotechnique, A. F. Richards, Ed. University of Illinois Press, 1967, pp. 189–220. 21. W. C. Haneberg, B. Bruce, and M. C. Drazba, “Using qualitative slope hazard maps and quantitative probabilistic slope stability mo- dels to constrain least-cost pipeline route optimization,” in Offshore Technology Conference, 2013, pp. 1–11, doi: 10.4043/23980-ms. 22. C. Melo and S. Sharma, “Seismic coefficients for pseudostatic slope analy- sis,” in 13th World Conference on Earthquake Engineering Vancouver, B.C., Canada August 1-6, 2004 Paper No. 369, 2004, p. 15. Authors Prodromos Psarropoulos National Technical University of Athens Structural & Geotechnical Engineer firstname.lastname@example.org Yiannis Tsompanakis Technical University of Crete Professor of Computational Dynamics & Earthquake Engineering email@example.com Nikolaos Makrakis Technical University of Crete Surveying & Earthquake Engineer firstname.lastname@example.org
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42 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Numerical prediction of material properties and structural response of JCO-E offshore pipes A. Stamou1, I. Gavriilidis1, C. Palagas2, E. Dourdounis2, N. Voudouris2, A. Tazedakis2, S. A. Karamanos1 > 1 University of Thessaly, 2 Corinth Pipeworks Abstract The present paper presents the application of advanced finite element tools to predict the influence of cold-forming on material properties and collapse re- sistance of steel JCO-E pipes. Results are obtained for a thick-walled 30-inch-di- ameter pipe, corresponding to diameter-to-thickness ratio value less than 20. The numerical simulations are supported by experimental tests determining the material properties of steel pipe and steel plate, which are used for form- ing the JCO-E pipe, and accounts for the influence of heat-treatment on pipe material and its effects on collapse capacity is discussed. The numerical results are also correlated with recent full-scale collapse experiments performed in C-FER, while both experimental data and numerical results are compared with the DNV-ST-F101 standard predictions, and suggestions on the value of fabri- cation factor are made, considering the material strength recovery due to heat treatment. Finally, the influence of heat treatment on material strength recov- ery and the collapse capacity is discussed.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 43 1. Introduction Large diameter and thick-walled line pipes, which are candidates for both deep offshore applications, are mainly manufactured by cold forming and expanding long plates. In this process the plate is deformed sig- nificantly in the inelastic range of its material, and a circular configuration (pipe) is obtained from the in- itial flat configuration (plate) through the following sequential steps: (a) crimping of plate edges, (b) “J” phase, where the forming tool (punch) forms the one side of the plate through a series of consecutive punch- ing steps and the plate obtains a J-shape, (c) “C” phase, where the other side of plate is deformed by the punch in a manner symmetrical to that followed in J phase, (d) “O” phase, where a quasi-round configuration is obtained, (e) welding stage where the plate ends are welded, and (f) expansion phase where a mechanical expander is used to expand the pipe and finally obtain the desired characteristics. These cold-forming steps affect the geometry, such as cross-sectional ovality and wall thickness, and the material properties of the final product . Previous works have reported the effects of cold-form- ing manufacturing process on the material prop- erties of the finished line pipe, and outlined the re- duced collapse capacity of cold-formed pipes when compared with the seamless pipes . During the ex- pansion phase of JCO-E, the pipe material is plasti- cally deformed in the circumferential direction, lead- ing to reducing the compressive strength of the pipe material, due to Bauschinger effect. The compressive strength of pipe material is an important factor that controls the structural performance of pipeline under external pressure loading conditions, and thus it is of major concern in offshore applications. However, it is possible to alleviate the material strength degradation with mild heat treatment of the line pipe during the coating cycle of the pipe , resulting in higher exter- nal pressure capacity. The present paper continues the authors’ research on collapse performance of “heat treated” and “as fabri- cated” JCO-E pipes , focusing on the influence of cold-forming process on the geometric and the ma- terial properties of the fabricated pipe. The manu- facturing process of a thick-walled 30-inch-diameter line pipe is simulated using a two-dimensional (2D) finite element model. The steel plate thickness is 39 mm. Furthermore, its structural response under ex- ternal pressure is calculated and compared with the results obtained by a three-dimensional (3D) analysis that simulates the full-scale experiment performed in C-FER . The beneficial effect of heat treatment on the compressive strength of pipe material and on the collapse strength of the pipe is also examined. The nu- merical predictions of the collapse pressure are also compared with the predictions of DNV-ST-F101  for- mula. Finally, the variation of mechanical properties through the pipe thickness is discussed and its influ- ence on the external pressure capacity of the pipe is investigated. 2. Numerical modelling 2.1 Description of JCO-E manufacturing process The JCO-E manufacturing process is simulated using a quasi-two-dimensional (2D) finite element model referred to as “Model 1”. In this model, the inelastic response of the steel plate material is described with a user-defined material subroutine (UMAT) which employs a nonlinear kinematic hardening plasticity model developed and implemented by the research team in previous works . The finite element model simulates rigorously the final line pipe product from the initial flat configuration of plate to the series of consecutive mechanical steps, and the final circular configuration of pipe after unloading from the expan- sion stage. The numerical analysis is performed using ABAQUS/Standard finite element package . The forming parameters for simulating the JCO-E man- ufacturing process of the 30-inch-diameter line pipe have been provided by Corinth Pipeworks S.A. (CPW). More specifically, geometric parameters, such as the dimensions of the plate, the forming dies, the punch, the expander segments, and kinematic parameters, such as initial positions and displacements of each part, constitute the basic input information for sim- ulating the fabrication process in a realistic manner. A 3D schematic representation of the JCO-E manu- facturing process is shown in Figure 1. The crimping stage is simulated by considering the inner die (upper) fixed and letting the outer die (lower) move upwards, and subsequently bend the plate edges up to a desired deformation level. The stage is completed by drawing
44 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY back the outer die, causing the plate to unload elas- tically. Figure 1 presents the J-C-O steps (b, c and d in Figure 1) that follow after crimping step in the numer- ical analysis. In these steps, the plate is subjected to several punching steps, which are forcing the plate to progressively deform under local bending and unload- ing conditions across the plate width. The number of punching steps is the same between the two crimped edges (J and C steps). Final punching occurs at the cen- tre of plate width, so that a quasi-circular configura- tion is obtained after unloading. Followingly, the two plate edges come into contact by applying a mechani- cal load on their lateral surfaces. The subsequent step of welding is not performed in the current simula- tion, since the welding process induces small residual stresses in the pipe and therefore, it has negligible ef- fect on the buckling pressure of the pipe, as demon- strated in a previous study . The last step of the man- ufacturing process is the expansion stage, as shown in Figure 1, where twelve expander segments are dis- placed outward in the radial direction, expanding the pipe, so that the pipe diameter size is controlled. In the 2D finite element analysis of the manufacturing process, the forming tools and dies are modelled as an- alytical rigid surfaces, whereas four-node reduced inte- gration generalized plane strain continuum elements (denoted as CPEG4R in ABAQUS/Standard) are used in the deformable plate, so that the conditions are similar to those imposed in a real pipe mill, and therefore the out of plane deformation during the process is taken into account. More specifically, twelve elements have been used in the through thickness direction of plate, and the size of elements in the circumferential direc- tion is chosen equal to 16% of thickness. The contact between the plate and the rigid surfaces is modelled using a “master-slave” algorithm with frictionless con- tact property; in the contact pair the undeformed rigid bodies of dies and tools represent the master surfaces, whereas the deformable plate constitutes the slave sur- face. Special care is given during the JCO steps to avoid the relative motion between the punch surface and the upper side of plate during punching. 2.2 Material model The sequence of punching steps across the plate width during the JCO process results in significant plastic deformation of the plate. Each punching step imposes local bending, and therefore the outer and the inner part of the plate wall is deformed under tension and compression, respectively. Furthermore, the expan- sion step strengthens the pipe material of the outer pipe wall further in tension, making it vulnerable to reverse loading, due to the Bauschinger effect. Since reverse loading conditions exist at the outer part of the pipe wall, when external pressure is uniformly applied on the pipe surface, an appropriate plasticity model should be employed to account for the Bauschinger Figure 1: Schematic representation of JCO-E manufacturing process; (a) Crimping, (b) J-phase, (c) C-phase, (d) O-phase, (e) Expansion.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 45 Figure 4c. The final gap is depicted in Figure 4d and is significantly lower than the one obtained after the O-step (Figure 4a). The initial gap (Figure 4a) and the final gap (Figure 4d) are in accordance with measure- ments with actual 30-inch-diameter pipe provided by CPW. At the end of the extra punching step, the final gap (Figure 4d) is closed and the two plate edges are kept in contact, using a “no separation” contact algorithm. effect, simulating the material response under reverse or cyclic loading stress paths. Herein, a Von Mises model with plasticity nonlinear kinematic/isotropic hardening is employed, and is described in more de- tail by Chatzopoulou et al. . A series of experiments, which are representative of the deformation history during the JCO-E manufac- turing process, have been carried out to determine the material properties of the X60 steel grade mate- rial of the plate and calibrate the plasticity model. The experimental procedure consists of tension-compres- sion-tension loading on specimens extracted from the steel plate at different locations and orientations fol- lowing the recommendations of SEP 1240 . Figure 2 presents the experimental stress-strain curve of the X60 steel plate material and the corresponding numer- ical fit from the plasticity model. Figure 3: Plate deformation during JCO manufacturing process prior to welding; von Mises contour plot. The nearly circular pipe configuration obtained after gap closing and welding is referred to as JCO pipe, as shown in Figure 5a. Subsequently, expansion of the JCO pipe is performed, as shown in Figure 5b, using twelve expander segments that move radially outwards. The final configuration of pipe, obtained after removing the expander segments, is referred to as “JCO-E pipe” and corresponds to the final product of the fabrication process, as shown in Figure 5c. The amount of expan- sion induced in the pipe is quantified in terms of the so-called “expansion strain” (εE), expressed by: E and C W are the lengths of pipe circumference where C after (Figure 5c) and before (Figure 5a), the expansion phase respectively. The expansion strain expression adopted in the present study is also adopted in per- vious works , , . The expansion strain value should be considered as a permanent strain of the final line pipe shape. The expansion strain applied on the JCO pipe of Figure 5, is equal to 1.30%, which Figure 2: Experimental curve of the X60 steel plate, and the corresponding numerical fit. 3. Numerical results 3.1 Simulation of JCO-E manufacturing process The deformation configurations of the plate during the manufacturing process are shown in Figure 3 for the initial crimping step and the subsequent “J”, “C” and “O” steps. In the present numerical analysis, fif- teen punching steps are applied during the JCO steps. After removal of forming tool (JCO punch), a secondary forming tool referred to as “finishing press” (Figure 4) is used to reduce the gap by imposing two extra bend- ing steps on the two crimped sides of the plate con- figuration after the O-step, as shown in Figure 4b and
46 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 4: Deformation sequence of JCO pipe under the finishing press; von Mises contour plot. is an approximate value of the actual expansion mag- nitude of the 30-inch-diameter pipe fabricated in the pipe mill. Considering this amount of expansion, the inner diameter of the JCO pipe at 0, 45 and 90-degree locations from the weld seam is 675mm, 675mm and 679mm, respectively, while the corresponding values of the JCO-E pipe are 687mm, 686mm and 686mm. The numerical predictions of the inner diameter of both configurations (JCO and JCO-E) are in very good agreement with actual measurements at the corre- sponding locations. process and the structural strength of the pipe under external pressure loading. Following the step of un- loading from expansion (JCO-E pipe), uniform exter- nal pressure is applied on the outer surface of the pipe. During the pressurization step, the modified Riks’ al- gorithm is employed to capture the maximum pres- sure at the onset of collapse and trace the post-buck- ling response. parameter with significant influence on the resistance of pipes under external pressure. The effect of expansion co) of the JCO-E pipe under con- on the collapse pressure (P sideration is shown in Figure 6, considering a wide range In JCO-E pipes, the expansion strain εΕ is an important of expansion strain values (εΕ). For small values of εΕ (up to 0.7%), P_co is an increasing function εΕ. For εΕ values only 1% lower. Increasing the εΕ value beyond 1.8% the co value remains ranging between 0.7% and 1.8%, the P nearly constant. It is worth noticing that the maximum collapse pressure is equal to 37.9 MPa at 1.69% expansion strain, whereas at 1.30% strain (an approximate value of co value is the expansion strain used in the pipe mill) the P collapse pressure reduces, as shown in Figure 6. This is attributed to the Bauschinger effect, which decreases the circumferential compressive strength. Also note that the maximum allowable expansion strain, according to DNV-ST-F101 standard , is 1.50%, which falls within the optimum range of expansion. The effect of expansion strain on the geometric configuration of line pipe is also investigated. The residual cross-sectional ovality (Oο) of the pipe at the end of the fabrication process is measured, using the following expression: Figure 5: Deformation sequence of expansion phase, resulting in the final pipe geometry of the JCO-E pipe; von Mises contour plot. (a) Before expansion (JCO pipe), (b) at maximum expansion (here εE=1.3%), (c) final stage after unloading (JCO-E pipe). 3.2 Effect of expansion on the geometry and, pipe structural integrity in deep water The finite element model presented in section 2 is capa- ble of simulating rigorously the JCO-E manufacturing where Dmax and Dmin are the maximum and minimum values of the outer diameter, and D is the nominal value of the outer diameter. The interaction between the cross-sectional ovality and the applied expansion strain is shown in Figure 6 for the 30-inch-diameter JCO-E pipe under consideration. The results demon- strate that the cross-sectional ovality after the JCO stage before expansion, is approximately equal to 0.6%. Subsequently, increasing the expansion strain, the cross-sectional ovality of the pipe decreases. This reduction is observed up to about 1.3% expansion
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 47 Figure 7: Effect of expansion strain on the average wall thickness of the JCO-E line pipe, compared with the plate thickness. model (Model 2), accounting for the material proper- ties of the as-fabricated (AF) and the heat-treated (HT) conditions. Material stress-strain curves have been obtained ex- perimentally from uniaxial compression tests on cou- pon specimens extracted and machined from the outer part of AF and HT pipes in the circumferential direc- tion. The experimental curves at 90, 180 and 270-de- gree locations around the circumference are averaged, and the corresponding responses are shown in Figure 8. Furthermore, the stress-strain curve of the X60 grade steel (plate material) is shown in Figure 8. The Bauschinger effect, due to reverse loading, is clearly shown in Figure 8 in terms of the reduced proportional limit of the AF and the HT curves, compared with the plate material curve. Additionally, the comparison between the AF and the HT curve demonstrates the beneficial effect of mild heat treatment on material strength (material strength recovery). The experimental and numerical results on the col- lapse pressure are summarized in Table 1. The re- sults include the numerical collapse pressure ob- tained from Model 1 described in Section 2, at 1.30% expansion strain, which is an approximate value of the expansion strain used in the pipe mill. The col- lapse pressure values obtained from the two numeri- cal models are in good agreement. Furthermore, the numerical prediction of the full-scale collapse pres- sure is also very successful. Finally, Table 1 shows that the collapse pressure is increased by 13% for Figure 6: Effect of expansion on residual cross-sectional ovality (Oο) prior to pressurization and the corresponding collapse pressure (P co). strain, reaching a value lower than 0.05%, while fur- ther increase of expansion strain has negligible effect on the ovality of the JCO-E pipe. Figure 7 presents the average thickness of the JCO-E pipe under consideration (final product) with re- spect to different expansion levels and is also com- pared with the initial thickness of plate (39mm). The numerical results demonstrate that the aver- age wall thickness of the line pipe decreases with increasing expansion strain in a quasi-linear man- ner, due to “Poisson” effect in the inelastic range of steel material. The results also show that the thick- ness of the JCO pipe (before expansion) is reduced by 0.1mm with respect to the initial plate thick- ness, and this is due to local bending induced by the punching steps during the J-C-O phases, as shown in Figure 7 at zero expansion strain. 3.3 Effect of mild heat treatment on pipe collapse capacity The collapse performance of JCO-E line pipes under ex- ternal pressure has been studied in a previous work by the authors . In that work, the effects of mild heat treatment on the compressive strength of the line pipe material and on the collapse pressure were examined. This heat-treatment corresponds to a typical coating process of the line pipe. A thermally-treated pipe, man- ufactured by CPW, with the geometric and material characteristics of the 30-inch JCO-E pipe under con- sideration was subjected to full-scale collapse test . The collapse test procedure was also numerically sim- ulated, using a three-dimensional (3D) finite element
48 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY the case of the heat-treated pipe, compared with the as-fabricated pipe. Table 1: Experimental and numerical results of collapse pressure results (in MPa). The collapse capacity of the 30-inch-diameter JCO-E pipe is also quantified using the DNV-ST-F101 design standard . The results are presented in Table 2 for fab) namely 0.85 and 1 two values of fabrication factor (a to account for the as-fabricated (AF) and heat-treated (HT) material properties. The collapse pressure predic- tions using the specification formula appear to be con- servative compared to the experimental and numeri- cal results of Table 1, and this is attributed to the high value of ovality parameter proposed by the standard (0.5%). 4. Conclusions The manufacturing process and the collapse perfor- mance of a thick-walled 30-inch-diameter JCO-E pipe (D/t≈20) is investigated, using advanced numerical tools. A two-dimensional (2D) finite element model is used (Model 1), which simulates the manufacturing process of the JCO-E pipe and predicts its collapse pressure. The ge- ometric characteristics of the fabricated pipe predicted by Model 1 are in very good agreement with measurements provided by the pipe mill. The effects of pipe expansion on its geometric characteristics and on its external pres- sure capacity are also examined. Increasing the expan- sion level up to about 0.7%, the cross-sectional ovality of the fabricated pipe is reduced and the corresponding col- lapse pressure is increased. For expansion strain values between 0.7% and 1.8%, the value of collapse pressure remains nearly constant, whereas for expansion strain Figure 8: Averaged experimental compressive stress-strain curves at the outer part of pipe before and after the heat treatment, and plate material curve. values beyond 1.8%, the collapse pressure decreases. The average wall thickness of JCO-E pipe is computed for dif- ferent values of expansion strain, and the results indicate a quasi-linear dependance of pipe wall thickness on the expansion level. The collapse pressure calculated from Model 1 com- pares very well with the collapse pressure from a three-dimensional (3D) model that simulates the full- scale collapse test (Model 2). Using Model 2, the effect of mild heat treatment on the collapse pressure is in- vestigated, considering the stress-strain curve before (AF) and after heat treatment (HT). The results show that P_co in the HT pipe is increased by 13%, compared to the AF pipe, verifying the beneficial effect of heat treatment. Collapse pressure predictions obtained from the DNV-ST-F101 collapse formula are compared with the numerical and experimental results. The comparison shows that the DNV-ST-F101 formula pro- vides reasonable yet conservative collapse pressure predictions for the pipe under consideration. Table 2: Collapse pressure predictions (in MPa) using the DNV-ST-F101  collapse formula for the as-fabricated (AF) and heat-treated (HT) conditions.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 49 5. Acknowledgments The authors would like to thank Dr Konstantinos Antoniou for his help and contribution on the first stages of the present investigation. References 1. K. Antoniou, G. Chatzopoulou, S. A. Karamanos, A. Tazedakis, C. Palagas and E. Dourdounis, “Numerical Simulation of JCO-E Pipe Manufacturing Process and Its Effect on the External Pressure Capacity of the Pipe,” Journal of Offshore Mechanics and Arctic Engineering, vol. 141, no. 1, p. 011704, 2019. 2. F. Arroyo, R. F. Solano, L. Mantovano, F. B. de Azevedo, H. Alves, D. Swanek, R. Silva and H. Ernst, “Qualification of UOE SAWL Linepipes with Enhanced Collapse Resistance for Ultra Deepwater Applications,” in Proceedings of the ASME 2013 32nd International Conference on Offshore Mechanics and Arctic Engineering, Nantes, France, 2013. I. Gavriilidis, A. G. Stamou, C. Palagas, E. Dourdounis, N. Voudouris, A. Tazedakis and S. A. Karamanos, “Collapse testing and analysis of JCO-E steel pipes,” in 17th Pipeline Technology Conference, Berlin, Germany, 2022. 3. 4. Det Norske Veritas, “Submarine pipeline systems,” STANDARD DNV-ST-F101, Hovik, Norway, 2021. 5. G. Chatzopoulou, S. A. Karamanos and G. E. Varelis, “Finite element analysis of UOE manufacturing process and its effect on mechanical behavior of offshore pipes,” International Journal of Solids and Structures, vol. 83, pp. 13-27, 2016. 6. H. Hibbitt, B. Karlsson and P. Sorensen, “ABAQUS: Theory manual, Version 2016,” Dassault Systèmes Simulia Corp, Providence, RI, 1992. 7. K. Antoniou, “Numerical simulation of JCO-E line pipe manufacturing and its influence on the mechanical behavior and strength of offsore pipelines,” PhD Thesis, Department of Mechanical Engineering, University of Thessaly, Volos, 2021. 8. SEP 1240, “Testing and Documentation Guideline for the Experimental Determination of Mechanical Properties of Steel Sheets for CAE Calculations,” 1st edition, Institute VDEh, Dusseldorf, Germany, 2006. Authors Aris Stamou University of Thessaly Ph.D. candidate email@example.com Ilias Gavriilidis University of Thessaly Post-Doctoral Researcher firstname.lastname@example.org Christos Palagas Corinth Pipeworks Engineering and Technology Manager email@example.com Efthimios Dourdounis Corinth Pipeworks Head of Technical Analysis firstname.lastname@example.org Nikos Voudouris Corinth Pipeworks Research & Development Senior Manager email@example.com Athanasios Tazedakis Corinth Pipeworks Chief Technology Officer firstname.lastname@example.org Spyros A. Karamanos University of Thessaly Professor of Structural Mechanics email@example.com
50 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Repurposing Hydrocarbon Pipelines to Transport CO2: PETRONAS' Study F. Aziz, K. A. Karim, Ir. H. Hussien > PETRONAS Abstract PETRONAS is considering pipeline repurpose option for one of its CCS projects in Malaysia. One of the opportunities identified is to repurpose existing gas ex- port pipelines, 24in and 30in with combined distance of 200km from offshore to onshore. Existing technical frameworks from available standard and inter- nal resources for pipeline repurpose have been reviewed. This is to provide complete approach to pipeline repurpose. Qualitative risk as- sessment (QRA) for pipeline repurpose is presented by discussing technical rec- ommendations made by the feasibility study team. This feasibility study involves CO2 characterization, review of existing hydrau- lics analysis, fitness for service (FFS) result review, Battelle Two Curve Method (BTCM) check against existing pipeline toughness and sour compatibility check. Existing pipeline capability limits are established to provide clarity if PETRONAS able to transport CO2. Further analyses are identified accordingly to address the established limits.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 51 1. Introduction In 2020, PETRONAS has embarked on its Net Zero Carbon Emission (NZCE) by 2050 target. The mission sets the company's business activities to be carbon neu- tral by 2050. Among efforts conducted by PETRONAS to achieve the target is the implementation of carbon capture and storage (CCS). One of the proposed CCS projects is to sequester vol- ume of CO2 in Table 1. CO2 will be injected into depleted gas reservoir offshore peninsular Malaysia. The de- pleted reservoir is part of the earliest gas complex de- veloped by PETRONAS which consists of: I. 1 no Central Processing Platform (CPP) Group Technical Solutions (GTS), the engineering arm of PETRONAS, together with asset owner initiated a study to determine the feasibility of repurposing the pipelines. The mechanical properties of the pipelines are listed in Table 1. This paper will share the assessment approach as well as the findings by achieving below objectives: I. To identify approach employed for pipeline repur- pose and to map with existing internal technical framework. II. To highlight qualitative risk assessment (QRA) rec- ommendations for pipeline repurpose scenario and outcomes of CO2 fluid characterization study. II. 2 nos wellhead platform (WHP) III. To elaborate technical challenges associated with III. 1 no 24in x 50km gas pipeline from CPP to collec- tor platform IV. To provide high level costing of newly built pipeline repurpose. IV. 1 no 30in x 150km gas export pipeline from collec- tor platform to onshore gas terminal V. To discuss way forwards for CCS detail engineering including study and validation. pipeline. Table 1: Pipeline Mechanical Properties and Proposed Volume
52 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 2. CO2 Pipeline Repurpose Technical Framework In general, there are two main existing standards for design and operation of CO2 pipeline namely DNV- RP-F104(1) and BS 27913(2) which outline basic require- ments of designing CO2 pipeline which encompasses description of CO2 properties, concept development and specific design criteria, materials and pipeline de- sign, construction, and operation. 2.1 Repurpose Approach as per DNV-RP-F104 While BS27913 provides only general statement of compliance to pipeline repurpose, DNV has laid out essential steps to repurpose existing pipeline which covers: I. Existing pipeline integrity assessment II. Hydraulics study guideline is timely to cater increasing demand of pipe- line repurpose studies within PETRONAS. The meth- odology is illustrated in Figure 1 which existing pipe- line integrity assessment and integrity reassessment & physical modification are the integral parts of the methodology. Pipeline integrity assessment comprises evaluation of pipeline integrity against various threats which can be external corrosion, internal corrosion, stress cor- rosion cracking, manufacturing defects, construction defect, equipment failure, weather condition and ex- ternal load, third party damage and incorrect opera- tions. However, corrosion is one of the biggest prob- lems contributing to leaks and ruptures of pipelines. Typically, all metal loss defects are treated the same as corrosion defect that is gauged by assigning safe working pressure related to the defect and to be com- pared against MAOP. This ratio is referred as Estimated Repair Factor (ERF). III. Safety evaluation As such for pipeline repurpose would consist of: IV. Integrity reassessment & pipeline modification Corrosion defects are assessed in item i and iv that involve estimating remaining life of pipeline using standard pipeline fitness for service (FFS) method. As opposed to using actual corrosion rate upon years of previous operation, the corrosion rate for repurpose pipeline is derived from CO2 corrosion analysis for specific operating cases. For pipeline repurpose, the new operating parameters are determined by hydrau- lics study analyzing design cases which are normal op- eration, shutdown, and start-up. An important input to hydraulics study is fluid characterization study whereby CO2 stream compositions are analyzed to de- velop its phase envelope based on various EoS. Analysis on sudden release of CO2, dispersion (on- shore) and dilution (offshore), is an integral part of the safety evaluation. The results of the analysis become the basis for operator to reassign the location class of the pipeline. 2.2 PETRONAS Existing Internal Technical Framework An internal guideline of PETRONAS pipeline life ex- tension (PLES) methodology has been established. The I. Determination of remaining life of pipeline based on the remaining wall thickness against corrosion rate. II. Predicting subsequent metal loss based on new op- erating condition with CO2 followed by determina- tion of remaining life of the pipeline at the end of intended life extension period. 3. Risk Assesment and related Repurpose Analyses 3.1 Qualitative Risk Assessment Qualitative risk assessment (QRA) has been performed by project team to provide clarity on the technical risks that are collectively agreed by the stakeholders. The QRA was carried out based on available information Pipeline 1 and Pipeline 2. The recommendations made are as follow: I. Rec #1: Significant presence of H2S seriously af- fects pipeline material compatibility as the pipelines are not designed as sour service. Preliminary assessment is required to determine appropriate sour region as per NACE MR-0175(4) recommendation.
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 53 Figure 1: PETRONAS Framework on Pipeline Life Extension Study (PLES)
54 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY II. Rec #2: Charpy impact testing was performed at 10°C as opposed to API5L recommendation, 0°C. Charpy re-testing may be required. Battelle Two Curve Method (BTCM) is required to analyze if the toughness is sufficient to resist running ductile fracture (RDF). III. Rec #3: Repurpose may involve pressure testing. Using water as a testing medium may initiate cor- rosion if the drying is not properly done. Worst, water will stubbornly retain in corroded profile of the pipeline. Hence, technical rationalization is required to determine the criticality of pressure testing. Alternative fluid may be used instead of water for the pressure test medium. IV. Rec #4: Thermodynamics behavior of CO2 must be established to understand the phase behavior of CO2 across pipeline length. considered and incorporated in the phase envelope. Pipeline operating conditions developed in the steady state hydraulics analysis was then mapped accordingly in the phase envelope. Based on fluid characterization result in Figure 2, composition with 4mol% of H2 have the largest area of 2-phase region compared to other studied compo- sitions. This condition imposes operational challenge which the bubble point at 0°C is found to be around 80barg compared to 50-60barg for other studied com- positions. Hence, to select operating window to trans- port CO2 with 4mol% H2 can be challenging. Hence, it has been advised that H2 content to be limited to 2mol% (max), named as worst-case phase envelope. All other impurities such as N2, Ar, CH4 are not impacting the phase envelope as greatly as H2. 3.2.2 Steady State Hydraulics Result 3.2 Hydraulics Analysis 3.2.1 CO2 Fluid Characterization The proposed development concept is expected to re- ceive CO2 from 2 main sources namely inherent and post-combustion. For the purpose of this study, 2 main compositions have been analyzed namely 99% CO2 (base fluid) and 96% CO2 with impurities sensitivity (worst-case). Base case specification is sourced from foreign CO2 supply where PETRONAS plans to provide transpor- tation and storage service (T&S-as-a-service) to for- eign emitters. For the worst-case scenario, the compo- sition has been established based on overwhelmingly CO2 condition with sensitivity of impurities including N2, Ar and H2. Four equation-of-states (EoS),GERG-2008, PR78, SRK, CPA had been tested which then compared against Span & Wagner. The comparison was made to estab- lish accuracy against density of pure CO2. As a result, GERG-2008 persistently demonstrated smallest vari- ance of 0.01% against pure CO2 density during export, arrival and depressurization (seabed) cases. Hence, GERG-2008 EoS had been chosen to further establish phase envelope of CO2 stream composi- tion. Water limits of 500ppm and 100ppm have been Steady state hydraulics analyses were initially per- formed without the constraint of pipeline repurpose. The analyses were modelled based on 200km pipeline with a landing pressure of 65barg during the early in- jection life. This has caused the results to be tailored for sizing of newly built pipeline only. For pipeline sizes ranging from 8-inch to 24inch, the highest re- quired departing pressure is 200barg. The results of the hydraulics analyses were mapped on 96mol% CO2 composition case with 2mol% H2. Solubility line for 500ppm and 100ppm water specifi- cations are also incorporated in Figure 2. The operat- ing conditions are outside of water dewpoint of both water limits. Also, it is away from hydrate line. Hence this CO2 composition would be manageable within the required operating pressure range for pipeline sizes from 8-inch to 24inch. 3.2.3 Hydraulics Sizing Sensitivity The proposed pipeline sizes for Option 1-4 are 8, 10,16 and 18in respectively. However, the sizes of Pipeline 1 and Pipeline 2 are larger, 24in and 30in. Hydraulically, bigger pipeline size would have lesser pressure loss and able to deliver larger volume. Since the existing pipeline sizes are larger, supposed there would be no issue to match intended CO2 volume in
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 55 Figure 2: Various composition phase envelope & worst-case phase envelope Pipeline 1 and Pipeline 2. Further hydraulic analysis is required to determine backpressure for 150km and 50km in 30in and 24in respectively. Hence the depart- ing pressure would be much lower than 200barg for any of the proposed flowrate, desirably below MAOP of 130barg. We reckon for the lowest flowrate, the re- quired departing pressure is most likely to be within the strength of existing pipeline. 3.3 Current Integrity Assessment: Fitness for Service (FFS) As a well-established company, PETRONAS has devel- oped an end-to-end web-based pipeline integrity man- agement system, i-PIMS, which integrates full integ- rity cycle of a pipeline from fitness-for-service (FFS), linear referencing, risk assessment to integrity man- agement plan (IMP) of respective pipeline.Fitness for Service (FFS) assessment of 30in and 24in pipelines has been retrieved from i-PIMS. FFS inputs are sourced from the latest intelligent pigging (IP) inspection re- sults, 2013 and 2014 respectively. 3.3.1 Integrity Condition of Pipeline 1 & Pipeline 2 In general, Pipeline 1 reported low defects of as shown in Figure 3. The lowest Psafe is 150barg with the earliest year Psafe to be challenged is 2028. The contributing defects are all due to internal corrosion and cluster of worse defects are distributed into sev- eral KPs. They are within KP35-44, KP59, KP71, KP79 and KP 156 with remaining lives vary from 2028 to 2043. Majority of the defects are axial slotting and pinhole types. Based on 2014 fitness-for-service (FFS) exercise, the lowest Psafe is 134barg with the earliest Psafe to be challenged is in 2024. Contributing defects are due to internal and external corrosion. Cluster of worse de- fects are distributed into two locations, at the start and at the end of the pipeline, KP0.02-KP0.13 and KP 40-43 respectively. Based on FFS assessment result, the re- maining life of worse defects vary from 2024 to 2035 and majority of the worse defects are external.
56 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 3: Psafe of Pipeline 1 and Pipeline 2 (excerpt from i-PIMS, PETRONAS) 3.4 Resistance to Running Ductile Fracture (RDF): Battelle Two Curve Method (BTCM) Running ductile fracture (RDF) is a prominent fail- ure mode for CO2 pipeline. RDF is initiated when CO2 is quickly depressurized from pipeline that causes temperature to drop drastically as energy is released. Consequently, the pipe material become brittle and easily torn longitudinally. I. Direct proportional relationship between CVN value and initial release pressure for 65°C and 55°C cases. The higher the initial release pressure, the higher the CVN value required to resist the driv- ing force. II. As the release pressure increase, CVN of 1000J is obtained from the calculation which may indicate insufficient pipe thickness to resist RDF. There are 2 forces related to RDF. The driving force that tears open the pipe due to internal pressure release i.e. depressurization and the toughness of the pipe mate- rial that resist the tearing from propagating. III. As opposed to item i, an unusual CVN trending of for 20°C case has been mapped. The CVN value is inversely proportional to initial release pressure. In this study, the driving and resistance forces are cal- culated using PETRONAS’ internal calculation pro- gram, enhanced Battelle Two Curve method (e-BTCM). As the team sighted mill certificate dated 1983, it was found that Charpy test was carried out at 10°C. As the current API SPEC 5L(3) requires Charpy test to be car- ried out at 0°C, retesting using actual pipe sample is strongly proposed. Figure4 shows the results of e-BTCM calculation by incorporating actual SMYS (441-448MPa), UTS (570- 590MPa), CVN value (154.8J at base metal) and DWTT value (756.6J). It appears that: IV. Due to item iii, a thorough review of internal cal- culation program may be required following find- ing of item iii. 3.5 Preliminary Sour Material Compatibility Assessment A preliminary sour assessment has been performed by considering 130barg MAOP as the highest operating pressure of the pipeline with 200ppm and 9ppm H2S concentration. The results are mapped as per Figure 5. As shown, 9ppm of H2S concentration will produce H2S partial pressure PH2S of 0.117kPa whereby 9ppm
Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 57 Figure 4: Pipeline 1 BTCM Result can be well adopted as the H2S limit. To stretch it fur- ther to the limit, 20ppm will result PH2S of 0.26kPa. With 200ppm of H2S concentration would certainly re- quire treatment prior to flow into the pipeline. 3.6 Technical Discussions Above sections demonstrate the result of preliminary assessments performed by the study team. The results provide further technical clarity on the feasibility of pipeline repurpose. Qualitative risk assessment (QRA) which attended by all stakeholders is an effective exercise to gauge the overall technical risks and recommendations to ad- dress them accordingly. With risk assessment in place, probability of pipeline repurpose to fail is minimized. Currently, existing hydraulics analysis only consider newly built pipeline case that requires departing pres- sure up to 200barg to transport dense phase CO2 for 200km distance with the highest proposed size as 18in. Given the size of Pipeline 1 and Pipeline 2 are 30in and 24in respectively, the study team believe there is an opportunity to further reduce pipeline operating pres- sure below MAOP. The integrity status of Pipeline 1 and Pipeline 2 is well understood. The remaining life of both pipelines are estimated based on corrosion rate of existing natural gas product. To obtain remaining life for future use, it Figure 5: Preliminary Sour Assessment. (Figure excerpt from NACE MR 0175) would require new set of corrosion assessment with credible design cases e.g. insufficient drying case and normal operating case. Pipeline 1 and Pipeline 2 remaining life can be fur- ther extended by repairing the worst defect locations respectively. Consequently, the remaining life can be extended between 1o-20 years. The result of the cor- rosion analysis consequently set the requirement for operational control measures, monitoring as well as repair strategies. This must be performed prior to the decision of using the existing pipeline for CO2 transportation.
58 Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY To meet the requirement to resist RDF can be chal- lenging. We are in the view that the input parameters and ambient temperature are not within the capac- ity e-BTCM software. Further discussion would be re- quired with the software owner. As of current, it ap- pears that rather than flowing in dense phase, it may be wise to consider flowing in gas phase and further re-compression is required at the injection site. This must be proven with cost comparison of purchasing additional compressor against laying new 200km pipeline. The cost discussion can be found in subse- quent section. Material compatibility to H2S only ap- plicable to 9ppm H2S concentration of 130barg MAOP. The H2S limit for the system is 20ppm. 3.7 Pipeline Cost Estimation As explained above this section presents budgetary estimate of an 18in offshore pipeline EPCIC project. Awareness on the pipeline cost shall assist decision maker to decide on the right direction of CCS facility concept. The assumptions are: I. Pipeline size of 18in x 19.05mmWT II. Carbon steel, non-sour, LSAW. III. Distance of 200km from onshore CCS Hub to off- shore injection site. IV. Shore approach construction included. V. Using s-lay installation method. Conservative lay- rate assumption of 1.8km/day. VI. Pipeline life 25 years with 4 nos of intelligent pig- ging operation. High level costing in Table 3 should provide guidance to compare against installing and operating compres- sor option. Also, it can be the input to cost benchmark- ing exercise typically performed in CCS project. Table 2: Superiority of coextruded Tapes Table 3: Cost Estimation for Newly Built Pipeline
4. Conclusion Existing technical frameworks of pipeline repurpose provide sufficient guidance for design engineer to in- itiate the feasibility study. The framework is devel- oped to address technical and safety integrity of exist- ing pipeline. PETRONAS framework of PLES can also be harmonized with repurpose framework suggested by DNV-RP-F104. The feasibility study is useful to es- tablish the limit of existing pipeline capability against future use. With limits in place, detail analysis can be identified accordingly to shed more clarity to pipeline repurpose. Upon completion of detail analysis, tech- nical authority should be able to decide either to pro- ceed or not to proceed on repurpose option. Although the current results have not given clear positive direc- tion, the economic values would justify advancing the study with further technical analyses, material testing and upgrade scope capability of existing software. Studying the feasibility of pipeline repurpose should be the priority when opportunity arises. This can be motivated from challenging economic driver of a CCS development project. Unlike build new option, the technicalities of pipeline repurpose is not as straight- forward. Thus, expert judgement will be required whereby in this case RDF and requirement of mate- rial testing. As reader may find different and unique circumstances when dealing with repurpose, at mini- mum this paper should provide general idea on how to approach pipeline repurpose option. 5. Acknowledgement We would like to acknowledge several key parties who have made important contribution to this study. Among them are Upstream Centre of Excellence (COE), CO2 Focus Area Group of Project Delivery & Technology (PD&T), Flow Assurance Centre (FAC). Also, thanks to Group Technical Solutions (GTS) of PETRONAS that pushes every boundary to deliver the best technical solutions within PETRONAS and outside to a larger industry. References 1. DNV-RP-F104: Design and operation of carbon dioxide pipeline 2. BS ISO 27913: Carbon dioxide capture, transportation and geo- logical storage- Pipeline transportation system 3. API SPEC 5L Linepipe Specification 4. NACE MR-0175 Materials for use in H2S-containing en- vironments in oil and gas production. Pipeline Technology Journal - 1/2023 RESEARCH • DEVELOPMENT • TECHNOLOGY 59 Authors Faisal Aziz PETRONAS Sales lead for Pipeline of the Future program firstname.lastname@example.org Khairul Anuar Karim PETRONAS Head of Pipeline Engineering with GTS email@example.com Ir. Hayati Hussien PETRONAS Custodian of Pipeline Engineering with GTS firstname.lastname@example.org
60 Pipeline Technology Journal - 1/2023 ask the experts Ask the Experts Who are the Experts? The experts are nominated in close cooperation with our partners. DNV is the global independent expert in assurance and risk management. Driven by our purpose, to safeguard life, prop- erty and the environment, we empower our customers and their stakeholders with facts and reliable insights so that critical decisions can be made with confidence. Backed by over 150 years of experience and a global team of energy experts, DNV works with operators, suppliers, governments and industry associations to safeguard life, property and the environment, and to support progress across the entire pipeline industry. We are recognized as the leading advisor in the development and delivery of on- and offshore pipeline services, providing tech- nical expertise and competence across all phases of an asset’s lifecycle from inception, design and development to operation, maintenance, life extension and decommissioning. Over the past century, DENSO Group Germany has built a reputation founded on experience, quality and reliability in corrosion prevention and sealing technology. Just a few years after the company was founded in 1922, DENSO Group Germany revolutionised corrosion prevention across the world with the DENSO®-Tape (Petrolatum-Tape), which was already patented in 1927 as the worldwide first product for the passive corrosion pre- vention of pipelines. Since then, DENSO Group Germany establishes and guarantees the high- est quality standards with technically trend-setting products. Research, development and production take place exclusively in Germany. Today, DENSO is a global group of compa- nies that, in spite of its international reach, still strives to deliver sustainable custom solu- tions and provide personal service to its customers. The group’s core business consists of the development and production of co-extruded 3-ply PE/Butyl-Tapes, Heat Shrink- able Sleeves, Petrolatum-Tapes & Mastics, Jetty Pile Protection Systems, Polyurethane Coatings and Bitumen profiles. The group’s high quality products - made in Germany - are applied in countless rehabilitation projects and new pipeline constructions world- wide. No other company has a longer experience in corrosion prevention for pipelines.
Pipeline Technology Journal - 1/2023 ask the experts 61 What is Ask the Experts? 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. Find out more under: www.pipeline-journal.net/news/ask-experts
62 Pipeline Technology Journal - 1/2023 company directory Association Coating DVGW - German Technical and Scientiﬁc Association for Gas and Water Germany www.dvgw.de IAOT - International Association of Oil Transporters Czech Republic www.iaot.eu PPSA - Pigging Products and Services Association United Kingdom www.ppsa-online.com YPI - Young Pipeliners International International www.youngpipeliners.com Automation FLEXIM GmbH Germany www.ﬂexim.com Penspen United Kingdom www.penspen.com Siemens AG Germany www.siemens.com Siemens Energy Germany www.siemens-energy.com Certification Bureau Veritas Germany www.bureauveritas.com DNV Norway www.dnv.com TÜV SÜD Germany www.tuvsud.com Cleaning Aipu Intelligent Pipeline Technology China www.pipelineip.com Reinhart Hydrocleaning Switzerland www.rhc-sa.ch Denso Germany www.denso-group.com Feromihin d.o.o. Croatia www.feromihin.hr KEBU Germany www.kebu.de Polyguard Products United States www.polyguard.com Premier Coatings United Kingdom www.premiercoatings.com Sulzer Mixpac Switzerland www.sulzer.com TDC International Switzerland www.tdc-int.com TIB Chemicals AG Germany www.tib-chemicals.com Trenton Corp United States www.trentoncorp.com Construction BIL eG Germany www.bil-leitungsauskunft.de Cyntech Group Canada www.cynetechgroup.com Herrenknecht Germany www.herrenknecht.com
Leobersdorfer Maschinenfabrik Austria www.lmf.at LogIC SAS France www.logic-sas.com MAX STREICHER Germany www.streicher.de/en MTS Microtunneling Systems Germany www.mts-tunneling.com Petro IT Ireland www.petroit.com Prime Drilling Germany www.prime-drilling.de Vlentec Netherlands www.vlentec.com Construction Machinery Maats B.V. Netherlands www.maats.com MAX STREICHER Germany www.streicher.de/en VIETZ Germany www.vietz.de Worldwide Group Germany www.worldwidemachinery.com Engineering Cyntech Group Canada www.cynetechgroup.com Dynamic Risk Canada www.dynamicrisk.net Pipeline Technology Journal - 1/2023 company directory 63 Elsyca Belgium www.elsyca.com ILF Consulting Engineers Germany www.ilf.com Leobersdorfer Maschinenfabrik Austria www.lmf.at Maats B.V. Netherlands www.maats.com OGE Germany www.oge.net Penspen United Kingdom www.penspen.com PSI Software AG Germany www.psi.de Siemens AG Germany www.siemens.com STATS Group United Kingdom www.statsgroup.com Inspection 3P Services Germany www.3p-services.com Aipu Intelligent Pipeline Technology China www.pipelineip.com Baker Hughes United States www.bakerhughes.com Distran Switzerland www.distran.swiss Eddyﬁ Technologies Canada www.eddyﬁ.com
64 Pipeline Technology Journal - 1/2023 company directory EMPIT GmbH Germany www.empit.com Entegra United States www.entegrasolutions.com GOTTSBERG Leak Detection GmbH & Co. KG Germany www.leak-detection.de INGU Canada www.ingu.com Intero Integrity Services Netherlands www.intero-integrity.com Kontrolltechnik Germany www.kontrolltechnik.com LogIC SAS France www.logic-sas.com MAX STREICHER Germany www.streicher.de/en NDT Global Germany www.ndt-global.com Online Electronics United Kingdom www.online-electronics.com PPSA - Pigging Products and Services Association United Kingdom www.ppsa-online.com PIPECARE Switzerland www.pipecaregroup.com Pipesurvey International Netherlands www.pipesurveyinternational.com ROMSTAR GROUP Malaysia www.romstargroup.com Rosen Switzerland www.rosen-group.com SONOTEC Germany www.sonotec.eu Spier Hunter United Kingdom www.speirhunter.com T.D. Williamson United States www.tdwilliamson.com TRAPIL France www.trapil.com Integrity Management Aipu Intelligent Pipeline Technology China www.pipelineip.com Direct-C Canada www.direct-c.ca Dynamic Risk Canada www.dynamicrisk.net Eddyﬁ Technologies Canada www.eddyﬁ.com EMPIT GmbH Germany www.empit.com Entegra United States www.entegrasolutions.com FEROMIHIN D.O.O. Croatia www.feromihin.hr GOTTSBERG Leak Detection GmbH & Co. KG Germany www.leak-detection.de Intero Integrity Services Netherlands www.intero-integrity.com
LogIC SAS France www.logic-sas.com Online Electronics United Kingdom www.online-electronics.com Penspen United Kingdom www.penspen.com PIPECARE Switzerland www.pipecaregroup.com Prisma Photonics Israel www.prismaphotonics.com Skipper NDT France www.skipperndt.com T.D. Williamson United States www.tdwilliamson.com TRAPIL France www.trapil.com Leak Detection AP Sensing Germany www.apsensing.com Atmos International United Kingdom www.atmosi.com Direct-C Canada www.direct-c.ca Distran Switzerland www.distran.swiss Eddyﬁ Technologies Canada www.eddyﬁ.com FEROMIHIN D.O.O. Croatia www.feromihin.hr Pipeline Technology Journal - 1/2023 company directory 65 Fotech Solutions United Kingdom www.fotech.com GOTTSBERG Leak Detection GmbH & Co. KG Germany www.leak-detection.de Hiﬁ Engineering Canada www.hiﬁeng.com INGU Canada www.ingu.com KROHNE Germany www.krohne.com OGE Germany www.oge.net OptaSense United Kingdom www.optasense.com Pergam Italia Italy www.pergamitaly.eu Prisma Photonics Israel www.prismaphotonics.com PSI Software AG Germany www.psi.de SENSOTOP France www.sensotop.com SEWERIN Germany www.sewerin.com SolAres (Solgeo / Aresys) Italy www.solaresweb.com TRAPIL France www.trapil.com
66 Pipeline Technology Journal - 1/2023 company directory Materials Monitoring Vallourec France www.vallourec.com Airborne Technologies Austria www.airbornetechnologies.at Direct-C Canada www.direct-c.ca Eddyﬁ Technologies Canada www.eddyﬁ.com Fibersonics United States www.ﬁbersonics.com INGU Canada www.ingu.com KROHNE Germany www.krohne.com Online Electronics United Kingdom www.online-electronics.com Prisma Photonics Israel www.prismaphotonics.com PSI Software AG Germany www.psi.de Skipper NDT France www.skipperndt.com Teren United States www.teren4d.com BIL eG Germany www.bil-leitungsauskunft.de Operators OGE Germany www.oge.net PETRONAS Malaysia www.petronas.com TRAPIL France www.trapil.com Pump and Compressor Stations Repair Baker Hughes United States www.bakerhughes.com TIB Chemicals AG Germany www.tib-chemicals.com CITADEL TECHNOLOGIES United States www.cittech.com Clock Spring NRI United States www.clockspring.com Fangmann Energy Services Germany www.fangmannenergyservices.com KEBU Germany www.kebu.de STATS Group United Kingdom www.statsgroup.com Research & Development Energy & Corporate Africa United States www.energycorporateafrica.com Spier Hunter United Kingdom www.speirhunter.com Leobersdorfer Maschinenfabrik Austria www.lmf.at
Safety Trenchless Technologies Pipeline Technology Journal - 1/2023 company directory 67 Baker Hughes United States www.bakerhughes.com BIL eG Germany www.bil-leitungsauskunft.de DEHN & SÖHNE Germany www.dehn-international.com Distran Switzerland www.distran.swiss Dynamic Risk Canada www.dynamicrisk.net FEROMIHIN D.O.O. Croatia www.feromihin.hr Franken Plastik GmbH Germany www.frankenplastik.de KROHNE Germany www.krohne.com OVERPIPE France www.overpipe.com Siemens AG Germany www.siemens.com Skipper NDT France www.skipperndt.com TÜV SÜD Germany www.tuvsud.com Franken Plastik GmbH Germany www.frankenplastik.de Signage Glinik Drilling Tools Poland www.glinik.com.pl GSTT - German Society for Trenchless Technology Germany www.gstt.de IMPREG GmbH Germany www.impreg.de KEBU Germany www.kebu.de Rädlinger Primus Line Germany www.primusline.com Vaishvi Engineers India www.vaishviengineers.com Valves & Fittings AUMA Germany www.auma.com T.D. Williamson United States www.tdwilliamson.com Zwick Armaturen Germany www.zwick-armaturen.de Pipeline Technology Journal Further boost your brand awareness and list your company within the ptj - Company Directory www.pipeline-journalnet/advertise