World Pipelines November 2023 by PalladianPublications

Volume 23 Number 11 - November 2023

The leading innovator supplying cutting-edge integrity solutions. Together we can ensure sustainable decision-making. Our combination of advanced inspection systems and expert consultants delivers a comprehensive understanding of asset safety, lifetime, and performance.

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CONTENTS WORLD PIPELINES | VOLUME 23 | NUMBER 11 | NOVEMBER 2023 03. Editor's comment 05. Pipeline news

With updates on Balticconnector, the Pacific Northwest pipeline, Trans Mountain and offshore pipeline contract news.

REGIONAL REPORT: AUSTRALASIA 08. Connecting the dots

World Pipelines talks to Wood about how Australia’s pipelines are playing a critical role in digitalisation and decarbonisation efforts.

COVER STORY 13. A comprehensive approach to compliance

ENERGY TRANSITION 31. Pipelines are key in the energy transition Dr Jens Tronskar, DNV Energy Systems, Singapore.

UNDERWATER INSPECTION 35. Beneath the surface Jonathan Bancroft, TSC Subsea, UK.

INTEGRITY AND INSPECTION 38. Traversing satellite technologies Lucy Kennedy, Spottitt, UK.

Russ Davis, MISTRAS Group, USA.

FLOW 17. Measuring multiphase flow

Information obtained from satellite data is crucial for understanding risks and changes which can lead to structural failures in pipelines, says Lucy Kennedy, CEO and Co-founder, Spottitt, UK. lobally, oil and gas transmission pipelines span a total length of 2.15 million km and are projected to grow by over 5% by 2027, equivalent to circling the Earth 53 times. Europe alone accounts for approximately 200 000 km of gas transmission pipes. These figures specifically refer to transmission pipelines, which form the backbone of the system, the final distribution lines to residential and commercial areas are excluded. Throughout history, underground construction has been the prevailing choice for oil and gas pipelines, driven by factors like external protection, safety considerations, and aesthetic preferences. While overground pipelines are less common, they are found in specific regions or for particular purposes. In most cases, the underground network lies at a depth of just 1 - 1.8 m beneath the surface.

Dr Craig Marshall, TÜV SÜD National Engineering Labatory, UK.

LEAK DETECTION 20. Fail to plan, plan to fail

Ageing infrastructure and outdated standards The longevity of many pipelines is remarkable, with many dating back to the 1950s and 1960s, a period when the global pipeline network expanded rapidly to meet the soaring energy demands of the post-WWII era. Some pipelines even predate this time, resulting in an average pipeline age of approximately 70 years today. Compounding the ageing issue is the fact that pipelines built on average 70 years ago were designed for the climate conditions, safety and leakage standards of 70 years ago. However, these standards and conditions have since become outdated, and are no longer applicable.

Phil Edwards, Atmos International, UK.

Risks and consequences The operation of oil and gas transmission pipelines entails inherent risks associated with the potential for unintentional product releases. Oil and gas product releases have traditionally been treated as safety issues due to the risk of explosions and asphyxiation, but increasingly the environmental impact of unintentional product releases is fast becoming the key risk, to be

FAIL to plan, plan to FAIL

reduced and avoided via leak detection and repair (LDAR) programmes. All pipelines are vulnerable to stresses and strains caused by movement of the land resulting from ground settlement, soil erosion, nearby excavation or construction and agricultural activities. In the past decade, external interferences, corrosion, construction defects, and ground movement accounted for 27%, 27%, 16%, and 16% of reported pipeline incidents, respectively. Other factors, such as operator control failure or lightning strikes, can also result in damages to pipeline integrity. Pipeline accidents are high-impact events that not only cause material and financial losses to the infrastructure owner but also pose significant risks to people and the environment. Pipeline damage can also lead to business interruptions and supply disruptions, particularly critical during the winter season. In respect of environmental damage, methane (CH4), a major component of natural gas, is a potent greenhouse gas (GHG) whose presence in the atmosphere contributes to global temperature rises and climate changes. Methane remains in the atmosphere for approximately 12 years and has a warming effect 86 times greater than carbon dioxide (CO2) over a 20 year period.

Regulation drives improved pipeline infrastructure management Transmission pipeline operators have always implemented measures to minimise the risk of releases and mitigate their consequences. These measures encompass careful pipeline route selection, design, construction, operation, and maintenance, along with the deployment of automated monitoring and control systems. But netzero goals are driving major changes in the landscape of both public perception and regulation, which is in turn, fuelling investment in improved pipeline infrastructure management on both sides of the Atlantic. While proposed methane emission reduction regulations in the US and the EU share common elements,

PAGE 38

44. Pigging and pressure Dr. Claudio Zanghì, Saipem, Italy.

Phil Edwards, Technical Manager, Atmos International, UK, discusses how the key elements within a trainer system can prepare pipeline operators for the many challenges they face.

47. Monitoring critical assets from afar Matthew Hawkridge, Ovarro.

t can be a challenge exposing pipeline operators to abnormal operating conditions, such as a leak situation. Pipeline control room staff are typically only trained using a real pipeline system and on average are asked to control different pipelines every three years.1 Hands on training in isolation is inadequate and places limits on an operator’s level of preparation when they eventually encounter transient activities like a pump or compressor trip or a leak. A transient is a change in the flow and pressure in a pipeline. While it can be caused by routine activities, such as the starting of a pump or the closing of a valve, it can also be caused by a leak or equipment failure. A variety of new challenges face pipeline operators as we move towards net-zero, so pipeline companies ask the following questions when considering a training simulator to optimise operations: ) How can we provide a safe environment for operators to understand the behaviour of a pipeline leak and the consequences of actions taken?

PAGE

) How will new pipelines behave, particularly carbon dioxide (CO2) ones,

and what operating practices should we have?

OFFSHORE AND SUBSEA 25. Midstream in motion

Joonas Arola, Pemamek Ltd, Finland.

WRAPS AND TAPES 55. Before it's too late

Jo Anne Watton, UTComp, Canada.

Kapil Garg, MarketsandMarkets, India.

27. Fast tracking carbon reduction targets Hugues Chuffart, Fugro, Netherlands.

AUTOMATIC WELDING SYSTEMS 51. Unleashing productivity in pipe production

PRECOMMISSIONING 59. Pressure drop? No problem

Pooya Gholami, Iranian Offshore Oil Company, Iran.

ON THIS MONTH'S COVER

Volume 23 Number 11 - November 2023

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“C

alifornia is coming for your pools”, says Politico.1 The state of California is making efforts to reduce power usage in the evenings, since that is when the state uses the most natural gas. The California Energy Commission voted on 18 October to require residential pools to be able to shut off their electricity when the grid instructs them to. “Starting in September 2025, all pool pumps sold in California will have to be able to connect to the internet and operate by default from 9 am to 3 pm. Anyone building a new swimming pool at home [...] or replacing their pump will have to install SENIOR EDITOR Elizabeth Corner the new version, but will still be able to use the pump elizabeth.corner@palladianpublications.com outside daytime hours.” The smart pumps are expected to reduce the state’s total greenhouse gas emissions by 0.5% and it’s hoped that by 2033, the state could gain over 500 MW of power by shutting off pool pumps (enough to power about half a million homes). A pair of new California laws concerning corporate climate disclosures were signed into law in October, requiring companies that are active in the state and generate revenue of more than US$1 billion annually to publish an extensive account of their carbon emissions starting in 2026. Reuters reports that, “The SEC has drafted its own rules, which would not go as far, giving companies discretion over disclosing some emissions they deem not material or not pertaining to their emission reduction targets. The SEC’s rules would apply to all US-listed companies”.2 This kind of mandated reporting seeks to hold companies to account for disclosing scope 1 and 2 emissions, along with scope 3 (emissions resulting from the use or disposal of their products). Under the spotlight currently is ExxonMobil’s US$60 billion bid for Pioneer Natural Resources, set to expand ExxonMobil’s footprint in the USA’s biggest oilfield. The much talked about acquisition has raised questions for shareholders over the company’s commitment to transitioning to low-carbon energy. ExxonMobil has “sought to play up the environmental benefits [of the deal] saying it will shave 15 years off Pioneer’s target to reduce operational emissions to net zero by 2050. It also pledged to apply technologies to monitor, measure and address fugitive methane emissions from operations”.3 Smart technology, in combination with regulation, is one way to control energy use and meet netzero targets. It requires compliance, and oversight, but it packs a punch when properly enacted. This month’s cover story, written by MISTRAS (p. 13), focuses on compliance: offering guidance on how to achieve ‘Mega Rule’ compliance by meeting the requirements on pipeline material properties and MAOP. PHMSA’s 2020 revisions to 49 CFR 192 Part 1 seek to increase the level of safety associated with the transportation and operation of onshore gas transmission pipelines. Read the article to find out how we can use data collection tools to meet requirements by the regulatory due dates. The pipeline industry is primed to benefit from using digital, or smart, solutions to meet regulations and standards. In this issue we cover: how operators are using digital and decarbonisation solutions to meet net-zero goals (Wood, p. 8); how training systems can help pipeline control personnel recognise and react to abnormal operating conditions (Atmos International, p. 20); and where remote monitoring and Edge computing can make a difference to pipeline efficiency and safety (Ovarro, p. 47). DNV’s article on hydrogen and CCS transportation standards (p. 31), along with Fugro’s piece on the Aramis CCS project (p. 27), provide a look at the pipeline transport standards of the future. Of course, in CCS news this month, Navigator CO2 Ventures cancelled its Heartland Greenway pipeline project, designed to capture 15 million tpy of CO2 from Midwest ethanol plants for permanent storage underground. The 2092 km pipeline would have traversed five US states. The company cited “unpredictable” state regulatory processes as the reason for cancellation. 1. 2. 3.

www.politico.com/newsletters/california-climate/2023/10/18/california-is-coming-for-your-pools-00122374 www.reuters.com/sustainability/companies-fear-lawsuits-californias-climate-disclosure-rules-2023-10-12/ www.thechemicalengineer.com/news/exxonmobil-gambles-us-60bn-on-shale-oil-buyout/

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WORLD NEWS Balticconnector pipeline damaged After a leak led to the shutdown of the Balticconnector pipeline on 8 October 2023, Finnish authorities have been investigating the damage they say was caused by external activity. Authorities in Finland and Estonia, whose state-run companies own and operate the Balticconnector pipeline, have said that the damage appeared to be caused by “mechanical force” and that it may have been a deliberate act. Finnish police have said a Chinese ship, whose movement coincided with the time and place of the suspected sabotage of the pipeline between Finland and Estonia, is now the focus of their investigation. The National Bureau of Investigation said it was investigating Newnew Polarbear and a Russian ship, Sevmorput, both of which they said were in the area at the time of the incident.

“The movements of the vessel Newnew Polar Bear flying the flag of Hong Kong coincide with the time and place of the gas pipeline damage,” Finland’s National Bureau of Investigation said. Police also confirmed the damage was caused by “an external mechanical force” and that they had found “a heavy object” near the damaged pipeline. The pipeline, which can export in either direction depending on where demand is greatest, was transporting a volume of around 30 GW/h of gas per day from Finland to Estonia at the time of the incident Alarm was raised in Europe after the natural gas pipeline and a communications cable in the Baltic Sea was damaged. It will take at least five months to repair the pipeline, its operator said, leaving Finland totally dependent upon LNG imports for the winter.

FERC approves Pacific Northwest gas pipeline expansion The Pacific Northwest gas pipeline expansion has been approved by US federal regulators. The Gas Transmission Northwest, or GTN XPress pipeline project, will increase the ability to transport methane gas from Canada to West Coast states and Idaho. Since first being proposed in 2019 the project, from operator TC Energy, has met wth opposition. The decision to install three new compressor stations along the pipeline route will increase reliability and capacity to ship gas.

The pipeline upgrades approved will allow for the additional transport of approximately 150 million ft3/d of additional methane gas for use in Washington, Idaho, Oregon and California. “The GTN XPress project will play a critical role in keeping energy affordable and reliable for consumers in California and the Pacific Northwest. We appreciate FERC’s bipartisan action today to approve the project and will work diligently to place it into service as soon as possible,” said Michael Tadeo, a spokesperson with TC Energy.

NNPC to deliver pipeline project by July 2024 NNPC Limited and its contractor for the US$2.5 billion AjeokutaKaduna-Kano (AKK) gas pipeline, Oilserv Limited, have vowed to deliver the 614 km gas pipeline project by July 2024. The assurance was given 12 October 2023 during an inspection tour of the project by the Minister of State for Gas, Ekperikpe Ekpo, at the Pai River crossing session in Kwali Area Council of the Federal Capital Territory, Abuja (Nigeria). Addressing the minister on the occasion, the Group Chief Executive Officer of Oilserv Group of Companies, Engr. Emeka Okwuosa, explained that the Pai River crossing was particularly

challenging, hence the deployment of HDD technology to ensure the perfect execution of the project. Responding to the question of when the job would be completed, he said: “From our schedule, I know we are finishing next year. On the main pipeline itself that will deliver the gas, we are optimistic that by July, or August next year, we would be done. We have our schedule as far as where we are today and we are working hard to mitigate and make sure we deliver. A lot of what we have to deal with in the next six months will be the river crossing area.”

Trans Mountain oil pipeline 90% complete The Trans Mountain oil pipeline is nearly finished and will be “complete in the coming months,” Canadian Minister of Energy and Natural Resources Jonathan Wilkinson told reporters on Friday 13 October 2023. “I don’t have a specific date in front of me in terms of when the corporation expects to complete it, but the project is over 90% complete,” Wilkinson shared, adding that he certainly expects it to come online “over the course of the 2024 period.” Wilkinson pointed to various delays that have plagued the expansion project, the costs of which have grown to an estimated CAN$30 billion.

The pipeline is once again moving ahead after securing a legal victory after being challenged in court by the Stk’emlupsemc Te Secwepemc Nation First Nation over the pipeline’s newly proposed route that would go through a 0.8 mile segment of the indigenous group’s territory. Canada’s regulator CER ruled in favour of the pipeline, thus preventing futher delays. Once complete, the newly expanded pipeline will be able to carry an additional 890 000 bpd of crude oil. Canada is hoping to complete the sale of the pipeline in 2025.

NOVEMBER 2023 / World Pipelines

CONTRACT NEWS EVENTS DIARY 2 November 2023

3rd Global Hydrogen Conference VIRTUAL EVENT https://www.accelevents.com/e/3rdghc2023

14 - 15 November 2023

Gas, LNG & The Future of Energy Conference London,UK https://www.woodmac.com/events/gas-lngfuture-energy/

30 January - 3 February 2024

76th annual PLCA Convention 2024 Nassau, Bahamas https://www.plca.org/annual-convention-events

12 - 16 February 2024 PPIM 2024

Houston, USA https://ppimconference.com/exhibition/

13 - 15 February 2024

AMI Pipeline Coating Vienna, Austria https://www.ami-events.com/

3 - 7 March 2024

AMPP Annual Conference + Expo 2024 New Orleans, USA https://www.ampp.org/

8 - 11 April 2024

Pipeline Technology Conference (ptc) 2024 Berlin, Germany https://www.pipeline-conference.com/

15 - 19 April 2024

TUBE Düsseldorf 2024 Düsseldorf, Germany https://www.tube-tradefair.com/

6 - 9 May 2024

Offshore Technology Conference (OTC) 2024 Houston, USA https://2024.otcnet.org/

6 World Pipelines / NOVEMBER 2023

Saipem wins contracts worth E850 million offshore Italy and Ivory Coast Saipem has secured two new contracts worth €850 million (US$910.6 million) in Italy and Côte d’Ivoire (Ivory Coast). The first contract, which has been awarded by Eni Côte d’Ivoire and its partner Petroci, is for the Baleine offshore oil and gas field. Saipem will supply subsea umbilicals, risers and flowlines for the development of the Baleine Phase 2 project. The scope of the contract includes the engineering, procurement, construction and installation (EPCI) of roughly 20 km of rigid lines, 10 km of flexible risers and jumpers, and 15 km of umbilicals connected to a floating unit. Saipem’s offshore construction vessels will carry out the installation work in 2024. The oilfield services provider was also contracted the drilling work for Baleine

Corinth Pipeworks awarded Snam offshore contract Corinth Pipeworks has been awarded a contract by Snam to manufacture and supply approximately 13 km of longitudinally submerged arc-welded steel pipes (LSAW) for the development of an offshore and onshore natural gas pipeline for the floating storage and regasification unit (FSRU). The contract is valued at over €10 million. The greenfield FSRU based LNG terminal project in the port of Ravenna is a strategic project to help ensuring Italy’s energy needs, increasing security of supply and diversification. Further-more, the project will provide critical infrastructure, with a capacity of 170 000 m3 and a nominal throughput of 5 billion m3/yr of natural gas. The 26 in. pipeline, will be certified to transport up to 100% hydrogen. Corinth Pipeworks is utilising cutting-edge technology and infrastructure, providing solutions for hydrogen certification of new pipelines. Steel pipes will be manufactured at Corinth Pipeworks’ facilities and will include internal and three-layer polypropylene, external coating, as well as concrete weight coating (CWC), applied at the same location as pipe manufacturing at Thisvi, Greece. This award to Corinth Pipeworks is the latest from Snam, with the assistance of its Italian business partner PIPEX, and builds on the company’s successful long-term relationship and a succession of earlier pipeline developments.

Phase 1. The second contract entails building the infrastructure for a new floating storage and regasification unit (FSRU) in the Adriatic Sea off the coast of Ravenna, Italy. It has been awarded to Saipem by Snam Rete Gas. The work involves the EPCI of a new offshore facility for the docking and mooring of the FSRU, which is connected to the existing one. The new facility will be connected to shore by a 26 in. offshore pipeline measuring 8.5 km in length, as well as a 2.6 km onshore pipeline and a parallel fibreoptic cable. Castoro 10, a pipelay barge owned by Saipem, will perform offshore operations and the new FSRU is expected to increase Italy’s capacity to import LNG, said Saipem.

ON OUR WEBSITE • Calls for EU to drop funding

for Malta pipeline intensify • Nigeria replaces broken

pipeline with tiny tankers • Canada’s Trans Mountain oil

pipeline expansion could face nine month delay • Aramco considers bidding

for Shell’s assets in Pakistan • Ocyan wins contract with

Petrobras • IEA oil report: geopolitical

risks to keep markets on edge Follow us on LinkedIn to read more about the articles linkedin.com/showcase/worldpipelines

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A World Pipelines talks to Wood about how Australia’s pipelines are playing a critical role in digitalisation and decarbonisation efforts.

cross Australia, the energy industry is directing its attention to critical decarbonisation projects that will pave the way for future sustainable operations. Much like other regions around the world, operators here are striving to achieve the delicate balance between ensuring energy security to provide power to local communities while enabling the energy transition. Regulation, both previously enacted and anticipated, is playing a leading role in the net-zero goals operators are setting for themselves. For example, Australia’s National Greenhouse and Energy Reporting Act is driving a reduction in emissions baselines by 4.9% each year before 2030. For energy leaders to achieve these ambitious targets, they are seeking ways to reduce their emissions with digital and decarbonisation solutions.

The critical role pipelines play While LNG is considered a sustainable energy source by the United Nations, there are still some emissions associated with LNG production. Carbon capture, transport and storage (CCS) is one such method of reducing those emissions. “We see CCS as a big growth area in Australia and are currently working on several projects, like the conceptual design phase in CCS hubs”, said Enda O’Sullivan, Director of Oil and Gas for Wood’s Asia Pacific region.

Another low carbon method of producing energy that is becoming increasingly more common is green hydrogen. Since no emissions are produced in the production of green hydrogen, there is a big initiative to create an export industry from Australia. Pipelines play a critical part of the infrastructure required to support this push. “At Wood, we specialise in capturing and transporting gases through pipelines,” said O’Sullivan. “While the molecule that’s being transported may change from methane to carbon dioxide to hydrogen, the fundamental design of the facilities required remains the same, and our industry expertise is transferrable from one energy source to another.”

Digitalising before decarbonising Decarbonisation is inextricably linked to digitalisation; we cannot decarbonise without digital solutions. Existing technologies house the potential to cut three-quarters of methane emissions from oil and gas production at no net cost to operators. By first using digital tools to actively identify and manage sources of greenhouse gas emissions in real-time, operators can harness data to identify the optimum pathway for an asset to achieve its carbon reduction goals.

Wood has applied its proprietary decarbonisation SCORE methodology (Figure 1) to clients around the world, delivering roadmaps that enable 15 - 20% reductions in Scope 1 and 2 carbon dioxide equivalent emissions. This decarbonisation SCORE methodology assesses the substitution, capture, offsetting, and reduction options and evaluates (SCORE) the economic and operational potential for operators. An example of decarbonising clients’ assets across the full lifecycle of a project can be observed with Wood’s work on the INPEX project in Perth, in which Wood supported the delivery of a 65 km digital twin inclusive of four years of operating history. Wood has worked with INPEX for nearly 20 years and has been a key partner in supporting INPEX every step of the way on the Ichthys project, from development through to production, operation, and now, expansion. “Since 2005, we have worked on the Ichthys project in Australia and have seen the whole of Wood involved in some way over the years from our consulting team analysing the pipeline behaviour and conducting the FEED for the offshore facility to our projects team assessing the rotating equipment and detailing the design of the offshore central processing facility,” said O’Sullivan.

Figure 1. SCORE methodology.

Initially, the first expansion project took place in 2018, where Wood designed the central processing facility topsides modifications to connect new wells. A 100 000 hour engineering effort was delivered by the Wood team on this phase of the project. Today, Wood has 150 engineers across the company supporting INPEX and the team is growing rapidly, ramping up for the next phase of the project. The team has delivered over 300 000 hours on this project, which is currently scheduled for completion in 2025. An example of implementing a digital solution to improve operational efficiency can be observed with AutomatedDesign, Wood’s platform for digitisation and automation of core engineering capabilities. It acts as a single source of truth for design data, automates engineering workflows including all associated quality assessment requirements and facilitates delivery. “Over 10% of the world’s offshore natural gas is monitored and controlled using Wood’s proprietary software, which equates to 40% of Australia’s LNG,” said O’Sullivan. The initial implementation of AutomatedDesign was for projects relating to energy security, including offshore pipelines, but it’s now being considered in applications for clean energy projects with hydrogen and carbon dioxide pipelines, carbon capture and underground storage and energy yield analysis for windfarms.

Importance of local expertise There are unique challenges to subsea developments in Australia to where what is considered industry standard and works well

10 World Pipelines / NOVEMBER 2023

in other geographic locations may not work in this region. For example, the temperature variation of the water column is such that there is a greater level of marine life activity closer to the seabed than in other regions. Additionally, the seabed in Western Australia is mobile, meaning bottom founded pipelines and structures face unique stability challenges. “This is why local expertise is so critically important, and why at Wood, we are committed to improving the industry’s understanding of these unique conditions in Australia,” said O’Sullivan. “Wood has been in the region for nearly 40 years, and we have worked on over 90% of the subsea pipelines across Australia.” Collaboration in the form of joint industry projects (JIPs) is one way in which Wood assists the industry in evolving our understanding. Through the Subsea Equipment Australia Reliability (SEAR) JIP, Wood is collaborating with five major Australian based operators to address these challenges. This unified industry provides opportunities for standardisation, life extension and development of new technologies. Additionally, Wood participates in the TIDE research hub, which supports fundamental research into pipeline and seabed interaction, with the company’s role being the application of the research to real life problems. Through its digital and decarbonisation solutions that support clients working to deliver on their net-zero ambitions, and the industry collaborations it is participating in, Wood is tackling the complex challenges in Australia’s energy industry, with a focus on designing a better future.

See it. Believe it. Trust it. To advertise email Chris Lethbridge at Chris.Lethbridge@worldpipelines.com or Daniel Farr at Daniel.Farr@worldpipelines.com

Russ Davis, MISTRAS Group, USA, writes about how to achieve ‘Mega Rule’ compliance by meeting the requirements on pipeline material properties and MAOP.

COVER

n 1 July, 2020, the Pipeline and Hazardous Materials Safety Administration (PHMSA) revisions to 49 CFR 192 Part 1 – popularly known as the ‘Mega Rule’ – went into effect. This includes pipeline material verification and maximum allowable operating pressure (MAOP) reconfirmation, and records required to reconfirm MAOP must be traceable, verifiable, and complete (TVC). However, where records are not traceable, verifiable, and complete for the pipeline material of construction, the owner must

ST O

RY 13

perform material identification. Records required to be verified include: ) Diameter. ) Wall thickness. ) Seam type. ) Pipe material grade (yield strength (YS), ultimate tensile

strength (UTS), pressure rating of valves and flanges, etc). ) Pipe material charpy V-notch toughness values.

There are multiple methods for gathering the data required to reconfirm MAOP, but the preferred method is to utilise in-situ non-destructive methods. This methodology can be performed at opportunity digs by qualified technicians utilising approved tools, or by a prescriptive approach (scheduled repairs, excavations, etc.). The prescriptive approach consists of 1 excavation per mile, or 150 excavations, if comparable population is more than 150 miles.

Figure 1. Quantitative risk models help to assess the current and future condition of the pipeline, along with the consequences of a potential failure, to help operators make confident integrity management decisions.

Figure 2. Advanced hardness, strength, and ductility (HSD) services can provide TVC records for missing integrity data to allow full utilisation of the MAOP, enabling additional pipeline capacity.

14 World Pipelines / NOVEMBER 2023

The scope of the new regulations, the lack of overall industry guidance, and often incomplete historical integrity records, have left many operators struggling with how to utilise their resources most effectively to achieve compliance. With so many different disciplines required to reach compliance – ranging from nondestructive examination (NDE) and inline inspection (ILI) material classification, to in-ditch material verification and engineering support services for establishing material verification programmes – operators typically require support to implement these programmes. Operators can benefit from working with a third-party service provider – like MISTRAS Group, a One Source provider of asset protection solutions – with the engineering expertise and complete solution toolbox required to achieve ‘Mega Rule’ compliance.

NDE methods and tools It is critical that qualified companies train, test, and provide qualified and certified technicians to perform testing with PHMSA-approved tools for data collection. Experienced service providers typically invest considerable resources in training quality technicians and in purchasing tested and qualified tools to accurately collect data in-situ at opportunity and scheduled dig sites. The tools required to accurately collect material of construction data must be validated by a subject matter expert (SME) as comparable to destructive testing results for material of comparable grade and vintage. The NDE method must conservatively account for measurement inaccuracies and uncertainties using engineering tests and analyses. The NDE method must also use test equipment that has been properly calibrated for comparable test materials prior to each usage. In May 2018 the Pipeline Research Council International (PRCI) released a report titled ‘Validation of In-Situ Methods for Material Property Determination’. The report provided a summary of test protocols applied and the performance results from various techniques. The Massachusetts Materials Technologies (MMT) ‘Hardness, Strength, and Ductility (HSD)’ advanced non-destructive material verification solution was tested by PRCI, and they found that the HSD was marginally the best technique with the lowest mean absolute percentage error (MAPE), highest correlation coefficients, and highest quantity of data within the specified error bands for both yield strength (YS) and ultimate tensile strength (UTS) of the methods tested. The HSD utilises frictional sliding of four styluses to gather data and a proprietary algorithm to determine YS and UTS. It is important to work with a service provider with certified technicians experienced in using this NDE technology. The HSD tool provides quality data for reconfirmation of MAOP and determination of ERW seam weld classification and seam toughness.

MAOP MAOP must be determined per the requirements of 49 CFR 192.619(a) for any steel pipelines that do not have TVC

documentation for any of the variables necessary to calculate designed MAOP. An operator may also determine to use the guidance provided by 49 CFR 192.620 “alternative maximum allowable operating pressure for certain steel pipelines.” These methodologies are conservative in the determination of MAOP. By collecting the variables necessary for calculating MAOP per the formulas in ASME 31.8, owners/ operators can document the full allowable MAOP and not be required to follow the conservative approach to determine MAOP. Advanced HSD tools can provide TVC records for missing YS and UTS data to allow full utilisation of the MAOP, thereby giving operators additional capacity in the pipelines they operate. Expert service providers, like MISTRAS, have a crew of qualified pipeline engineers who can lead the required data collection activities and perform the MAOP calculations for owners/operators to meet the requirements of 49 CFR 192.

) Focusing on what is driving risks higher.

Engineering critical assessments (ECA) for MAOP reconfirmation, critical flaw size determination and metal loss defects

Working with an experienced service provider, operators gain access to a risk team that includes diverse skills and experience to support a variety of risk management needs, including: ) Data collection, consolidation, and preparation.

A service provider that offers pipeline integrity engineering experts in addition to geographic information system (GIS) software and services is best suited to perform the ECA per 49 CFR 192.632. By utilising the data collected from the owner/operator and in-situ materials data collection, a wide variety of data can be integrated to support information analysis and risk assessment. Some key areas that must be consumed as part of the data analysis include: ) Pipe material properties.

) Evaluating risk reduction using ‘what-if’ analysis and

mitigation planning. ) Producing reports, maps, dashboards, and other visuals

to communicate and document findings. Designed for transmission pipelines, this type of risk model is also suitable for gathering and distribution systems with adequate data to support quantitative risk. Mature models, like the quantitative risk assessment (QRA) variance that runs on New Century Software by MISTRAS’ Spatial Risk Analyst platform, produce exceptional results and have passed many regulatory audits. However, perfecting a digital twin is an evergreen process.

Supporting services

) Adaptation to company data sources, data models, and

domain types. ) Customisation of algorithms. ) Verification and validation of model results.

) Product characteristics.

) Customised maps, dashboards, and other visualisations.

) Operating conditions.

) Risk analysis to develop insights, identify issues, and

propose actions. ) Environmental conditions. ) Facilitating development of company risk criteria. ) Pipe and coating condition assessments. ) Integrating risk management within the integrity ) Engineering and corrosion management surveys.

management process.

) Cathodic protection data.

) Updating integrity management plans.

) Population impacts and encroachment.

Comprehensive programme for MAOP reconfirmation

) Natural hazards.

By utilising the complete toolbox delivered by qualified engineers, certified technicians, tested and validated tools for in-situ testing, and risk modelling software written specifically for meeting the requirements of 49 CFR 192, owners/operators can meet the PHMSA requirements by the regulatory due dates. Additionally, service providers can supply engineering and qualified technical resources to augment owner/operator needs. A lack of resources and having access to the proper tools should not be a roadblock when it comes to meeting this new set of regulations, as an experienced service provider, like MISTRAS, is ready, willing, and able to help you meet your critical compliance needs.

This information is used to feed algorithms that create a digital twin of the pipe and its environment. The current and future condition of the pipeline is modelled along with the consequences of a potential failure to estimate risk. The outputs of such models are quantifiable and verifiable units of risk (in $/y or $/mile per year) that can be used to make confident integrity management decisions. Benefits of this approach include: ) Identifying potential pipeline integrity threats. ) Zeroing in on the highest-risk areas.

16 World Pipelines / NOVEMBER 2023

ENHANCING SAFETY AND CONTINUOUS IMPROVEMENT IN PIPELINE OPERATIONS

PIPELINE SAFETY MANAGEMENT SYSTEM ASSESSMENT PROGRAM

Enhances safety and operations

Provides shared learnings and benchmarking across the industry

Strengthens safety management systems for individual operators

A C O M M I T M E N T T O A C U LT U R E O F S A F E T Y A N D C O N T I N U O U S I M P R O V E M E N T

To learn more about the Pipeline SMS Assessment Program and take your first step toward your assessment, visit: www.API.org/PipelineSMS

© 2023 – American Petroleum Institute, all rights reserved. API, Pipeline SMS, the API logo and the Pipeline SMS logo are trademarks or registered trademarks of API in the United States and/or other countries. API Marketing & Communications: 2023-108 | PDF

Dr Craig Marshall, Consultant Engineer, TÜV SÜD National Engineering Laboratory, UK, discusses the importance of multiphase flowmeters and their verification. ver 10 000 multiphase flowmeters (MPFMs) have been purchased by the oil and gas industry over the past three decades, which constitutes a significant investment in sensing and measurement technology. This investment is not squandered, and has been shown that accurate and timely production flowrate measurements can help to optimise reservoir long-term recovery, as well as being more economically beneficial. But what are MPFMs, how have they been used in the oil and gas industry, and more importantly, how can we have confidence in the measurements they provide?

Multiphase flow Multiphase flow is the simultaneous flow of different fluid phases within a pipe or flowline. In the oil and gas industry, this typically represents the flow of liquid hydrocarbons, liquid water and gaseous hydrocarbons all together in a dynamic mixture. The two liquid components are immiscible, with water usually having a larger density. Gravity attempts to separate the fluids into their three distinct regions, but the energy from the flowrate and physical installation enables mixing of all phases together into various distributions called flow regimes. The different magnitudes of mixing and separation result in several flow regimes being possible with one dominating under specific process conditions. For instance, at lower flowrates, separation usually dominates, and the individual components flow in distinct regions within the pipe, i.e. water on bottom, hydrocarbon liquid in middle with gas on top (separated by increasing density). At higher flowrates, the fluid could be extremely well mixed and flow as a homogenous mixture. To further complicate the situation, the quantity of each phase is important too – if there is more liquid than gas, flow can be described as bubbly; if there is much more gas than liquid, then the process is described to be a wet gas with droplets of liquid in a gas continuous phase. This demonstrates just how challenging the measurement of multiphase flow can be. There are a great number of variables to account for and considerable practical constraints to include, such as contaminants and impurities. Many manufacturers of MPFMs have risen to meet the

challenge by designing topside and subsea modules to provide their best estimate of production flowrates.

Real-time monitoring Before the widespread implementation of MPFMs, and still in place today where they are not installed, well production rates are monitored by periodic well testing. This involves the use of a test separator and the well under test being directed to it for a short period: around 2 - 3 days depending on distance from facility. These systems are usually accurate if properly maintained, however, the main drawback is the periodicity of the test. If a well increased water production between well tests, this would not be picked up until the next well test. This leads to production inefficiencies and increased costs. Real-time monitoring of wells is therefore of considerable importance to controlling, and more importantly, optimising production rates. MPFMs play a critical role and have enabled end users to improve performance. Aside from improving production rates, further benefits of measuring multiphase flow in real-time can be observed from how the data is used and what decisions can be made based on the values. Production rates are sometimes used for allocation measurements, i.e. adjusting flows in comingled systems, and are the basis of how much a producer gets paid for their fluids. The impact of inaccurate measurement in this instance is clear as financial losses are more clearly evident.

Verification With advances in technology and changes in oil prices, it is becoming more economically viable for smaller fields that were once too costly to produce to come online through the use of tiebacks. MPFMs play a vital role in these instances as they enable monitoring and control, and sometimes allocation of produced fluids where there is little infrastructure to employ a more traditional method e.g. a test separator. It is clear that MPFMs have provided a valuable tool for industry to improve their operations. However, like any measurement technology, it needs to be verified in order to trust the results that it gives. The most common way to verify an MPFM currently is by using that same infrastructure that it replaced – the test separator. This time, the periodic nature of the test is not a major issue as the measurements are still being undertaken in real-time during operation. This method also helps

Figure 1. Verification of measurement technology is essential.

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alleviate the stress on a test separator used when no MPFMs are present as it is normally constantly in operation, leaving little to no time for verification of its own measurement sensors. With less time constraints it is easier to ensure the test separator is properly maintained and calibrated. Comparison of the measurements of two different technologies is a tried and tested method of calibration but, with these multiphase applications, there are added complications. The presence of many process interdependent variable measurements can be extremely challenging. Additionally, MPFMs are not always located close to a test separator. There may be many kilometres between the systems which can create significant problems which need to be resolved, for example, line-packing (variability of the mass stored between the systems), pressure and temperature changes, and pressure drop. This is especially true when the fluids have mass transfer between the phases – when molecules may be liquid at one pressure or gas at another. A direct comparison of measured values can sometimes be misleading if all of the above are not considered. Errors can be picked up that do not exist, or ones that do may go unnoticed. A static PASS/FAIL value does not fully allow for changes in MPFM performance in different conditions. To add further difficulty, some sites or tiebacks may not have access to a test separator without first shutting in other wells. This is very unlikely to happen as, besides the technical challenges it causes (start up and shut down of wells), it also accrues loss of revenue for the producer from the closed well. Improved methods are therefore needed to help verify MPFM performance in the field and to provide end users and operators of the technology with confidence in the operation of the field instruments.

Measurement uncertainties One such method proposed by TÜV SÜD National Engineering Laboratory is the introduction of measurement uncertainty into the comparison method and using statistics to justify the PASS/ FAIL criteria used. This will provide more accurate estimates of how well the MPFM performs as it will include the inherent measurement uncertainty of the measurement instruments used – both the MPFM and the reference measurements. The method relies on accurately quantifying the expected performance of the MPFM under near ideal conditions. This could be by basing the performance on the information found in the manufacturer’s datasheet for the product. However, it is often found that these can be more optimistic when compared with physical test work or real-life performance. A better way to quantify the performance is through an in-depth calibration at an accredited flow laboratory with multiphase flows. This allows for realistic process conditions, but with fluids that have well documented physical properties. The results of the calibration can be used to develop an uncertainty budget for the MPFM that provides a range around any measured value where the instrument has a high degree of confidence that the true value lies within. For any sort of calibration or verification, it is vitally important that the test is conducted under appropriate conditions. Namely, flow stability is paramount and should remain constant through any individual test point. This way, the measured values are not

subject to process condition changes as well as the effect of the specific flowing conditions. When taking this method in situ, the same process is applied where one measurement is compared with another. The reference method should also have an appropriate uncertainty budget for its operation. When using a test separator, this is usually much more traditional in nature as there should be single phase flows at the outlets. However, this is not always true, and contamination has to be considered if it’s present. Regardless, any comparison will result in two measured values with associated measurement uncertainties. These values can now be statistically compared and a score can be attributed to the test point.

Zeta-score Score value is called a zeta-score and represents the similarity of the MPFM, and reference measurements given the constraints of the respective measurement uncertainties. A zeta-score of less than 1 shows excellent equivalence between the measurements and they match well with the MPFM within specification i.e. the verification has been PASSED. A zeta-score between 1 and 2 indicates the comparison is satisfactory and within the confidence levels i.e. the verification has PASSED. Lastly, if the zeta-score is larger than 2, this indicates possible errors in the measurements and the verification has FAILED, and remedial action is required. The test can be completed at various flowing conditions to ascertain the full performance of the MPFM. It should cover a number of measured parameters including component volume and mass flows. Any parameter can be verified in this manner

as long as it has a corresponding reference measurement and associated uncertainty. The reference uncertainties can be variable depending on the technology used. Using a larger uncertainty reference can still statistically provide PASS, but the wide range may hide underlying issues that a lower uncertainty reference system would pick up as a FAIL. The method described here is purely based on the statistics of the measurement systems used and as such is independent of technology. Implementing the method will allow for more realistic performance checks and the ability to trend the data over verification checks to predict trends in results over time. The idea is that it also provides end users with a traceable verification method that is independent of technology but also changes with the capabilities of all technology involved. TÜV SÜD National Engineering Laboratory has implemented this technique into a new software suite that also uses digital technologies in the verification process. The software is currently being trialled by major end users and the outputs expected to be published once the trial has ended.

Conclusion Verification of measurement technology is a must for users of sensor technology as it provides them with confidence in their equipment. From simple measurements to complex systems such as multiphase flows, confidence is needed to make decisions on the future of processes, and that is very true in oil and gas where changes in operating conditions can have significant financial implications.

FAIL to plan, Phil Edwards, Technical Manager, Atmos International, UK, discusses how the key elements within a trainer system can prepare pipeline operators for the many challenges they face.

and what operating practices should we have?

plan to FAIL

relying on lessons learned after the fact, it’s important for pipeline operators to understand the behaviour of a pipeline leak before it occurs. Training systems provide a safe environment for operators to better understand the pipeline hydraulics and how their actions, or lack of actions, will impact it. Training sessions can be repeated multiple times until the operator has followed the correct steps. Abnormal operations can also be introduced, which would never or rarely happen on an actual pipeline but prepare operators nonetheless. Figure 1. Basic architecture for a generic training system.

Preparing for the behaviour of new pipelines and setting up the correct operating practices

Figure 3. An example of a training system’s distance based trend showing the hydraulic profile along the full pipeline.

With carbon capture and storage (CCS) becoming a popular method for reducing emissions from industrial processes, pipelines will be crucial in the transportation of CO2 to storage sites during the CCS process, which means leak detection will be too. CO2 transported in these pipelines can take many states, such as a gas or a supercritical fluid at extremely high pressure. Compared with a natural gas pipeline, the explosive decompression of a CO2 pipeline is faster. Leak detection is vital in this case to limit damage to the pipeline’s integrity and reduce interruption to pipeline operations. CO2 is also one of the most damaging greenhouse gases, meaning a leak on a CCS pipeline can cause groundwater contamination, health hazards and a threat to life as well as releasing greenhouse gases back into the environment.2 Applying a training system for a CO2 pipeline would use simulation software to replicate the hydraulic behaviour of the pipeline in the form of a model which represents the network, its instrumentation and equipment, such as pumps and valves. The trainees would receive a front-end view of the simulated values and issue commands, providing them with the necessary training on how to operate a CO2 pipeline before they come into direct contact with the real pipeline (Figure 1). An instructor can also trigger abnormal operating conditions (eg. pump/compressor trips, leaks, station shutdowns, etc) which reduces the likelihood of a poorly handled leak event on the real pipeline.

) How can operators be prepared for new pipeline

Preparing for new pipeline operations with the introduction of hydrogen blends

Figure 2. A graph outlining CO2 as a supercritical fluid.

operations when hydrogen blends are introduced and what is the effect of hydrogen on the pipeline capacity? ) How can the overall risk to real pipelines be reduced?

This article discusses these challenges and how the key elements within a trainer system can prepare pipeline operators for the challenges they face.

Understanding the behaviour of a pipeline leak and the consequences of actions taken A pipeline leak sets into motion a range of events both inside and outside the pipeline, from negative pressure waves propagating in both directions of the pipeline to the integrity of the pipeline weakening as the leak worsens. Instead of

22 World Pipelines / NOVEMBER 2023

The introduction of hydrogen (H2) and hydrogen blends to existing pipeline networks will have a range of impacts on a pipeline network. For example, the molecular makeup of hydrogen is smaller than other natural gases’, meaning product can escape more easily in the event of a leak.3 Pipeline operators need to be able to reskill quickly to fulfil these new pipeline operations, learn how to simultaneously maintain security of supply and accommodate changes in demand and prioritise leak detection. Since hydrogen has a lower energy density than natural gas, its impact on pipeline capacity needs to be understood in order to manage the pipeline operations effectively. Because the introduction of hydrogen to gas pipelines will expose knowledge gaps in both new operators and existing operators, training simulation software has never been more important.

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Training systems enable trainees to understand pipeline hydraulics. Distance based trending can present the user with a view of the hydraulic profile along the full pipeline so flow or pressure changes caused by the introduction of hydrogen and hydrogen blends can be viewed in an interactive format. For example, a UK-based Atmos customer with a pipeline containing multiple inlets and outlets, recently deployed a training simulator to test their SCADA system in an offline environment, simulating the pipeline hydraulics for their network and the programmable logic controller for more than 20 stations.4

Reducing overall risk to real pipelines Because a primary goal of training is increased performance levels, pipeline training systems are flexible to the needs of the pipeline company. If the instructor in charge of the training session wants to stop pumps or compressors unexpectedly or implement a full station shutdown, open pre-configured leak points, training systems typically allow for this level of customisation. This reduces the overall risk to real pipelines in the event of a leak or other abnormal operation, because trainees can be exposed to risks in a range of contexts before encountering them in situ. An operator scoring module often features in a training system, so operators can receive automatic grading based on predefined conditions, such as leaks identified, response to pump trips or amount of time taken to take actions. Paired

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with a training system’s customisation options, the risk to real pipelines is significantly reduced if used appropriately.

Fail to plan, plan to fail Failure to implement a training system before pipeline operators begin operating a real pipeline exposes a pipeline operation, colleagues and the surrounding environment to unnecessary risk, which can all be avoided by planning in advance. As well as supporting with realistic training of all operational scenarios, training systems provide documented evidence of training sessions, performance and training history, which is particularly beneficial in the USA where federal regulations require companies to provide evidence that operators are sufficiently trained to recognise and react to abnormal operating conditions. Additionally, confidence and performance are known to improve in pipeline operators after using a training system, owing to the availability of more interactive training that reduces risk to real pipelines.

References 1. 2. 3. 4.

https://www.atmosi.com/en/resources/product-brochures/atmos-trainerproduct-brochure/ https://www.atmosi.com/en/news-events/in-the-media/the-iet-how-pipelineleak-detection-can-support-carbon-capture-and-storage/ https://www.atmosi.com/en/news-events/in-the-media/h2-tech-high-qualitylow-risk-energy-transition-to-hydrogen/ https://www.atmosi.com/en/news-events/news/operator-training-for-pipelinesimulation-and-real-leaks-detected/

Kapil Garg, MarketsandMarkets, India, outlines growth in the offshore pipeline market.

ith the increase in global population and industrialisation, the demand for oil and other energy resources is increasing rapidly. The global oil consumption in 2022 was around 99.4 million bpd and is expected to reach 104.1 million bpd by 2026. The decreasing cost of oil is encouraging end user companies such as British Petroleum and Chevron Corporation to invest in the development of offshore reserves and support the growth of offshore pipelines such as flowlines and gathering lines. Petroleum is the primary material to manufacture many chemical products, such as pharmaceuticals, fertilizers, solvents, and plastics. Key companies such as Exxon Mobil, BP, Rosneft, and Total are likely to invest more than US$385 billion in refinery capacity addition or new refinery development projects in next five years. Therefore, the enhancement of refining capacity to meet the demand for refined products is expected to lead to a rise in the need for the construction of new pipeline networks, which, in turn, will drive the growth of the offshore pipeline market.

Stringent regulations for installation of offshore pipeline Infrastructure placement on the seafloor, such as anchors and pipelines, directly disturbs the seabed and causes a temporary increase in local sedimentation. Potential impacts are generally assessed at the project level through some type of formal process known as an environmental impact assessment (EIA). Prior to the start of a project, these typically involve the identification, prediction, evaluation, and mitigation of impacts. The following are key standard components of an EIA: ) A description of the proposed development, including information about its size, location, and duration. ) A baseline description of the environment. ) A description of potential environmental impacts. ) Proposed mitigation of impacts.

) Identification of knowledge gaps.

Board (NEB) have been observed as they must perform pipeline integrity and viability before commissioning any pipeline to Regulations outline the basic features and requirements for avoid disaster. developing and implementing an assessment plan for pipeline As per economic regulations, liquid pipelines are common systems. These regulations are intended to evaluate the risk carriers; the rates charged, terms, and conditions of the services, associated with pipelines. Also, it effectively allocates resources such as commissioning and decommissioning, are regulated by for inspection, prevention, detection, and mitigation activities the Federal Energy Regulatory Commission (FERC) for interstate before issuing any permit for the commencement of pipeline lines and similar state agencies for intrastate lines. State agencies operations to ensure the safety of pipelines. It is necessary to regulate intrastate lines, and local jurisdictions become involved comply with all statutory rules, regulations, and acts in force in various matters, including drafting an emergency response to obtain requisite approvals from the relevant competent plan in the event of an incident. However, in Canada, regulators authorities for the pipeline. For instance, in North America, need to maintain regulations throughout their lifecycles. For delays in issuing permits from statutory authorities such as the instance, the Office of Pipeline Safety (OPS), Canada, provides Association of Oil Pipelines (AOPL), Pipeline and Hazardous most operational oversight, along with other federal agencies, Material Safety Administration (PHMSA), and National Energy such as the Environmental Protection Agency (EPA) and the Minerals Management Service (MMS), which also play important roles. Thus, obtaining a permit by the Table 1. Types of impacts from offshore oil and gas activities statutory government bodies to commence safe and NATURE ENVIRONMENTAL S NO. CONCERN reliable pipeline operations is necessary, making it a ISSUE major challenge in the offshore pipeline market. Physical – excess Smothering – clogging of 1 Drilling discharges sedimentation Chemical – toxic effects

feeding Direct toxicity – altered electrochemical environment, decreased species abundance

Anchors

Physical – direct damage, hard substratum

Direct physical impact at emplacement, provision of hard substratum for colonisation by sessile epifauna and associates

Flow and control lines, umbilical

Physical – direct damage, hard substratum

Direct physical impact at emplacement, provision of hard substratum for colonisation by sessile epifauna and associates

Export lines

Physical – direct damage, hard substratum

Pipelines can corrode, increased toxicity, and fragmentations of fauna

Seabed infrastructure

Artificial habitat

Altered distribution, mortality of corals

Figure 1. Historic and expected global oil consumption, 2019 - 2026.

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Market outlook The offshore pipeline market is expected to grow from an estimated US$14.8 billion in 2022 to US$18.6 billion by 2027, at a CAGR of 4.69% during the forecast period. The rising demand for crude oil and natural gas along with the increasing demand for the safe, cost-effective and reliable connectivity are expected to be the primary drivers of the market. A few major players that have a wide regional presence dominate the offshore pipeline market. The leading players in the offshore pipeline market include Saipem (Italy), Subsea7 (UK), McDermott (US), John Wood Group PLC (UK), TechnipFMC Plc (US), and Sapura Energy Berhad (Malaysia). The major strategies adopted by these players include product launches and new product development, contracts and agreements, investments and expansions, mergers and acquisitions, joint ventures, and partnerships and collaborations. North America is expected to witness significant investments in pipeline infrastructure. After an increase in shale oil and gas production in the US, the country focused more on new pipeline construction projects to meet the growing demand for oil and gas. Pipeline integrity services are essential to reduce transportation risks, ensure structural integrity, and safeguard personnel and assets. These services are of paramount importance to avoid geohazardous situations along the pipeline route and protect the pipeline against corrosion. All such critical factors create immense opportunities for assessment activities at the construction phase.

Hugues Chuffart, Regional Project Director, Fugro, Netherlands, outlines meeting complex safety, scheduling and data quality challenges in a route survey for the Aramis CCS pipeline.

he Aramis carbon capture and storage (CCS) project aims to reduce industrial carbon emissions in the Netherlands by developing CO2 transport infrastructure for offshore storage in the Dutch North Sea. Once captured, the CO2 will be transported

to a hub, consisting of a compressor station and shipping terminal, located at the Maasvlakte in the Port of Rotterdam. From this hub, the CO2 will be transported and injected into depleted offshore gas fields at a depth of about 3 - 4 km (approximately 2 miles) below the seabed.

Figure 1. 2DUHR seismic equipment on the back deck of Fugro Searcher.

TotalEnergies, Shell, EBN and Gasunie are partnering to deliver the landmark project which will help industries with a traditionally greater CO2 burden – such as steel, cement, chemicals, refineries and waste incinerators – to operate more sustainably. Uniquely, Aramis will handle multiple sources of both gaseous and shipped emissions, with scope for industrial and offshore storage users to connect to the infrastructure in the future through an open access arrangement. Much rests on the successful construction of a resilient, high-capacity pipeline and storage infrastructure in realising this long-term vision, which is critical not just to national carbon reduction in the Netherlands but also to Europe’s wider climate action targets.

Seabed and subsurface investigations The foundation to the pipeline’s success, and indeed its strategic role in cross-boundary carbon management, is established long before the first piece of pipe is laid. Crucial in assuring best value and long asset lifecycle are the seabed and subsurface investigations to identify a secure and buildable pipeline route. The site assessment must provide accurate data on geological competence and unseen hazards, such as unexploded ordnance (UXO), as the foundation to choosing a secure route, delivering robust infrastructure and minimising construction risk. Logistically, the water-borne operations need to be meticulously managed in close communication with maritime authorities and other agents using the busy shipping waters. Current market conditions have added to the challenge. Clients are keen to deliver large-scale subsea infrastructure quickly and safely to address existential crises like climate change and energy resilience. Availability of geotechnical labour, equipment and expertise, however, is under pressure in the wake of the COVID-19 pandemic and Russo-Ukrainian War. Fugro was awarded the marine geophysical and geotechnical site investigation of the proposed offshore

Figure 2. Fugro’s Kommandor Orca equipped with the Blue Snake®.

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pipeline corridor, which runs from the Maasvlakte to fields located 80 - 100 km (approximately 50 - 60 miles) offshore the Netherlands. A global leader in geo-data, the company offered broad expertise and in-house solutions to support the safe and timely execution of investigations covering a target corridor some 200 km (124 miles) long and 500 m wide.

Planning for success Since August 2022, Fugro has been underway with a 12 month programme to collect, integrate and interpret multiple data streams to deliver the detailed geophysical and geotechnical insights to guide route selection, including: ) Seismic refraction (MASW). ) 2D ultra-high resolution (2DUHR) processing of seismic

data. ) UXO survey. ) Analogue nearshore and offshore geophysical surveys. ) Environmental desktop study and survey. ) Geotechnical site investigation and laboratory testing.

With a significant area to assess, including shallow nearshore and offshore locations, a high bar of logistical management has been critical to the survey success. The pipeline requires the resource and technical agility to survey nearshore at shallow depths of a few metres, and as deep as 40+ metres offshore. The North Sea is one of the busiest bodies of water in the world, both above and below water, with shipping routes, wind farms, cables and pipes, as well as sensitive areas containing wrecks, WWII UXO, and marine mammals that must be protected from noise disturbance. Other operators are also running simultaneous surveys (SIMOPS) in the area to investigate the seabed or monitor infrastructure. The Aramis team is considering several route options, so Fugro planned and prioritised work in order to supply coherent tranches of route data to facilitate decision-making. Routes under consideration all cross the Maasmond, the very busy shipping channel to the Port of Rotterdam that must remain open 24/7. Fugro was already familiar with the challenges here, having undertaken investigations for the export cable to the Hollandse Kust Zuid (HKZ) offshore wind farm. The Fugro project team has called on specialist equipment and expertise from multiple Fugro sites in Europe, including the UK, Netherlands, Belgium, France, Germany and Norway. “It is a group effort: we make use of all relevant know-how and experience from the global Fugro organisation. This also makes us flexible enough to quickly absorb changes in the scope of work, so that we can effectively serve our client,” says Matthijs Hogerwerf, Commercial Manager, Fugro.

Nearshore surveys The nearshore surveys were focused on two different route options, one based on the use of micro-tunnelling and the other on a direct pipe solution. Most nearshore work was carried out on the Fugro Seeker, a 12 m long catamaran ideal for the analogue surveys in shallow water, such as multibeam, side scan sonar, magnetometer and sub bottom. Seismic surveys were also carried out, which included MASW and 2DUHR. Fugro also used its Seeker for the nearshore UXO surveys, undertaking a full UXO detection survey required to issue the UXO ALARP certificates for subsequent geotechnical operations, as per the applicable regulations in the Netherlands. The UXO desktop study forming the basis of this survey was provided by the client, although this is something Fugro has the capacity to prepare when required. Coordinated from its hub in the Netherlands, Fugro kept tight management of logistics, including close collaboration with the Port of Rotterdam to gain permissions to work, and liaising with other parties to coordinate Fugro vessel movements with other shipping traffic. To avoid the need to close the channel, the Port of Rotterdam control room organised short windows of time when Fugro could undertake geotechnical work discreetly and safely. A pilot was present on the survey vessels when required to maintain constant communication with other boat traffic. For one of the route options, the Maasmond seabed was investigated to a depth of 30 m, where the pipeline would run at a deep level to prevent risks with dredging and shipping traffic. Fugro deployed its Normand Mermaid – a geotechnical vessel with dynamic positioning systems – to carry out all the deep probing within 12 hours. By the end of 2022, five months of the survey programme had been completed with no major incidents to the satisfaction of both the port authority and the Aramis team.

Offshore Further offshore, the surveys were handled in two stages. The first stage comprised of a geophysical survey, which was a continuation of the nearshore survey, and the second stage focused on other geotechnical work. The first stage of the offshore geophysical survey involved a 2DUHR seismic investigation covering the centre of the planned pipeline route. Closely following the seismic investigation, a UXO survey was performed to ensure there was no risk to subsequent geotechnical investigations. During the last stage of the geophysical survey, an analogue geophysical survey is performed on a corridor to assess potential hazards for the pipeline installation and provide room for rerouting if needed. GIS mapping provides a guide to the presence of underwater structures to ensure that the geotechnical tests can be planned with appropriate clearance. Fugro’s expertise in data integration from multiple surveys enabled them to identify a potential UXO hazard that could have posed a risk for the subsequent geotechnical investigations. Additionally, Fugro experts in Norway were able to remove the noise from the collected data and, together with geophysical data, any

30 World Pipelines / NOVEMBER 2023

hidden geohazards which could pose a problem for pipeline installation will be identified. In total, five survey vessels were assigned to the offshore programme, making use of all relevant know-how and experience within Fugro’s global network. This breadth of resource gives flexibility to readily absorb changes in scope to keep programmes on track for the client.

Need for speed With plans for Aramis to open by 2027/2028, there has been a need for speed while assuring robust standards. The offshore investigations have been boosted by Fugro’s latest geotechnical innovation, the Blue Snake® system, designed for the efficient execution of shallow probes and samples. The Blue Snake integrates cone penetration testing (CPT) and sampling technology (vibrocore) to enable safe, fast and high-quality data acquisition in marine environments. It works in water depths from 3 - 100 m and has a penetration length typically of 6 m (though up to 10 m can be accommodated) – more than sufficient for the Aramis route survey. The system collects CPT data and soil samples in a single pass, with the tests being completed consecutively at a fixed distance. This improves geotechnical data correlation and ensures high-quality data, accelerating the acquisition and delivery of geotechnical data. Efficiency and weather workability are also improved by the customised integrated launch and recovery system (LARS). This enables controlled lifting of the Blue Snake unit, independent from crane handling capabilities, thereby reducing manual handling and minimising HSSE exposure. The traditional method uses separate equipment for the CPT and the coring, with possibly different working ranges that can involve extra time repositioning the survey vessel to obtain satisfactory results. A comparison of work cycle efficiency and fuel consumption suggests that the Blue Snake reduces operational time by around 35%, and a potential reduction in carbon footprint of up to 50%.

Data collection and analysis Fugro’s in-house experts used advanced IT to process the huge volumes of geo-data and analyse thousands of drill samples at multiple laboratory locations. Fugro engineers worked on the geophysical and geotechnical data processing to identify any hidden geohazards that could cause a problem for the installation, feeding results to the reporting team who used state-of-the-art IT and digital modelling to deliver taskready data to the client. The final route survey report was delivered in October 2023. The Aramis team will be able to finalise the pipeline route with confidence based on high quality geo-data, expediating the move to design and construction. Despite the current supply pressures for large infrastructure, Fugro’s extensive and flexible capabilities will help secure the delivery of a project integral to meeting CO2 reduction targets in the Netherlands’ National Climate Agreement and the EU’s Green Deal.

Dr Jens Tronskar, Senior Vice President and Chief Technology Officer, Materials Testing & Integrity Assessment, DNV Energy Systems, Singapore, says collaboration is key to ensuring that technology evolves in line with the pace of the sector.

hile pipelines are traditionally used for the transport of natural gas over long distances, even as the energy transition ramps up pace, they remain a critical piece of the energy infrastructure. With 73% of new gas fields and gas resources having high levels of CO2 and hydrogen sulphide (H2S), the design, installation, and operation of the pipelines present a major challenge that must be overcome. Such hurdles stem from the need for de-hydration of wet sour gas due to corrosiveness of H2S and CO2 and the requirement for the removal of the acid gas and CO2 before the natural gas

can meet the strict sales gas composition. CO2 can be captured and injected in depleted gas wells which would require specially designed CO2 pipelines. Natural gas may, to a limited extent, be steam reformed or transformed to hydrogen by other processes. Pipelines are therefore required for CO2 and hydrogen transport for these processes. Green hydrogen, from electrolyses using sustainable electricity, and blue hydrogen, generated from natural gas and enabled by carbon capture and storage, also need transport by pipelines. DNV, the independent energy expert and assurance provider, forecasts that hydrogen will increase to around 15% of world energy demand by 2050 to meet the Paris

Agreement targets. Put simply: pipelines are vital to the facilitation of the energy transition. It is estimated that 75% of new submarine pipelines globally are designed and installed to DNV Standard ST-F101 ‘Submarine pipeline systems’ and it is the world’s most widely used standard for offshore pipeline design. Given its importance, for the last 25 years, DNV pipeline committee meetings are organised twice a year. Attended by energy sector majors, engineering contractors and pipeline manufacturers, the aim is to obtain feedback to improve the pipeline standard and the associated pipeline recommended practices. Another purpose of these meetings is to discuss the latest technology developments in pipeline design, installation, operations and the need for pipeline research.

What is DNV Standard ST-F101? ST-F101 is an internationally recognised standard for submarine pipeline systems. It specifies the requirements and recommendations for the concept development, design, construction, operation, and abandonment of pipelines while emphasising the importance of structural integrity.

Operator considerations When it comes to the repurposing of pipeline systems for hydrogen or CO2 transport, the decision to proceed lies ultimately with gas network operators in collaboration with governments and regulators. These decisions must consider whether the repurposing is safe, feasible and cost effective, but the initial intention must be to identify when, where and what gas quantity demand there will be for hydrogen transport. Before a natural gas pipeline can be pressurised with hydrogen, studies must be undertaken in advance to determine the challenges and impact of hydrogen on the system. With hydrogen transport in long-distance pipelines limited to date, new uses may lead to unknown failure modes. To ensure that operators align on their repurposing projects, a harmonised process is needed as greater quantities of hydrogen are anticipated to be transported over longer distances across more borders.

Understanding fatigue crack growth and unstable fracture risks In advance of a committee meeting early this year, it was determined that there was a need to update the recommended practice DNV-RP-F108: ‘Assessment of flaws in pipeline and riser girth welds.’ Feedback noted the need for an upgrade, providing guidance on pipeline materials, girth welds and riser girth weld testing for sour service. This recommended practice (RP) provides guidance on assessments to develop alternative flaw acceptance criteria to traditional workmanship criteria for automatic ultrasonic testing (AUT) of the girth welds during offshore pipeline installation covering its future operations until its end of life. In the workshop on design limitations for sour service and materials testing, a survey conducted among those in attendance showed that the majority (80%) of companies use the DNV Pipeline standard and the DNV RP F-108 as basis for the design philosophy, design and material selection and installation requirements for sour service pipelines.

32 World Pipelines / NOVEMBER 2023

While the results emphasised the importance of the codes, it also served as a reminder of the importance they will have to CO2 and hydrogen pipelines, whether through design and construction or by the re-purposing of existing natural gas pipelines. A significant outcome from the meeting was the proposal of R&D projects for the update of guidance related to fracture toughness and fatigue crack growth rate in sour environments. In such a service, the weld fracture toughness is reduced (between 3 and 15 times depending on the severity of the environment). Furthermore, the fatigue crack growth rates are significantly increased (30 - 140 times higher) compared to that of non-sour natural gas pipelines. For fatigue, current guidance in Appendix C of the RP-F108 takes the form of an equation to derive a fatigue crack growth rate acceleration factor from environmental parameters, pH and H2S partial pressure. R&D was proposed to develop updated guidance based on a review of available fatigue crack growth rate data collected by testing conducted by energy companies, engineering, procurement, and pipeline installation businesses (EPCIs) and DNV. This data provides a much wider database compared to that available from the Safebuck JIP, which was the basis for the current equations in RP-F108.1 The review requires JIP participants to donate data to the project. The Safebuck JIP ran for 13 years between 2002 and 2015 to develop safe methodologies for the design of deepwater, or high pressure, elevated temperature pipelines which are susceptible to lateral buckling and the associated challenge of pipeline walking. The Safebuck design guideline enables engineers to design pipelines deliberately encouraged to buckle in a controlled way, thus reducing and sharing the loads between each buckle site. The next step will be to develop more sophisticated models for predicting fatigue crack growth rates as a function of key environmental and loading parameters. For the future design of hydrogen pipelines and reuse of natural gas pipelines for hydrogen transport, the R&D is expected to serve as a model to develop guidance for integrity assessment of hydrogen pipelines.

Defects inherent in the welds represent a threat to pipeline integrity With pre-existing planar defects in welds, adding hydrogen to a pipeline network can accelerate crack propagation, potentially causing fatigue failures. For operators considering the potential conversion of natural gas pipelines for hydrogen, the likelihood that expected pressure cycles will produce unacceptable fatigue growth of pre-existing weld defects must be considered. A threshold value for the pipelines can then be established based on the frequency of pressure cycles, free-span vortex induced vibration, thermal stress and outside forces causing crack extension of flaws to reach the critical size for unstable fracture and pipeline failure. High pressure hydrogen is known to reduce the fracture toughness and increase the fatigue crack growth rates of steel pipe and welds; the critical flaw size will be significantly smaller for a re-purposed pipeline than for the original natural gas pipeline. Repurposed hydrogen pipelines are assumed to be operated under similar conditions as natural gas in terms of pressure fluctuations. But in practice, it is not always possible to keep the fluctuations below determined threshold values. Hence, the ability

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to control and limit the crack growth in repurposed pipelines may be difficult. A risk assessment which considers fatigue crack growth and potential fractures should consider: ) The current integrity of the pipeline and operation conditions. ) The impact of high-pressure hydrogen on the material and

weld fracture toughness and fatigue crack growth rates. ) The probability of detecting planar weld flaws by existing

inline inspection tools. ) The determined threshold operating pressure value and

supplemental stresses.

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) The new working conditions expected when transporting

hydrogen.

Collaboration essential to the future of pipelines As already outlined, for Paris Agreement targets to be met, significant investment in infrastructure to enable a hydrogen economy is necessary, particularly for decarbonising hard-to-abate sectors. Significant reductions in investment could potentially arise from the repurposing of natural gas pipelines, with those costs expected to be just 10 - 15% of new construction prices. DNV forecasts that the global spend on producing hydrogen for energy purposes from now until 2050 will be US$6.8 trillion with an estimated US$180 billion spent on hydrogen pipelines. As the energy transition continues, design parameters and standards must also move with time and evolve in line with technological developments to ensure that infrastructure meets current requirements and are fit for purpose. Joint industry projects and R&D projects play an essential role in closing knowledge gaps to develop standards and recommended practices needed for the safe and efficient repurposing and construction of pipelines for the transportation of wet sour gas, CO2, and hydrogen. DNV has recently launched Phase 2 of the H2 JIP.2 The DNV standard for submarine pipeline systems (DNV-ST-F101) includes hydrogen as a listed transport product, however additional considerations are required to meet the target safety level for an increased use of hydrogen. A special concern in this respect is the potential detrimental influence of hydrogen on resistance to cracking in carbon steels as discussed earlier in this article. Another Joint Industry Project is the H2S challenges in CO2 pipelines.3 This JIP looks at how increasing acceptable levels of H2S will affect the risk for sulphide stress cracking (SSC) and corrosion damages in carbon steel pipelines used for CCS. Increasing the acceptable level of H2S in the pipes will potentially enable CCS projects to receive CO2 from a higher number of sources/customers with a limited need for processing/cleaning. The project will provide general recommendations for industry wide use and will lead to an update of the DNVRP-F104 ‘Design and operation of carbon dioxide pipelines’. By working in partnership with pipeline operators, contractors, and other stakeholders to continuously raise the bar, the entire energy sector can benefit.

References

1. https://safebuck.com 2. www.dnv.com/news/dnv-to-launch-phase-2-of-offshorehydrogen-pipelines-joint-industry-project-2 3. www.dnv.com/article/hydrogen-sulfide-challenges-incarbon-dioxide-pipelines-co2-safe-and-sour-219712

orrosion under insulation (CUI) represents a significant and persistent challenge to asset integrity across various industries, leading to substantial financial implications, estimated to amount to hundreds of billions of dollars annually. Many of the contributing factors that contribute to CUI are inherently difficult or impossible to control. However, the key to mitigating this issue lies in regular inspections and proactive maintenance practices. CUI arises from the infiltration of moisture and the presence of elevated temperatures within insulated assets such as pipework. It commonly manifests as general corrosion, causing gradual degradation and compromising the structural integrity of the affected components. To combat CUI effectively, it is essential to implement routine inspections and employ proactive maintenance measures that can help identify and address potential issues before they escalate. By embracing a preventive approach, the detrimental effects of CUI can be minimised, ensuring the longevity and reliability of industrial assets. Unless an advanced non-destructive testing (NDT) method is used, however, CUI or coating is difficult to detect as the protective layers hide it, making it likely only found when insulation or coating is removed for visual inspection or when a

Leveraging a variety of NDT modalities ensures the inspection process is optimised for accuracy, reliability, and effectiveness in assessing subsea assets, says Jonathan Bancroft, TSC Subsea, UK.

leak occurs. CUI is said to be responsible for the highest occurrence of leaks in the chemical and refining sectors. The cost and occasion of CUI can be alleviated through implementing systems that allow early detection with NDT while assets remain in service. Subsea pipelines introduce additional complexities due to the presence of thicker coatings and insulation layers, requiring subsea engineers to carefully consider various material properties, including buoyancy. Concrete weight coat (CWC) is widely recognised as a popular coating within the oil and gas subsea sector. One of the key benefits of CWC is its ability to offer dependable negative buoyancy, along with robust shielding against demanding environments and potential mechanical harm that may impact both the pipe and its thermal insulation coating.

Figure 1. Pipeline inspection through concrete weight coat (CWC) with SPECTA.

While concrete serves as an effective protective layer, it can present challenges as a barrier to external NDT methods. The coarse grain structure of concrete, typically forming a layer measuring 2 - 4 in. in thickness, renders ultrasonic testing impractical and limits the effectiveness of many electromagnetic inspection technologies.

Case study TSC Subsea was commissioned to conduct a wall thickness assessment of the condensate export pipeline (CEP) and pipeline end manifold (PLEM) while retaining the protective CWC. The purpose of this assessment was to address the client’s concerns regarding potential compromises to the integrity of the steel pipework concealed beneath the concrete coating. The scope presented a distinct challenge as the operators aimed to minimise the reliance on divers and maximise the utilisation of remotely operated robotic scanners for the inspection. TSC Subsea is a leading inspection vendor, leveraging advanced technology to tackle the most demanding subsea NDT inspections worldwide. Its comprehensive portfolio encompasses a range of NDT inspection technologies, such as alternating current field measurement (ACFM®), acoustic resonance technology (ART), pulsed eddy current (PEC), and subsea phased array (SPA). These advanced techniques seamlessly integrate with a variety of robotic scanners, all of which can be deployed via remotely operated vehicles (ROVs). The decision was made to deploy a robotic scanner for the majority of the inspection tasks, supplemented by the assistance of a diver specifically for inspecting the elbow bends on the PLEM, which were inaccessible to the robots. The combined inspection involving both the diver and robotic technologies necessitated meticulous planning and effective communication. Given the client’s stringent timelines and a limited inspection window, ensuring that all designated inspection locations were completed within the allotted timeframe posed a significant challenge.

The solution

Figure 2. ROV deployable vCompact with SPECTA probe.

36 World Pipelines / NOVEMBER 2023

Given the structural composition of the CWC, ultrasonic methods were deemed unsuitable for the inspection. Consequently, TSC Subsea opted to utilise its latest technology, Subsea Pulsed Eddy Current Testing Array (SPECTA), as the most fitting solution. PEC is among several NDT technologies offered by TSC Subsea for corrosion mapping of cylindrical components. PEC stands out as an exceptionally robust inspection technique, offering substantial capability for measuring wall thickness through the coating. While it is a semi-quantitative screening method and may not match the precision of ultrasonics, it reliably provides readings for the remaining wall thickness and corrosion depth, providing invaluable inspection data without removing the coating. PEC offers the advantage of conducting scans in ‘screening mode’, employing larger grid sizes to identify potential defect areas. Once these areas are identified, they can be revisited and scanned at a higher resolution, enabling more precise and accurate results to be obtained. This approach allows for a systematic and efficient inspection process, where potential issues are initially detected and subsequently examined in greater detail, ensuring thorough evaluation and assessment of the identified areas.

For deploying the SPECTA probe, TSC Subsea opted for its vCompact X-Y robotic scanner. Under normal circumstances, the vCompact would utilise standard permanent magnets to attach to the inspection surface. However, the presence of the concrete coating posed a challenge to magnetic adhesion. To overcome this, TSC Subsea engineers ingeniously customised the scanner by incorporating a hydraulic clamping mechanism. The hydraulic clamps were affixed to the robot, enabling it to securely attach to the concrete pipe and serve as an anchor for the articulating arm responsible for gathering the PEC readings. During the inspection process, the vCompact efficiently covered 180˚ of the pipe with a single placement, completing a 600 mm axial scan in under an hour. This streamlined approach facilitated swift and comprehensive data collection, optimising the overall efficiency of the inspection operation. Given the complex and intricate nature of subsea inspections, it is crucial to ensure accurate data collection and analysis right from the start. To maintain the integrity of the data, TSC Subsea utilised its expert data analysts, who provided remote support from the UK. These skilled analysts meticulously analysed the data results in real-time, facilitating prompt analysis and delivering instantaneous outcomes for any identified areas of concern. This approach significantly expedited the analysis process, enabling swift decision-making and ensuring the highest level of inspection quality and reliability. The combination of SPECTA and the vCompact robotic scanning solution offers several notable benefits. Firstly, it provides pinpoint accuracy in location scanning, ensuring precise identification of defect locations. This level of accuracy surpasses traditional diver-deployed offerings, enhancing the overall effectiveness of the inspection process. Moreover, the fully encoded scanning capability enables repeatable inspections, facilitating future monitoring and fitness for service assessments. The encoded scanning ensures consistent and reliable data collection, enabling comparative analysis over time and aiding in the evaluation of asset integrity. By leveraging the SPECTA vCompact combination, TSC Subsea delivers exceptional accuracy in defect location scanning, and enables reliable and repeatable inspections for ongoing monitoring and assessment purposes.

Figure 3. Simulation of SPECTA penetrating thick coatings.

Figure 4. SPECTA data detailing wall thickness measurements.

limitations of most NDT technologies when it comes to concrete, the utilisation of TSC Subsea’s technology proved crucial for the client. Without this innovative solution, the client would have been compelled to remove the concrete coating to conduct the assessment. Such a course of action would have entailed substantial costs and significant operational disruptions. SPECTA emerges as the ideal tool for corrosion mapping and subsequent inline inspection (ILI) follow-up. Moreover, it can be seamlessly integrated with other NDT sensors to complement the PEC data, further enhancing the overall inspection capabilities. By leveraging the capabilities of SPECTA, TSC Subsea empowered the client to efficiently and cost-effectively carry out assessments without the need for concrete coating removal. This significantly reduced expenses and operational impacts.

The result

Conclusion

The project was executed with remarkable efficiency, adhering to the designated timeline and staying within the allocated budget. The inspection process yielded successful data acquisition, and no areas of concern were identified during the assessment. The implementation of the SPECTA vCompact solution proved to be highly successful, as it minimised the reliance on diver deployed inspections, consequently reducing risks associated with diver operations. By achieving the project objectives without any noteworthy issues, TSC Subsea demonstrated its proficiency in delivering highquality results while effectively managing time and resources. The successful deployment of the SPECTA vCompact solution not only ensured accurate and reliable inspections but also prioritised the safety and wellbeing of the divers involved. SPECTA stands out as the pioneering commercially available solution for subsea CUI and PEC array inspection. Given the

The utilisation of CWC pipework is prevalent among many operators who frequently need to assess the integrity of their pipework under similar conditions. In such cases, a comprehensive approach involving detailed risk-based integrity assessments and data obtained from ILI is often necessary to evaluate the remaining wall thickness of subsea assets. TSC Subsea distinguishes itself by offering a diverse range of NDT modalities. This versatility enables us to select and utilise the most suitable NDT technique tailored to the specific needs of each client. By leveraging a variety of NDT modalities, we ensure that the inspection process is optimised for accuracy, reliability, and effectiveness in assessing subsea assets. Whether it is through advanced technology such as SPECTA or other NDT solutions in our portfolio, TSC Subsea is committed to delivering tailored and comprehensive inspection services that address the unique requirements of each client’s subsea assets.

NOVEMBER 2023 / World Pipelines

Information obtained from satellite data is crucial for understanding risks and changes which can lead to structural failures in pipelines, says Lucy Kennedy, CEO and co-Founder, Spottitt, UK. lobally, oil and gas transmission pipelines span a total length of 2.15 million km and are projected to grow by over 5% by 2027, equivalent to circling the Earth 53 times. Europe alone accounts for approximately 200 000 km of gas transmission pipes. These figures specifically refer to transmission pipelines, which form the backbone of the system, the final distribution lines to residential and commercial areas are excluded. Throughout history, underground construction has been the prevailing choice for oil and gas pipelines, driven by factors like external protection, safety considerations, and aesthetic preferences. While overground pipelines are less common, they are found in specific regions or for particular purposes. In most cases, the underground network lies at a depth of just 1 - 1.8 m beneath the surface.

variations may be found across the measurement, reporting, and verification (MRV) requirements, and LDAR practices. Looking specifically at the EU, which contributes 7% of global GHG emissions and 4 - 5% of global methane emissions, the number of national policies and measures has been increasing since 2015. Over 2200 policies and measures have been created across the three target sectors of agriculture, waste, and energy. These account for 53%, 26%, and 19% of EU methane emissions, respectively, according to the European Environment Agency. The EU Methane Strategy and the proposed EU Methane Regulation, define methane emission measurement, reporting and mitigation requirements across these three sectors. In May 2023, the EU Parliament adopted amendments to strengthen obligations for methane LDAR in the energy sector. Looking top down, the International Methane Emissions Observatory (IMEO) will work at a global scale using satellite technology to monitor big emitters, thus helping to inform EU oil and gas importers on the methane footprint of their supplies. Working bottom up asset owners, including gas transmission and distribution network owners will be required to perform and report on regular LDAR activities at both asset and site levels. While the debate on what level of methane LDAR activities across the energy sector are both proportionate, and implementable is very much ongoing. What is clear is that MEPs are pushing for:

) Multiple LDAR surveys per year, instead of annual

surveys. ) The surveying of all assets, as opposed to only medium

and higher-pressure assets. ) The use of much lower leakage thresholds. ) Quicker repair times once a leakage has been detected.

So how can asset owners meet the requirements of the future finalised EU Methane Regulation without having to significantly increase their current LDAR budgets? Are there new monitoring technologies that asset owners can turn to which don’t themselves have a big carbon footprint? There is more talk of the role that satellites have to play, but what is the truth?

Attraction of satellite derived monitoring for pipeline operators

One key advantage lies in their ability to capture images over vast areas, delivering wide coverage. This eliminates the need for physical inspections onsite at every location, saving valuable time and resources. Unlike flight inspections, satellites do not contribute to additional pollution while providing a swift and comprehensive view. Moreover, remote monitoring enables surveillance of remote or inaccessible areas, ensuring that the entire network and all regions are effectively monitored, regardless of geographical location or infrastructure limitations. Satellite data can be swiftly collected and analysed in near realtime, enabling prompt identification and mitigation of detected issues. Consistency and standardisation of data play a vital role as well. Satellite imagery ensures a consistent and standardised approach to data collection, fostering uniformity in monitoring infrastructure assets. This facilitates data analysis, trend identification, and comparison over time. Consistent data also supports the development of predictive models and aids the Figure 1. Spottitt Metrics Factory: metrics-as-a-Service for geospatial risks analysis. decision-making processes. Unlike other

Figure 2. Land motion analysis derived from SAR satellite imagery.

40 World Pipelines / NOVEMBER 2023

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techniques that often require training and the installation of specific equipment, satellites offer a more accessible and streamlined approach. Analysis is available within a few clicks, simplifying the monitoring process and reducing operational complexity. In summary, satellites offer distinct advantages in pipeline monitoring, providing wide coverage, remote accessibility, near real-time data analysis, and consistent data collection. These capabilities revolutionise the monitoring landscape, enhancing efficiency and enabling effective mitigation strategies.

Satellite technologies for pipeline operators Stepping back and acknowledging that there is a whole host of very successful frontline effort and investment that goes into ensuring that pipelines don’t leak in the first place, let’s look at some of the ways in which satellite data and technologies can be deployed to reduce the risk of pipeline integrity loss and leakage.

Pipeline routing Satellite technologies can provide valuable data for pipeline routing, ensuring optimal placement based on factors such as digital elevation, land cover, proximity of encroachment issues, biodiversity loss, and site access. Satellite-based

climate and weather data can also help understand the typical climate conditions, soil moisture level, frost, flooding risk and more along the pipeline’s routing.

Monitoring above ground risks and changes Satellite data can be used to monitor above-ground risks and changes along oil and gas pipelines. This includes tracking land and asset motion, habitat changes, land use and land use change, vegetation encroachments, third-party change and risk detection, and flooding events. By continuously monitoring these factors, gas pipeline operators can proactively address potential risks and ensure the ongoing integrity of their infrastructure.

Monitoring atmospheric risks and changes Satellites equipped with climate and weather sensors can monitor atmospheric risks and changes that may impact gas pipeline operations. This includes tracking lightning strikes, rainfall, wind patterns, humidity levels, snow accumulation, temperature fluctuations, and more. By understanding these current and past atmospheric conditions, operators can optimise their asset upgrade, maintenance and ongoing operations to mitigate potential risks.

Monitoring below ground risks and changes While satellites cannot directly observe below-ground conditions, certain sensors can penetrate the top few centimetres of soil, providing valuable data on soil moisture and composition. This information is crucial for understanding below-ground risks and changes, such as soil stability, erosion, and other potential impacts which can lead to structural failures in pipelines.

Satellite technologies for methane LDAR: fact or fiction? Fact The International Methane Monitoring Observatory uses open source and commercial satellite data to search the globe for ‘big’ emitters. Figure 3. Satellite derived soil moisture data. One of the many metrics available via Spottitt MF.

Fact GHGSat is currently the global leader in terms of satellite derived methane specific emissions monitoring. They offer a pixel resolution of approximately 25 m and a validated capability to accurately detect emissions of 100 kg/hr or more. There are new commercial satellite data providers working on new sensors which will be able to detect even smaller leaks.

Fiction

Figure 4. Spottitt Metrics Factory: metrics-as-a-Service for geospatial risks analysis.

42 World Pipelines / NOVEMBER 2023

Satellites will be able to spot leaks of g/hr? Despite being passionate about what satellites have to offer, in the short to medium-term that level of sensitivity is beyond even a drone mounted sensor

flying 10 m off the ground, let alone a plane or satellite mounted sensor.

Fact Smart asset owners are still busy evaluating satellite and other novel remote methane monitoring technologies because, ultimately, methane regulations will have to find a path between driving a drastic reduction in methane emissions and being regulations that are proportionate and implementable. This is likely to involve complex hybrid monitoring approaches that blend data from bottom up asset measurements with data from top down site wide measurements where satellite technologies will have an important role to play.

Unlocking geospatial analytics full potential Spottitt, a geospatial analytics company headquartered in the UK, has pioneered cutting-edge technology that harnesses data from a diverse range of satellite constellations and satellite sensor types. Spottitt’s innovative solution revolutionises the detection of various external pipeline risks, including ground and asset motion, third-party intervention, climate conditions, flooding, vegetation, and more. Leveraging advanced machine learning algorithms, our technology swiftly delivers precise information on the location and magnitude of risks, regardless of the network’s size or geographical position, all within an impressive 48 hour timeframe.

The best part? It requires no additional hardware or complex installations. Simply provide your pipeline location details, and Spottitt’s advanced system takes care of the rest. Through a user-friendly, cloud-based platform, Spottitt delivers actionable insights in a variety of formats. Visualise the data through intuitive heat maps, allowing for easy identification of hotspots and areas of concern. Alternatively, explore the numeric table format to delve into specific details and conduct an in-depth analysis. This versatility empowers oil and gas pipeline operators to manipulate the data according to their unique needs and make informed decisions with confidence. In contrast to other market players, Spottitt is an authorised reseller of satellite imagery. This unique distinction allows you to own the license and utilise the imagery multiple times for your operational needs. Our clients say: “Spottitt champions advancing the use of satellite imagery and analytics as a standardised data approach, increasing accessibility of the technology”; “The analysis is available quickly, super helpful and easy to understand”; “It’s already in a GIS-compatible format, so it’s easy to pull it down and load it into internal systems”; “I look forward to continued collaboration and excited to see what else Spottitt will do for us”.

Note The work done is part of the project that was co-financed by NCBR.

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here are often problems encountered during pigging operations in new internally uncoated pipelines. The first part of this article presents a case study of a 30 in. export oil pipeline, 180 km long, situated in the Sahara desert. Issues were encountered during the pigging runs on test sections of 26 km.

Cleaning operations Various problems were encountered during cleaning operations, mainly related to the internal porosity of the uncoated pipes and hence the important frictional forces that are generated during pigs running. These problems were exacerbated by the presence of fine sand and by high external temperatures (more than 60˚C during the summer). All these conditions contributed to the wearing out of the rubber gaskets on bidirectional pigs during pigging. To solve this issue, Saipem has been using different types of discs with rubber 60 shore (and guide disc with rubber 80 shore) to optimise performance, but the results were still not comparable to the pigging of the internal coated pipelines due to the considerable abrasive forces. Pigging operations and costs in these conditions were increasing, since each single pig run utilised a new set of rubber

discs. In addition, some discs were breaking (Figure 1), with pigs that were getting stuck in the pipeline. Another relevant aspect is that the porosity of the pipes favoured a formation of residue deposit of iron powder and sand, which contributed to the abrasion of the seals used. The best method to clean the pipes is to utilise a pig equipped with brushes and magnets. The pig removes all surface deposits distributed along the walls, and then another pig follows behind, to gather the materials that detach from the pipe walls. A large quantity of debris is typically involved in such long distances (36 km).

Swabbing operations During swabbing (preliminary drying using medium density and low-density foam pigs) various problems were encountered by the many passages of the foam pigs, due to the micro porosity of the internal uncoated pipes. This porosity also caused surface abrasion of the foam pigs utilised, which decreased the absorbent capacity of the pigs. In cases like these, where large forces are involved, it can lead to the failure of foam pigs, and then a rupture creates a stuck pig, that obstructs passage within the line. For operations like this, it is very important to achieve the desired dew point level. As a simple comparison with daily life,

Dr. Claudio Zanghì, Precommissioning Manager, Saipem, Italy, writes about pigging internally uncoated pipelines in the desert, and a new method of pressurisation for hydrostatic testing of pipelines. Figure 1. Damaged sealing and guiding rubber discs after pig run into the internal uncoated pipeline.

we may take the example of washing your hair. If you dry your hair first with a towel, it will only take a few minutes of using a hairdryer to be dry. But if you are not doing a towel dry first, the timing of drying with a hairdryer will be longer. For this reason, the dryness capacity of the foam pig should be at maximum level to optimise the result, especially in terms of timing schedule.

Cost evaluations of cleaning operations Saipem carried out a careful analysis of the costs of cleaning operations, based on the equipment working hours, manpower and material utilised, fully considering the many steps that were taken during operation at site. We can quantify in an amount equal to 50% more than the pipelines painted internally. This figure is completely empirical, compared to the experiences of pigging internal coated pipelines, that have been quantified on equal terms with a significant delta of 50% less than the pipes unpainted. In this evaluation, Saipem also considered the index of porosity and roughness of the inner pipe, and compared the result to an evaluation from a survey in the field, which allowed to us to estimate the duration of the rubber gaskets of the pigs used.

Figure 2. Swabbing operations – medium density foam pig being removed from internal coated pipeline.

Cost evaluations of swabbing operations Saipem observed an increase of the steps performed equal to 50% or more, when compared to an internal coated pipeline (Figure 2). This was also due to the factor of internal porosity, which favours the absorption or the stagnation of small amounts of water along the walls. This means additional foam pigs to be run, in order to completely eliminate any residual water inside the pipes.

Figure 3. Pigging cost comparison between internal painted and unpainted pipelines.

Conclusion Figure 3 shows an analysis of the overall costs. You’ll notice an estimated difference of 50% in costs for the pipelines that are internally coated. The costs include: consumables, manpower, working hours, and more fuel due to the increased power of the compressors utilised. This evaluation is based on empirical data of the project, where we applied a unit cost per meter of length.

Pressurisation case study The second part of this article looks at methods of pressurisation adopted during hydrostatic testing of pipelines. This case study references a method applied during pipeline hydrostatic testing activities for a 48 in. cross country pipeline in the Caucasus regions (Azerbaijan – Georgia). Figure 4. Pressures vs temperatures plotted. This method of testing is focused on the pressurisation phase, performed by a gradual Table 1. Test sections pressure/temperature data measured during pressurisation up to 80%, providing 24 hours of hydrostatic testing stabilisation. Hydrostatic test Drop in pressure Drop in pressure Pipe wall By applying this method, we have obtained good sections number (2 hrs holding at (24 hrs holding at temperature variation results, especially in longer hydrotest sections (with 80% TP) (bar) 80% TP) (bar) (˚C) maximum length of 40 km). The pressure drop during the 1 -0.5 -0.2 24 hours of the test was negligible. All the data during 2 -0.3 -0.1 testing have been monitored by a digital interface with 3 -0.4 -0.2 high accuracy, that also includes a data recorder and 4 -0.35 -0.1 graphical representation. 5

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Pressurisation method This method works by pressurising with a constant flowrate, to increase the pressure no more than 1 bar per minute, up to 80% of the final pressure test. Then, the pressurisation is stopped and continues with thermal stabilisation. After 24 hours of thermal stabilisation, we then continue to pressurise to 100%, increasing the pressure by not more than 0.5 bar per minute. In Figure 4 and Table 1, you can see that the performance of the test within 24 hours is definitely better, in terms of pressure lost, compared to the other test sections (in which pressurisation was performed with just 2 hours of pressure stabilisation between 80 - 100% of reaching the final test pressure). Plotted in the Figure 4 (in yellow), you can see that the pressure vs temperature was stable, and the pressure loss was negligible, compared to the blue line, where you can notice that the pressure was not correlated to the temperature, means unstable pressure and fluctuation of the parameters considered. This pressurisation method is particularly effective for longer pipeline sections (over 10 km) and does not affect the construction schedule.

Matthew Hawkridge, Chief Technology Officer, Ovarro, explains the crucial role of remote telemetry units (RTUs) in optimising performance, safety and failure reductions in oil and gas pipelines.

lobal oil demand will grow sharply in 2023, according to March 2023’s Oil Market Report (OMR) published by the International Energy Agency (IEA). The accelerating demand places a greater onus on oil and gas network operators to deliver oil and gas consistently and to ensure pipelines operate safely and without failures. The IEA predicts that world oil demand will skyrocket from 710 000 bpd in 1Q23, to 2.6 million bpd by 4Q23. This demand will be driven by “rebounding air traffic and the release of pent-up Chinese demand”. These developments will place extra demands on oil and gas pipelines;

transportation, storage and trading are all integral to midstream oil and gas operations. These business areas are connected by pipelines that carry unrefined crude oil and natural gas from thousands of wells on to central locations for further handling. However, oil and gas pipelines are far from failsafe. Corrosion, cracks and leaks are all common issues that, unless rectified, can cause downtime and supply interruptions, or decrease operational efficiency. The impact of pipeline outages was made clear in December 2022, when a combination of a faulty weld and ‘bending stress fatigue’ caused the Keystone Pipeline, a major oil

pipeline system in Canada and the US, to spill more than 500 000 gal. of crude oil. The accident was the largest spill of its kind in the US in nearly a decade. The IEA’s OMR forecast highlights the importance of preventing such accidents in order to ensure the safety of staff, the public, and also the markets. Indeed, Bloomberg reported that crude oil prices rose by 5% after the Keystone Pipeline incident. That entails identifying, analysing and evaluating potential risks before they happen – but how?

Get SMART To prevent pipeline failures or accidents, oil and gas network operators must first establish a robust framework and adhere to relevant key performance indicators (KPIs). But, this process is not without obstacles; oil and gas companies have previously struggled when implementing the hardware and software necessary to guarantee safety and performance. This was frequently because the project’s scale was misjudged from the beginning or because specific, measurable, achievable, relevant and time-bound KPIs – otherwise known as SMART goals – were not properly set. Instead, oil and gas network managers and operators must invest in mechanisms that improve communication and asset supervision. One of the most appropriate devices to collect and process this information is the remote telemetry unit (RTU), a field mount computer that operators can deploy to control and monitor a wide range of assets. RTUs are critical to data chains, managing information flows from asset input/outputs (I/Os) throughout businesses, even up to the CEO. An additional advantage of RTUs is managing critical assets in remote locations; because some pipelines are in the most remote locations on Earth, asset monitoring, predictive maintenance and employee safety must be effectively managed from secure locations that are sometimes thousands of miles away. For this purpose, RTUs have a longstanding track record of remotely capturing and feeding back valuable insights across pipelines, wellheads and offshore platforms. Once installed, the RTU collects data locally and acts on it immediately, regardless of the surrounding environmental

Figure 1. With Ovarro’s Kingfisher remote telemetry units (RTUs), it’s possible to control and monitor geographically dispersed assets in real-time.

48 World Pipelines / NOVEMBER 2023

conditions. The RTU can report data back to the central supervisory control and data acquisition (SCADA) control room while maintaining a local historical store as a backup, if needed. The real value of an RTU is in its autonomy – it can perform self-governing control in real-time and report to the supervisory SCADA system that everything is under control. Operators situated at the SCADA interface can supervise operations by centrally establishing and enforcing KPIs, which include set points and instructions. The RTUs then manage and implement these instructions locally.

Worker safety Before specifying and installing an RTU, oil and gas operators must ensure the system will be resilient to the site’s environmental conditions. After all, critical pipelines cover thousands of miles, including through some of the harshest environments on Earth. The RTU is required to handle multiple control algorithms and protocols in order to communicate seamlessly with multi-vendor devices within the network, and without draining local power supplies. RTUs also benefit worker safety. In a scenario where the pipeline’s control system must operate in temperatures of -50˚C, it’s preferable to reduce the time required for technicians to be onsite, or eliminate the need for human maintenance altogether. That’s why having an RTU with extensive diagnostic capabilities and a low mean time to repair (MTTR) can be essential, helping management teams make better and more informed decisions in real-time. This also helps in the case of communication breakdowns. Such failures are to be expected in the Arctic, deserts or other remote locations – but this doesn’t mean operators must accept the inevitable. Since RTUs control and monitor assets independently and locally, they can continue to run in the event of a communications breakdown by maintaining a historical log and reporting this back to the central SCADA later when normal service is resumed.

100% uptime Beijing Gas Group is the largest urban gas enterprise in China. By the end of 2016, its natural gas pipeline network had reached over 20 000 km and was supplying 18 billion m3/yr to over 5.89 million customers. Its extensive pipeline network is managed from a Production Command System, which includes SCADA for both transmission and distribution networks, plus pipeline simulation, consumption forecasting, and geographic information systems. To achieve 100% uptime, the pipeline network’s control systems are duplicated between a master control centre (MCC) and an emergency control centre (ECC) – so the network can be controlled from either centre. Initially, the network included DataDirect Network (DDN) lines to around 60 high pressure regulating stations. Over the years, this has grown to more than 200 stations that now use fibre optic cables, with wireless communication as a backup

channel – illustrating how quickly oil and gas infrastructure is expanding to meet increased demand. As these sites grow, Beijing Gas Group’s operators must ensure consistent control and management, as well as remote and local visibility over system status. That’s why Beijing Gas Group turned to Ovarro’s partner in China, the local systems integrator ZKCiT, which supplied 381 Kingfisher RTUs from Ovarro over ten years. The Kingfisher RTUs help manage communication issues by, for instance, collecting data that can support maintenance decisions and verify that KPIs are being adhered to. As well as operations, RTUs can support maintenance teams, health and safety initiatives, and environmental management. The Kingfisher RTUs were ideal for Beijing Gas Group’s expansive network because they are easy to configure and deploy, with built-in programming shortcuts that ensure reliable connections with assets. By simplifying automation tasks, it enables critical infrastructure operators – like those working on oil and gas pipelines – to control and monitor data from geographically dispersed assets in real-time. Since installing the RTUs, Beijing Gas Group has improved monitoring and control of metered off-takes, gas storage, CNG stations, and pressure regulation stations.

Closer to the edge RTUs are now functioning as so-called ‘mini PCs in the field’ and will help harness the power of the Industrial Internet of Things (IIoT) by making older assets smart. Continued innovations will help drive this increased adoption, and it is already possible to deploy RTUs on most equipment irrespective of size or age. Inbuilt redundancy and resilience are also helping to avoid system failures. Going forward, improvements in processing power and throughput are helping RTUs keep up with the increasing demand for data. Edge computing will also come into the mix at some stage, although increased processing power of RTUs means they are already part of a distributed network, processed at the edge of the network. The benefit of this is low latency by computing the data where it is generated, which is essential for real-time monitoring. This edge capability also provides linear scalability; scalability has

been an obstacle for oil and gas operators in the past, so will be essential to support the increased deployment of communication devices that reduce pressure on the central network infrastructure. As global demand for oil grows sharply, as predicted by the IEA, so too will the onus on pipeline managers and operators to improve efficiency, ensure safety and deliver shareholder value. Fortunately, RTUs offer a solution to many of the common issues facing pipeline operators – whether this is structural failures, pressure monitoring, asset optimisation or logging critical data in remote locations. With the right RTU, operators can protect their staff, the public and markets.

Joonas Arola, Director, Pemamek Ltd, Finland, discusses intelligent welding automation for pipe shops and component manufacturers. he energy industry is under rapid change. The already fragmented markets require reliable, safe, and affordable energy, whereas energy providers require highquality technology, higher production capacity, and cost-efficiency. To meet these industry demands, tackle the lack of skilled welders and maintain competitiveness, companies need to reconsider their production and identify the phases that slow down the total process and from which they can look for improvements. Fortunately, there are often simple things to be improved.

Solutions for pipe production In oil and gas pipe production, pipe components and special pipe fabrication are one of the most demanding phases in the entire pipe manufacturing process. When implemented manually, the entire process from handling to welding is time-consuming and inefficient, and there is never a full guarantee of labour safety. Additionally, it requires a significant amount of highly skilled and steady-handed workers to weld demanding components, such as pipe elbows and valve frames promptly and with high-quality results. Figure 1. External longitudinal welding.

One, if not the only, option to meet modern challenges is to increase the level of production automation. When integrated into daily fabrication routines, automation brings immense and long-lasting advantages that are visible immediately. Automation is versatile, reliable in quality and performance, plus it reduces costs. There are different levels of production automation: from simple mechanised solutions to put the pipe rotating during manual welding, to highly automated robotic solutions, and everything in between.

Robotised solutions for component manufacturers Robotised welding for components like valves, pumps, and joints just makes things easy and keeps the quality high, even when the welder feels low. The shift from

manual welding to robotised welding across various industries keeps ramping up. This development applies to component manufacturers as well. PEMA Skytrack is designed for companies wanting to increase production flexibility, productivity, and scalability. PEMA Skytrack is a compact and hassle-free solution. It is fast to install and easy to integrate into existing production routines. Furthermore, robotic welding machines like the PEMA Skytrack open a clear path for component manufacturers to enter or further strengthen their robotic welding capabilities. Taking the first step is often considered the most difficult one. In many ways, this applies to robotic welding too. Additionally, it is the exact reason why easy installation, programming, and day-to-day operation were the key features while designing the PEMA Skytrack. Combined with advanced welding technologies and fast return on investment, PEMA Skytrack shows the way for compact robotised solutions for component manufacturers. This compact robot station is a perfect solution to pipe components and small pressure vessel manufacturers. Integrated positioner keeps the welding position always at the most optimum, ensuring the best possible quality and high productivity. Additionally, the compact size of the PEMA Skytrack makes it possible to move the station between different manufacturing locations with minimum effort. It will give you a real competitive edge for upcoming projects.

Digging the deep grooves With an additional laser scanning function and PEMA WeldControl 300 Scan software, you can easily scan the actual geometry of deep welding grooves, create welding paths and start welding. This scanning package has already proven its worth in Pemamek’s bigger robotic welding devilries for demanding oil and gas pressure vessel manufacturing and heavy machinery welding. Figure 2. PEMA Skytrack is designed for companies wanting to increase production flexibility, productivity, and scalability.

Figure 3. Technical specification of PEMA Skytrack station.

52 World Pipelines / NOVEMBER 2023

Automated solutions for pipe shops Pipelines require a huge amount of straight pipe sections provided by reliable pipe mills. Building different types of pipelines demands a large variety of sub-components that align with the same strict production requirements. Today there are a great number of intelligent automation solutions for longitudinal welding of tubular pipes, pipeto-pipe, elbow-to-pipe, and flange-to-pipe connections available in the markets. The wide selection of roller beds and positioners integrated into column and boom (C&B) welding solutions, and combined with special welding automates, have been proven to bring significant improvements in pipe shop production capacity. Integrated solutions can be typically modulated from any welding and production automation providers’ standard product families. Various welding processes, such as GMAW or GTAW for root pass welding and multi-arc SAW welding for filling up, are integrated into large-diameter pipe fabrication equipment. To maximise the output without

Despite the challenging shape and angle degree, thanks to modern and innovative production technology, elbow component welding can be automated; requiring faultless integration and machine communication between handling, welding, and control systems. Typically, the fabrication of the elbow component process is separated into two different phases: internal and external seam welding. Due to the wall thicknesses and handling requirements, both phases have their specific stations and processes.

Welding solutions and heads for elbow welding • Internal welding head: C&B with elbow welding Figure 4. Internal pipe elbow welding.

head and material handling. • External welding head: special station with C&B and

material handling. • Single and tandem SAW process. • Special positioners with interpolating movements

and integration into welding.

Special pipe section fabrication • Internal welding to welding C&B with long reach

boom, single arc, and Tandem arc SAW. • External welding to welding portal tandem SAW and

multi-arc SAW.

Control system integration

Figure 5. Inside pipe welding.

compromising any fabrication quality, automated tube end bevelling machinery, hotwire GTAW for joining small diameter process tubes, and also joining the end connectors to pipe spool components, must be integrated into the production lines. Additionally, modular welding torch sets with motorised slide modules are required to automate the welding of different size geometries and designs.

Elbow pipe welding One of the most common components used in oil and gas piping is the elbow angle. This fitting provides the simplest way to alter the flow deviation in piping systems. Angle bending is typically 90° or 45° degrees. The bigger the pipe diameters and wall thicknesses are, the more challenging it will be to meet the operational demands. In the production of critical pipe components, there is absolutely no room to compromise on quality.

54 World Pipelines / NOVEMBER 2023

Most modern production control systems include all the functions that effective components and special pipe production require. When quality is one of the most important criteria, a well-rounded production control system becomes a necessity. Automation solutions utilising welding and production control systems with adaptive multi-pass SAW functionality for thick materials have a wide range of tools to control process parameters. A verified welding parameter library, WPS, ensures a reliable welding process without the possibility of human errors during the welding process. The actual weld data can be monitored and stored with ID information for QC and tracking purposes. Integration of control systems, including the welding process itself, and controlling welding movements by linear or rotating systems make an effective management tool for operators to monitor the process, collect data, control process parameters, and enable full management of the production equipment, such as C&B, material handling, and welding power sources.

Conclusion In a rapidly changing environment, traditional manufacturing industries need to improve their operations to maintain competitiveness. Increasing the level of production automation towards robotics is a great choice, in a world where the amount of highly skilled welders is decreasing, because many younger people are not interested in these more traditional jobs. Ongoing change in the energy sector also creates opportunities for manufacturing companies that are agile, willing to change, and to invest in modern technologies.

Jo Anne Watton, CEO, UTComp, Canada, discusses quantitative tools for assessing corrosion barrier condition.

Before it’s too

l at e B

uilt to withstand the toughest operating conditions, fibre reinforced polymer (FRP) composites play a critical role in corrosion control and improved reliability of pipelines and other industrial equipment in many sectors. Accurately assessing the condition of in-service FRP assets is essential in order to detect damage, prevent failures and provide guidance on the remaining life of equipment made from these materials. However, while there have been remarkable advances in FRP design and construction codes over the years, progress has been slower in developing consensus standards for non-destructively inspecting FRP piping and other equipment after it is in service. Non-destructive inspection must provide quantitative information on the extent of the damage that has occurred so that the condition of the FRP can be assessed using engineering methods. The recent publication of Welding Research Council (WRC) Bulletin 601 provides reliability engineers with a technically valid, quantitative and repeatable process for evaluating in-service FRP equipment. “WRC-601 is a major step forward in addressing the gap in inspection needs for FRP assets,” said the bulletin’s author Geoff Clarkson, Founder and Chief Technical Officer of UTComp Inc. “Providing a safe, reliable and cost-effective method to assess fitness for service of FRP composite piping is critical, especially in the chemical processing and petroleum sectors where FRP piping is widely used to transport hazardous materials, and protecting people and the environment from accidental leaks or spills is a top priority.” WRC-601 provides technical validation and guidance for assessing FRP equipment using inspection methods, including ultrasonic techniques developed by UTComp that can detect and quantify the damage that occurs to these materials while in service. Currently, the consensus code developed by the American Petroleum Institute and American Society of Mechanical Engineers (API 579-1/ASME FFS-1) is focused primarily on fitness for service assessments of metal piping, tanks and pressure vessels. Contents of WRC-601 are expected to inform new sections of the code – the first-ever for non-metallic materials. The UltraAnalytix® NDT system combines off-the-shelf ultrasound technology with proprietary algorithms, to provide data about the condition of FRP composites by monitoring the changes that take place in the polymer over time. These changes can be

used as the basis for repair and replacement planning – essential for managing the impacts of corrosion on industrial equipment, which NACE International has estimated to cost the global economy US$2.5 trillion/yr. “Regular inspections using the UltraAnalytix system have become a key component of the corrosion control and fitness for service assessment strategies of FRP asset owners around the world in a variety of sectors,” Clarkson said.

Development of corrosion-resistant FRP FRP composite piping, pressure vessels, tanks, scrubbers and other equipment have been in industrial service in chemical plants, refineries, wastewater plants and other facilities since the 1950s. In addition to providing superior corrosion resistance, FRP composites are an economical, lightweight, strong and durable alternative to metals for many applications, including pipelines. Depending on the type of resin used, they provide heat resistance up to 165˚C (329˚F) operating temperatures, and the resins in FRP pipes also protect the reinforcement material from chemical attack while providing leak protection and a smooth interior surface that ensures a low-friction environment for optimal flow. As the science and understanding of these materials evolved over the decades, standards and codes were developed for design and construction of FRP that aligned with standards and codes for equipment made with metallic materials. One of the design features that evolved to significantly improve reliability of FRP equipment is to incorporate a corrosion-resistant barrier onto the inner surface of the FRP that is to be exposed to corrosive chemical conditions. The corrosion barrier protects the fibre components of FRP used for structural support from damage by the operating environment. The corrosion barrier is normally composed of layers of reinforced thermosetting polymer or a thermoplastic sheet. A thermosetting polymer is a polymer that is applied in liquid form with curing agents added that react with the polymer to form bonds between the polymer chains, known as cross-linking. Examples of thermosetting polymers include epoxy, vinyl ester, and polyester resins. A thermoplastic polymer is a polymer that can be

deformed by some combination of heat and stress. Examples of thermoplastic materials include: polypropylene, polyvinyl chloride, polyethylene, polyvinylidene fluoride, and many others. After the use of corrosion barriers was introduced in the late 1960s, asset owners and engineers understood that a key requirement for maintaining FRP reliability was to monitor the condition of the corrosion barrier. This approach almost always involved some combination of confined space entry, visual inspections and destructive testing that required operational shutdowns. But construction codes provide no guidance for inspections of FRP or the damage that can be expected once the equipment is in operational service. Industry organisations such as API developed inspection codes for destructive and non-destructive testing (NDT) of in-service steel pipes – including standards for ultrasonic inspection. Many industries rely on ultrasound technology as their go-to NDT methodology for detecting corrosion, loss of thickness, cracking and other defects in steel infrastructure. However, while FRP has a long record of success safely transporting and storing petroleum products, corrosive acids and other materials, NDT of FRP piping is relatively new. “UltraAnalytix is a proven non-destructive and non-intrusive assessment system that provides a reliable, repeatable and scalable method for inspecting in-service FRP pipelines and ensuring their safe performance and maximum lifespan,” said Clarkson. “We’ve completed thousands of assessments worldwide and our results have been validated through academic research and by hundreds of comparisons with destructive tests in the field.” Conventional inspection approaches, including destructive testing and visual inspections that typically require confined space entry, are not well-suited to assessing pipeline networks due to the small diameter of the equipment and the vast amount of piping snaking through a typical facility. Regular visual external inspections are important but provide only limited insight. The patented UltraAnalytix system provides trained inspectors with the tools they need to assess fitness for service by efficiently gathering data to accurately calculate FRP thickness and determine corrosion barrier condition anywhere along a piping circuit, calculate the percentage of design stiffness (PDS) and estimate remaining service life (RSL).

Assessing FRP piping: key factors to consider

Figure 1. The UltraAnalytix system allows inspectors to determine the condition of FRP anywhere in a facility, including reinforcements at key locations such as access hatches, without confined space entry.

56 World Pipelines / NOVEMBER 2023

A recent case study illustrates the value of the UltraAnalytix approach for pipeline owners. Project managers planning the expansion of a large phosphoric acid plant in the Middle East engaged UTComp to assess the condition of existing FRP pipeline systems at the facility. The inspection team examined over 5 km of side-by-side piping used to transport acidic solutions from various parts of the plant to a port storage facility where phosphoric acid is loaded onto ships for export. Designed for operating pressures of 1000 kPa, some sections of pipe had been in service for nearly 20 years, while other sections were less than a decade old. Inspection of the piping followed UTComp’s standard practice: as each ultrasonic survey was completed, an external inspection was also completed to identify surface damage such as cracks, UV damage, gouges, blisters, corrosion damage to supports; condition of flanges, nozzles, lugs and repads, disbonding or peeling, and more.

The inspection team evaluated a phosphoric acid emptying and export line, dividing each into 100 m sections that were inspected and reported upon. The assessment revealed some corrosion barrier damage plus evidence of leaks and corrosion damage to key components that needed repair. However, in general, the piping systems were in good condition with a RSL exceeding six years in most sections of the facility.

Damage mechanisms affecting FRP are different In general, steel loses thickness over time but not strength; FRP won’t usually lose thickness but will lose stiffness and strength in ways that until recently were difficult to measure without destructive testing. Fitness for service evaluation of FRP piping is based upon striking a balance between the mechanical and chemical stresses applied on in-service equipment and its design capacity. Failure modes describe visible damage such as cracking or delamination that can occur over time; damage mechanisms are the underlying processes and changes in the FRP material that lead to the appearance of a failure mode. There are three main damage mechanisms that occur in FRP: ) Damage to the polymer matrix or resin. ) Damage to the reinforcement fibres. ) Damage to the interface between the matrix and the fibres.

Figure 2. Damage mechanisms affect the components that combine to give FRP strength and stiffness. Problems almost always start in the resin or polymer. While polymer damage is invisible to the naked eye, it is detectable using UltraAnalytix, which calculates changes in stiffness (PDS) as a proxy for several damage mechanisms.

These damage mechanisms affect all the components that combine to give FRP strength and stiffness. Problems always start in the resin or polymer rather than the fibre reinforcement; generally, the fibre fails only after the polymer has failed and the damage may go undetected before a leak occurs. Therefore, it’s important to identify polymer damage early on to avoid bigger problems in the future. The challenge is that

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initially, polymer damage is invisible to the naked eye. However, it is detectable using the UltraAnalytix system, which calculates changes in stiffness (PDS) as a proxy for several damage mechanisms.

For the phosphoric acid plant discussed in this case study, the inspection team created 34 IPs that covered 623 CMLs and involved 2492 UltraAnalytix readings.

Inspection plans required for each piping circuit

Standard components to consider

FRP pipeline systems have several distinct components that each require slightly different analysis of ultrasonic readings taken by following UTComp procedures. The make-up of each piping system or circuit is often unique or different from other piping systems or circuits at the same facility. API 570 requires an inspection plan (IP) for each piping system or circuit to be inspected. IPs are created within UltraAnalytix software so that readings can be assigned to specific condition monitoring locations (CMLs). For each FRP piping system or circuit, the IP is intended to show specific CMLs so that the current condition of the piping and components can be tracked at known locations, and piping condition can be determined.

There are generally seven standard components to consider for FRP piping systems: fittings, butt and wrap joints, socket joints, flanges, spools, spools at joints (SAJ), and repads. Each of these is treated separately and included with the results found in the Piping System Report prepared for each IP. FRP piping components are classified based on a pressure rating developed by following calculations and tests according to a standard specification, practice or guide. Generally, piping systems are designed and installed so that the design pressure rating exceeds the actual operating conditions for the piping. In most cases where FRP piping or a pressure vessel has failed, the equipment was not operating outside its allowable temperature range or stress levels. Historically, FRP equipment could remain in operation for years with no visible signs of distress or damage, then a failure would occur without warning that would remove the equipment from service. These failures almost always appear as fractures, cracks or leaks in the polymer and may lead to eventual breaking of the reinforcement. UltraAnalytix gives inspectors the tools they need to monitor the condition of the polymer and identify developing failures in time for corrective action. The UltraAnalytix system does this by calculating three main values: ) PDS. ) Thickness of the FRP. ) Depth of damage to the corrosion barrier.

PDS is defined as:

PDS = (Current flexural modulus) / (Design flexural modulus) Generally, PDS values above 50% indicate the material is in overall good condition and will be fit for service until the next scheduled inspection. Values 40 - 50% indicate problem areas that may require an engineering review, while PDS values below 40% indicate a high risk of equipment failure requiring immediate action.

Case study results

Figure 3. A UTComp inspector takes UltraAnalytix readings of a pipeline section at a phosphoric acid plant in Jordan. API 570 requires detailed Inspection Plans for each piping section or circuit to be evaluated.

58 World Pipelines / NOVEMBER 2023

While both pipelines were in generally good overall condition, there were numerous examples of visible damage due to corrosion and also some loss of FRP thickness and corrosion barrier damage detected by UltraAnalytix. Typical problem areas included cracked rubber at expansion joints and cracked or mismatched flanges that needed repair. “While conventional ultrasonic testing can be used to measure thickness and find cracks and other defects, UltraAnalytix does more,” said Clarkson. “By providing a fast, reliable way to calculate changes in stiffness (PDS), FRP thickness and the depth of corrosion barrier damage, it quantifies the condition of the material and provides owners with reliable data to make informed decisions about their FRP assets.”

PRESSURE DROP?

NO PROBLEM Is your pressure drop due to subsea leakage from a flange, or metal loss damage? Pooya Gholami, Iranian Offshore Oil Company (IOOC), Iran, offers a handy calculative solution.

ipeline integrity and assuring a pipeline’s ability to withstand the operational conditions have always been important issues for both the onshore and offshore industries. The common solution for checking the integrity of a pipeline is hydrotesting, which in a very general way

can be divided into hydrostatic testing and leak testing. Hydrostatic testing uses liquid media under pressure to test the structural integrity of weld joints and piping spools, while leak testing uses gas or service media, at (or close to) the maximum working pressure of the system, to serve as a final confirmation that the

system is ‘leak tight’ and ready for service.1 In both methods, the pipeline system is filled with liquid media (usually water) and is pressurised by gradually injecting additional media into the system. Once the system gets to the final pressure value, its behaviour is investigated based on observing pressure drop or

visually witnessing a leakage from the pipeline. These tests are commonly used in both onshore and offshore pipelines. Once a leakage is recognised in a pipeline system, further remedial actions to be taken are dependent on the pipeline’s location and condition. When the pipeline is onshore, technicans patrol the pipeline route and look for wet soil to find the leakage location and take further repair actions. When putting an offshore pipeline under a pressure test (hydrostatic or leak test) and encountering a pressure drop, patrolling the pipeline (which in offshore is called pipeline survey) in pursuit of the leakage location would be difficult, time consuming and very expensive. However, if some evidence was found that could help the test team to somehow limit the pipeline zone under survey and reduce the survey length, or even target for particular suspicious items on the pipeline, the time and cost would be drastically reduced. The point of difference here is the time and cost of patrolling or surveying onshore pipelines verses offshore pipelines. It is common to test onshore pipelines section by section, which means that even if a long pipeline is going to be pressure-tested, it is divided into smaller sections based on technical calculations and standards. Offshore pipelines, by comparison, are commonly pressure tested along their whole length. Surveying the whole length of an offshore pipeline using DP vessels and subsea observational equipment (such as ROVs) looking for a probable leak would be much more timeconsuming and expensive than patrolling a particular section of an onshore pipeline. Thus, the idea of differentiating between sources of leakage in subsea pipelines during leak test operations is very useful. When performing a leak test or a hydrostatic test on a subsea pipeline and encountering a leakage, it is always a challenge to find the reason and location of the leakage.

Theoretical background and basis of physics The idea for this article arose during an actual problem when a pressure drop was observed during leak testing of a subsea pipeline. The leakage was later found to be from a recently installed flange connection during a subsea repair. But the subsea repair team did not witness the leakage accurately on the seabed, and the test team could not figure out that the leakage was from the exact flange that was undergoing the leak test. There is a substantial difference between leakage from a flange and leakage from general damage: their leaking areas are different. The leaking area from general damage is constant and does not change with pressure changes inside the pipeline (as the pipeline pressure drops when the liquid media is leaked out of it). The leaking area in a loosened or not-properly-installed flange is not constant, and is reduced as the pipeline pressure is dropping due to the leak. Thus, investigating the theoretical physics behaviour of fixed-area and variable-area leakages is the key to finding the solution. Physical and mathematical basis of pressure leakage responses in piping systems has earlier been investigated by others. Schwaller and Van Zyl have presented work based on reviewing other articles and also modelling the pressureleakage response of water distributing systems based on

60 World Pipelines / NOVEMBER 2023

individual leak behaviour.2 Some part of their work, especially in regard to modelling the behaviour of variable-area leakages, has been utilised in this article. Their paper presents valuable work on the theoretical background of the leakage concept in piping systems. Then, Kabaasha et al. showed that the relationship between an area of a variable-area leakage and inside pressure is linear: “Using finite element analysis under linear elastic deformation, Cassa & Van Zyl (2013), showed that leak area varies linearly with pressure irrespective of leak type, loading conditions, pipe material and section properties. Some experimental studies like Ferrante et al., (2012 and 2013), have also confirmed these results. Ssozi et al (2015) also investigated the impact of viscoelasticity on pressure–leakage relationship using finite element analysis and found a linear relationship”.3 The famous Fluid Mechanics by Frank White is useful for drawing the actual situation of the question case into physics and mathematics.4 Another useful document in predication of volume changes of a pipeline under pressure is the TOTAL General Specification.5 After defining the problem and finding its basis in physics, and also investigating the theoretical background of the problem, the mathematical and numerical calculations were begun to solve it.

Physics of the problem Every real-life question that is going to be solved with help of physics and mathematics needs to be divided into common smaller physics questions. Here, the question can be simplified as follows: there is a subsea pipeline filled with water which is pressurised up to a certain pressure value (final test pressure) and, due to a leakage in the pipeline (the source of which is unknown), the pipeline pressure is dropping with a measurable rate. The target is to find the relation between the rate of pressure drop and the area of leakage. Thus, the question can be divided and simulated into following typical questions in physics. A. Changes in the leakage area of a leaking flange due to pressure changes inside the pipeline can be modelled according to an equation of a variable leak area.2,3 B. The leakage itself can be considered as an orifice. The equations can be derived from Bernoulli’s principle.4 C. The pressure change of the pipeline under pressure due to a medium discharge can be calculated based on hydrostatic testing equations.5 Hence, a mathematical equation can be presented for each scenario above, based on theoretical physics: A. Considering the nature of a leaking flange, it can be declared that the leaking area of a flange would be zero at a certain pressure value (P0). This is obvious as when there is a leaking flange and the pressure is dropping, the final dropped pressure would never be zero and a loosened flange maintains a certain pressure value. Also, the relation between the leakage area and the pipeline’s inside pressure is linear.2,3 Thus, this relation can be described with the following equation: (1) Where:

A = leak area at pressure P. k = head-area slope (potential of pipe to increase leak size under pressure). P0 = initial pressure (the pressure at which leak area is zero). B. Hydraulically, leaks are orifices and therefore should adhere to the orifice equation.3 Thus, the relation between the leak flowrate and the inside pressure of the pipeline can be derived from Bernoulli’s principle, which is written for fluid media before and through the orifice (leakage):4 (2) Where: P1 = hydrostatic pressure of fluid media before the orifice. ρ = density of water. V1 = velocity of fluid media before the orifice. g = acceleration due to gravity. h1 = elevation of fluid media before the orifice. P2 = hydrostatic pressure of fluid media through the orifice. V2 = velocity of fluid media through the orifice. h2 = elevation of fluid media through the orifice. According to familiar concepts of fluid mechanics, it is known that the velocity of fluid media before the orifice (V1) is zero.4 Also, the elevation of fluid media before and through the orifice (h1 and h2) at the location of leakage are equal and will be omitted from the equation. So, the equation is simplified as below: (3) Moreover, it is known that the term (P1 - P2), which shows the difference between the hydrostatic pressure inside and outside the pipeline at the leakage location, is simply the gauge pressure which is measured during the leak test. In knowing that the velocity of fluid media through the orifice (V2) multiplied by the area of leakage equals flowrate of the leakage, the following equations can be concluded: (4)

pressure at leaking point would be unknown in a water-filled onshore pipeline. These pipelines always have elevation changes along their route. So, if the location of the leakage and its elevation is unknown, the actual pressure to be considered when calculating the orifice equation would be also be unidentifiable. This issue does not concern subsea pipelines, as at each elevation in the pipeline route, hydrostatic heads of water inside and outside the pipeline are equivalent and do not affect the calculations. It means that in a subsea pipeline, regardless of the location and elevation of the leakage, the orifice-based equation for leakage flowrate and pipeline pressure stays consistent. C. The relation between pipeline pressure changes and injected or discharged water during a hydrostatic test or in a pressurised pipeline can be presented as below:5 (7) Where: ΔV = incremental volume (discharged volume of water from leakage area). ΔP = incremental pressure (changes in pipeline pressure due to leak). V = geometrical volume of the whole pipeline. D = pipeline outside diameter. E = Young’s elastic modulus of steel. t = nominal pipe wall thickness. ν = Poisson ratio for steel. B = bulk modulus of water. In equation 7, the right side of the equation is constant for a specific pipeline. So, it can be concluded that the relation between water discharge from a pipeline (leakage) and its pressure changes due to leakage is linear.

(8)

By dividing both sides of the equation by time increment (Δt), and considering the fact that incremental volume (ΔV) divided by incremental time (Δt) would be the definition of flowrate (Q), it will result in:

And thus:

(9) (5)

And finally by combining equations 6 and 9, the result would be:

Or:

(10) (6)

Where: P = pipeline inside pressure. A = leak area at pressure P. Q = flowrate of leakage at pressure P. ρ = density of water. An important note to be mentioned here is that this calculation is only applicable to subsea pipelines and not onshore pipelines. The reason for this is that the accurate

This equation shows the mathematical difference between a variable-area leakage in comparison with a fixed-area leakage. Once the leakage area (A) is fixed, equation 10 shows an exponent of 0.5 to the pipeline pressure (P). But when the leakage area is variable (as in equation 1), equation 10 shows an exponent of 1.5 to the pipeline pressure. This means that the variation of pipeline pressure upon time and, more visibly, the variation of pressure change upon time (rate of pressure drop upon time) would vary from a fixed-area leakage to a

NOVEMBER 2023 / World Pipelines

variable-area leakage. And that is the key to differentiating them accordingly.

Numerically solving the question by visual illustration of an example

Mathematical equations might seem a little incoherent. However, by selecting a sample situational example and presenting a visual illustration of the subject, the topic becomes more Nominal size 30 in. understandable. Length 147 km In order to define a sample example with actual values, let’s Outside diameter 762 mm use the real pipeline that initially inspired this article. The data Wall thickness 17.5 mm for this subsea pipeline is shown in Table 1. Inside diameter 727 mm It is assumed that the pipeline is being leak tested at pressure 3 Geometrical volume 61 021 m of 60 bars and it does not withstand the test pressure. So, Young’s Elastic Modulus 2 070 000 bar the pipeline pressure starts to drop. It is assumed that at this Poisson ratio 0.3 pressure (60 bar) a 1 in. diameter leakage is causing the pressure drop which gives an area of 0.0005067 m2. In order to compare the variable-area leakage (leaking flange) with fixed-area leakage (general damage) more accurately, it is assumed that at the test pressure (60 bar) both hypothetical leakages have the same area. It is clear that as the pressure starts to drop, the area of the hypothetical leaking flange reduces while the area of hypothetical damage remains constant. Also, it is known that when the pipeline pressure drops due to a fixed-area leakage (here considered as a general damage), it will continue to drop until it reaches zero pressure. But, when the pipeline pressure drops due to a variable-area leakage (here Figure 1. Pipeline pressure during pressure test with fixed-area considered as a leaking flange), it will stop at a certain pressure and variable-area leakages. (P0). This pressure can be practically measured once observed during a pressure test. In this example, this value is considered to be 6 bar. But it can be any other value and it is provable that it does not affect the final conclusion. Moreover, the bulk modulus of water is considered as 23 000 bar for the calculations. With all this being said, the pipeline pressure in periods of 1 min. (incremental time) has been calculated in both cases (fixed and variable area leakages) and is presented in Figure 1. As it can be seen in the graph, the algorithm of the pressure drop is completely different in fixed-area and variable-area leakages. But it will not be distinguishable in a jobsite due to the fact that there will not be access to some data that were initially assumed here: most importantly the initial area of the leakage. Here in this example, it was assumed that the initial area of the Figure 2. Pipeline pressure drop rate during pressure test with leakage is 0.0005067 m2. However, during an actual pressure test fixed-area and variable-area leakages. operation, the actual area of leakage will be unknown. Thus, Table 2. Sample numerical calculations for fixed-area leakage although the shape of these two Time (min.) Initial Initial area Flow velocity Flowrate End End area Pressure curves are different, it will not be pressure of leakage (lit/min.) pressure (m2) drop rate (m2) (bar) (m/s) (bar) (bar/min.) possible to easily distinguish the two types of pressure drops with 0 60 0.000507 109.5 3330.4 59.13 0.000507 fixed and variable area sources. 1 59.13 0.000507 108.7 3306.1 58.26 0.000507 0.87 Consequently, here comes 2 58.26 0.000507 107.9 3281.9 57.40 0.000507 0.87 the solution. In order to 3 57.40 0.000507 107.1 3257.6 56.55 0.000507 0.86 distinguish the two types of 4 56.55 0.000507 106.4 3233.3 55.71 0.000507 0.85 pressure drops, one needs to 5 55.71 0.000507 105.6 3209.0 54.87 0.000507 0.85 plot the diagram of pipeline 6 54.87 0.000507 104.8 3184.7 54.03 0.000507 0.84 pressure changes upon time. It 7 54.03 0.000507 104.0 3160.5 53.21 0.000507 0.83 means that the rate of pressure 8 53.21 0.000507 103.2 3136.2 52.38 0.000507 0.83 drop be measured (here it is 9 52.38 0.000507 102.4 3111.9 51.57 0.000507 0.82 calculated) and be illustrated 10 51.57 0.000507 101.6 3087.6 50.76 0.000507 0.81 during time. The result is shown To be continued… in Figure 2. Table 1. Characteristics of the example pipeline

62 World Pipelines / NOVEMBER 2023

Table 3. Sample numerical calculations for variable-area leakage Now the difference is obvious. Time (min.) Initial Initial area Flow velocity Flowrate End End area Pressure The rate of pressure drop when the pressure (m2) of leakage (lit/min.) pressure (m2) drop rate pipeline has a fixed-area leakage (bar) (m/s) (bar) (bar/min.) (general damage) is linear upon 0 60 0.000507 109.5 3330.4 59.13 0.000499 time. On the other hand, the rate 1 59.13 0.000499 108.7 3252.8 58.28 0.000491 0.87 of pressure drop when there is a 2 58.28 0.000491 108.0 3177.5 57.45 0.000483 0.85 variable-area leakage (leaking or 3 57.45 0.000483 107.2 3104.6 56.63 0.000475 0.83 loosened flange) in the pipeline is 4 56.63 0.000475 106.4 3033.9 55.84 0.000468 0.81 not linear upon time. Thus, these 5 55.84 0.000468 105.7 2965.3 55.06 0.000460 0.79 two types of leakages can easily be 6 55.06 0.000460 104.9 2898.8 54.30 0.000453 0.78 distinguished by a sharp-sighted test team and, consequently, the 7 54.30 0.000453 104.2 2834.2 53.56 0.000446 0.76 survey team can directly go to the 8 53.56 0.000446 103.5 2771.6 52.84 0.000439 0.74 suspicious points without having to 9 52.84 0.000439 102.8 2710.8 52.13 0.000433 0.73 survey the whole pipeline. 10 52.13 0.000433 102.1 2651.7 51.43 0.000426 0.71 It also should be noted that To be continued… in actual real life situations, the diagrams and curves would not be so clear and vividly distinctive. The lines and curves might get These results can be re-examined with different values of a little confusing and vague. So, one should master the basic of initial assumptions. It is worth mentioning that in this research, physics and mathematics in order to be able to differentiate a different values have been examined and the final result and linear curve from a non-linear curve. conclusion have remained steady. A sample of numerical calculations regarding each type of leakage is presented in Tables 2 and 3. The same data has been Conclusion used for illustration of earlier presented diagrams. With the help of physics and mathematics, it was proved that In Tables 2 and 3, the time based calculations have been a fixed-area leakage can be differentiated from a variable-area continued accordingly so that the required data for plotting the leakage in a subsea pipeline, regardless of the location and size diagrams and curves in Figure 1 and Figure 2 are provided. of the leakage. The most applicable usage of this discrimination

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is when a subsea pipeline is being hydrostatically pressure tested and fails the test. More importantly, when there are suspicious flanges within the pipeline, this simple method helps to decide whether the flanges are leaking (variablearea leakage) or general damage/a hole/metal loss is causing the leak (fixed-area leakage). This idea can be very useful when one wants to avoid unnecessary subsea surveys by means of expensive vessel and ROVs, or any other subsea leak detection device. Of course, this solution is only applicable when variable-area leakage is recognised and the survey team can go directly to the location of suspicious flanges or connections. However, if a fixed-area leakage is recognised, the subsea survey of the whole pipeline is unavoidable. To summarise this solution, the following steps can be defined for a test team to distinguish the fixed-area leakage from a variable-area leakage during a hydrostatic pressure test: 1. Collect all pipeline data and install accurate measuring devices on the pipeline. 2. Make sure the pipeline is fully filled of water and air content is evacuated as much as possible. 3. Pressurise the pipeline to a certain value according to allowable test pressure. 4. Stop pressurising and let pipeline pressure drop while measuring the pressure. 5. Record the pipeline pressure very accurately within small periods of time. 6. Make sure any change in pipeline pressure is meticulously observed and recorded. 7. Plot the pipeline pressure upon time (as in Figure 1). 8. Calculate pressure changes (pressure drop) within smallest periods of time (eg. 1 min.). 9. Plot the pressure drop rates upon time (as in Figure 2). 10. If the plot of pressure drop rate upon time is linear, the leakage is most likely to be fixed-area. 11. If the plot of pressure drop rate upon time is not linear, the leakage is most likely to be variable-area. The following additional steps can be considered as additional ways to differentiate the two types of leakages: 12. Let the pipeline pressure completely drop to its lowest possible value for a long period of time. 13. If the pipeline pressure drops to certain zero pressure, the leakage is most likely to be fixed-area. 14. If the pipeline pressure does not drop to zero pressure and remains steady at a certain pressure value, the leakage is most likely to be variable-area.

References 1.

Seal For Life Industries

OBC, 29

Stark Solutions

STATS Group

YPI

2. 3.

4. 5.

‘Introduction to Leak Testing’, by Gate Keeper in reference to ASME Boiler and Pressure Vessel Code, Section V-A10 ‘Leak Testing’, October 2013. SCHWALLER, J. and VAN ZYL, J. E., ‘Modeling the Pressure-Leakage Response of Water Distribution Systems Based on Individual Leak Behavior’, Journal of Hydraulic Engineering, December 2014. KABAASHA, A. M., VAN ZYL, J. E., and PILLER, O., ‘Modelling Pressure: Leakage Response in Water Distribution Systems Considering Leak Area Variation’, 14th CCWI international conference, Computing and Control in Water Industry, November 2016, Amsterdam, Netherlands. 7 p. hal01549955. WHITE, F., ‘Fluid Mechanics’, 7th edition, McGraw-Hill, New York, 2011. TOTAL Exploration Production, ‘Hydrostatic Testing of Submarine Pipelines’, General Specification, SP-STR-544.

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