World Pipelines September Issue 2022

®

Volume 22 Number 9 - September 2022

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 9 | SEPTEMBER 2022 03. Editor's comment

DEEPWATER PIPELINE ENGINEERING 40. Sealing solutions in HPHT environments

05. Pipeline news

Your round-up of international pipeline news and contract wins.

James Simpson, Global Segment Director Oil & Gas and Energy, Trelleborg Sealing Solutions, UK.

KEYNOTE FEATURE: DIGITALISATION 09. Security, visibility, and detection at the OT edge

WELD INSPECTION TECHNOLOGY 47. 3D modelling focus

14. A new path for process control

WELDING 50. Capturing emissions

A reliable network is essential to the smooth operation of any business, and it’s especially important in critical infrastructure environments like pipelines, says Jori VanAntwerp, CEO and Co-founder, SynSaber, USA. Magnus Hammar, Global Segment Manager, ABB, USA, discusses how advances in technology are providing an alternative, cost-effective and flexible approach when setting up new oil and gas process control systems.

Masateru Ito, Evident Corporation, Japan.

Adam Murray, Vice President of Performance Products, WeldFit, USA.

ike many other pipeline operations, when a midstream operator in the central plains of North America had to perform updates and tie-ins to a newly acquired 136 mile section of 16 in. natural gas pipeline, they already were facing multiple challenges. Not only were they focused on the day-to-day tasks associated with transporting product safely and efficiently, but they were also striving to respond to growing public and investor demand – not to mention their own goals – to minimise greenhouse gas (GHG) emissions. And they had to find ways to accomplish all of those things while achieving the overriding objective of all businesses: remaining profitable.

With pipeline depressurisation an important part of this project, they turned to WeldFit’s ReCAPTM emissions recovery system to avoid venting or flaring. Until recently, those were the only options for releasing all of the natural gas in an isolated line so maintenance, testing, or other projects could safely be conducted, but both came at a

Magnus Hammar, Global Segment Manager, ABB, USA, discusses how advances in technology are providing an alternative, cost-effective and flexible approach when setting up new oil and gas process control systems.

cost in terms of emitting methane into the atmosphere – something the operator was eager to avoid.

Rather than perform costly double block and bleed line stops at multiple main line valve stations and tie-in locations, the operator decided to depressurise the entire pipeline section and conduct numerous operations simultaneously. Using WeldFit’s ReCAP equipment to depressurise the pipeline segment, recapture its more than 35 million ft3 of natural gas, and transfer the methane from the depressurised section to an adjacent pressurised system, saved the EPA equivalent of: ) The GHG emissions from more than 3500 gasolinepowered passenger vehicles driven in one year. ) The CO2 emissions from more than 1.8 million gal. of

gasoline consumed.

) The carbon sequestered by almost 20 000 acres of

forest in one year.

This emissions recovery system exceeds expectations for pipeline depressurisation, says Adam Murray, Vice President of Performance Products, WeldFit, USA.

S

etting up new process control systems in the oil and gas industry has traditionally been dominated by a critical path approach which has often added extra layers of time and complexity into projects.

The vital and multifaceted role of process control in oil and gas applications makes it important to get things right from the outset when it comes to getting new systems up and running. In larger projects in particular, the stakes are often extremely high to prevent project drift, and ensure that systems are brought online as quickly and effectively as possible without compromising functionality, reliability or safety.

To date, the design, development and commissioning of process control systems has had to follow a linear progression of critical path actions.

While this approach ensures that everything gets done that needs to be done, it can also often result in prolonged system delivery time and potentially costly project overruns, especially when elements of a project timeline rely on the successful completion of a preceding stage.

Much of this time is often associated with the work entailed in having to set up I/O systems with fixed addresses, fixed locations, fixed tags and fixed wiring, each of which have to be individually tested and installed. With each I/O dedicated to a particular function, making any future changes can be a difficult and costly exercise requiring additional time to carry out, and pushing up project costs and delivery schedules.

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Figure 1. Ogden, Iowa. 7.6 miles of 30 in. pipeline, depressurised: 585 380 psig, estimated depressurisation time: 20:30, actual time: unknown, CO2e savings: 1211 t, emissions reduction: 89.976%.

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WRAPS AND TAPES 61. Steel repair sleeves: a closer look

Allan ‘Chip’ Edwards IV, President, Allan Edwards Inc., USA.

PIGS: LAUNCHING AND RECEIVING 19. Access with ease

PIPELINE MACHINERY FOCUS 63. Electric auger boring machines

Morgan Sledd, Stark Solutions, USA.

Richard Levings, Product Manager, American Augers, USA.

23. The devil is in the detail

Brock Falkenhagen, Global Vice President, Fulkrum, USA.

28. Boosting detectability

Carey Aiken, Online Electronics Ltd., UK.

PIPELINE CONDITION ASSESSMENT 33. The importance of accuracy

Ryan Lacy, Engineering Project Manager, and Aaron Crowder, Director of Commercialisation, MMT, USA.

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Volume 22 Number 9 - September 2022

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K

ellas Midstream recently made an announcement that it has deployed continuous emissions monitoring technology at its Teeside Central Area Transmission System (CATS) terminal in the UK. North Sea pipeline and terminal owner Kellas (which is backed by BlackRock and GIC) transports 40% of the UK’s domestic gas production.

It owns and operates CATS, which takes gas from the central North Sea to a terminal in Teesside. Working in partnership with SENIOR EDITOR Elizabeth Corner Project Canary, a US-based SaaS-focused elizabeth.corner@palladianpublications.com ESG data analytics company, Kellas has installed ultra-sensitive sensors to detect, monitor and measure methane emissions from the site in real-time.

Monitoring these emissions is a major part of Kellas’s decarbonisation programme and ESG leadership strategy. “Kellas supports the North Sea Transition deal’s commitment to decarbonisation. We must lead the way in reducing carbon intensity in our own operations,” says Andy Hessell, Managing Director of Kellas.

The partnership with Kellas is Project Canary’s first international installation, following significant growth in the US. Project Canary’s ethos is that ‘not all gas molecules are the same’: its measurement and environmental performance certification solutions identify certified or responsibly sourced gas (RSG).

RSG is natural gas that has undergone independent third party certification that the molecules were produced under specified best practices for methane mitigation (e.g. certified low methane gas) as well as other best practice for minimising environmental and community impacts. An RSG framework allows gas producers and operators to confidently characterise and refine their environmental footprint, and helps buyers make informed choices about the gas supply chains from which they draw.

In the US, reports suggest that Tenessee Gas Pipeline (TGP), a Kinder Morgan subsidiary, will be given approval from the Federal Energy Regulatory Commission (FERC) to sell RSG at a premium price. TGP is looking to charge a special tariff for its producer-certified gas (PCG) or RSG, as delivered by its aggregation pooling service.

The pooling service “facilitates greater transparency and liquidity into markets for this important, lower emissions energy source,” according to Ernesto Ochoa, TGP’s Vice President of Commercial. Producers that have had their gas certified by qualified third-party organisations, including Project Canary, can supply the RSG for the pooling service.

Midstream companies are increasingly looking to partner with technology companies or academic institutions that can help them quantify and manage methane emissions, to further their ESG goals and to potentially monetise the RSG process.

This issue of World Pipelines includes an emissions capture story: on p.50, Weldfit writes about emissions recovery to avoid venting or flaring during pipeline depressurisation. The article explores the current sense of urgency among midstream operators to curtail their most frequent sources of emissions, and outlines several case studies where pipeline operators have been recapturing emissions and achieving significant environmental benefits.

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WORLD NEWS TSA reissues cybersecurity requirements

The Transportation Security Administration (TSA) announced the revision and reissuance of its Security Directive regarding oil and natural gas pipeline cybersecurity in the US. This revised directive will continue the effort to build cybersecurity resiliency for critical pipelines.

Developed with extensive input from industry stakeholders and federal partners, including the Department’s Cybersecurity and Infrastructure Security Agency (CISA), the reissued security directive for critical pipeline companies follows the directive announced in July 2021.

The directive extends cybersecurity requirements for another year, and focuses on performance-based – rather than prescriptive – measures to achieve critical cybersecurity outcomes.

Through this revised and reissued security directive, TSA continues to take steps that protect transportation infrastructure from evolving cybersecurity threats. TSA also intends to begin the formal rulemaking process, which will provide the opportunity for the submission and consideration of public comments.

Projects announced to expand Permian natural gas capacity The EIA’s latest Natural Gas Pipeline Project Tracker includes five new projects – four newly announced projects and one project under construction – since the last update in April 2022. Of the four new projects, three will expand capacity for existing pipelines, and one will be a new pipeline. If completed as planned, these five projects together would increase takeaway capacity out of the Permian Basin by a combined 4.18 billion ft3/d over the next two years.

The three capacity expansion projects were announced in May and June: )) Gulf Coast Express Pipeline Expansion, announced by Kinder Morgan on 16 May, will expand compression on the pipeline, increasing capacity by 0.57 billion ft3/d to 2.55 billion ft3/d. The project is expected to enter service in December 2023. )) The Permian Highway Pipeline Expansion, which reached

a Final Investment Decision (FID) by Kinder Morgan on 29 June, will also expand compression, increasing capacity by 0.55 billion ft3/d to 2.65 billion ft3/d. The project is expected to enter service in November 2023.

)) The Whistler Pipeline Capacity Expansion, announced

on 2 May by WhiteWater and MPLX, is a Joint Venture (JV) between Stonepeak and West Texas Gas, Inc., that will expand compression by installing three new

compressor stations on the pipeline, increasing capacity by 0.5 billion ft3/d to 2.5 billion ft3/d. The project is expected to enter service in September 2023.

The new pipeline project reached a FID on 19 May: )) The Matterhorn Express Pipeline is a JV among

WhiteWater, EnLink Midstream, Devon Energy Corp, and MPLX. This pipeline will be 490 miles long and will be able to transport up to 2.5 billion ft3/d of natural gas from the Waha Hub in West Texas to Katy, Texas. The pipeline will receive natural gas from upstream Permian Basin connections and from direct connections at processing facilities in the Midland Basin before connecting to the Agua Blanca Pipeline. The pipeline is expected to enter service in 3Q24.

The project already under construction is expected to be completed by the end of 2022: )) The Oasis Pipeline Modernisation Project will modernise and optimise Energy Transfer’s existing Oasis Pipeline. This expansion would provide an additional 0.06 billion ft3/d of Permian Basin takeaway capacity.

According to the July 2022 Short-Term Energy Outlook, the EIA expects production in the Permian Basin to increase by 2.3 billion ft3/d in 2022 and an additional 1.4 billion ft3/d in 2023.

Denmark to lead hydrogen pipeline length additions For planned and announced hydrogen pipeline projects between 2022 and 2026, Denmark is expected to lead in terms of global length additions, contributing around 35% of the total global hydrogen pipeline additions in this period, finds GlobalData.

GlobalData’s latest report, ‘Hydrogen Pipelines Length and Capital Expenditure (CapEx) Forecast by Region, Countries and Companies including details of New Build and Expansion (Planned and Announced) Projects, 2022-2026’, reveals that Denmark is set to have a total hydrogen pipeline length of 800 km by 2026 through announced projects.

Himani Pant Pandey, Oil and Gas Analyst at GlobalData, comments: “Holstebro-Hamburg is the largest upcoming hydrogen pipeline project in Denmark with a length of

450 km. Expected to start operations in 2025, the pipeline aims to supply green hydrogen from offshore windfarms in Denmark to Germany to meet local industrial demand.”

The Netherlands ranks second globally in terms of hydrogen pipeline length additions, with an announced pipeline length of 545 km by 2026. The Groningen-AlkmaarYara is the longest upcoming hydrogen pipeline project during 2022 to 2026 with a proposed length of 308 km.

Pandey adds: “Italy stands third globally with a planned hydrogen pipeline length of 440 km by 2026. The Snam Hydrogen is the longest upcoming pipeline in the country and is slated to begin operations in 2026. The pipeline is expected to boost hydrogen consumption in the country.”

SEPTEMBER 2022 / World Pipelines

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WORLD NEWS IN BRIEF USA Baker Hughes has announced an agreement to acquire Quest Integrity, a subsidiary of Team, Inc.

Netherlands HydrogenOne Capital Growth plc has invested £8.4 million (€10 million) in Netherlands-based hydrogen pipeline company Strohm.

Mexico TC Energy and Mexico’s Comisión Federal de Electricidad have announced a first-of-its-kind strategic partnership to develop world-class energy infrastructure in Mexico, to forge a strategic alliance to accelerate the development of natural gas infrastructure in the central and southeast regions.

UK Cadent has informed the market of its selected approach to delivering its flagship hydrogen pipeline project. The opportunity to provide EPCC services for the first 100% hydrogen pipeline at scale in the UK was released at the end of July 2022, and is the first step in the procurement of these and other services.

USA NGL Energy Partners LP (NGL or the Partnership) has announced the completion of the Ambassador Pipeline in the state of Michigan, USA.

Norway Research teams from Fugro and the Ocean Industries Concept Lab (OICL) at Oslo School of Architecture and Design have been exploring how best to harmonise maritime design by integrating digital innovation in next-generation workplaces for safe remote operations.

Simplified, standardised control interfaces will enhance training, remove the potential for error and enable operators to successfully perform remote operations.

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World Pipelines / SEPTEMBER 2022

Billion-dollar microbial corrosion issue tackled by new project DNV, the independent energy expert and assurance provider, has joined ExxonMobil Upstream Research Company and Microbial Insights, Inc in a joint industry project (JIP) to develop the next generation of microbiologically influenced corrosion (MIC) detection, monitoring and mitigation technology.

With global costs of corrosion estimated at US$2.5 trillion, the project aims to significantly enhance detection and monitoring methods of MIC. Difficult to detect and monitor, MIC poses a significant problem in numerous industries, and taking early action to mitigate its effects can protect the environment and safe operations by reducing the risk of costly pipeline failures.

Assembling MIC experts from across the industry, the project plans to create up

to 1200 datapoints of corrosion-tobiomarker correlations, generated on simulated pipelines with actual field waters and participant-selected service conditions.

The team aims to develop methods, tools and workflows (‘biomarker technology’) to improve reliable detection of MIC in oilfield operations, heavily leveraging advanced laboratory (bio) reactors and molecular analytical platforms that have been specifically developed for MIC biomarker discovery and KPI development.

DNV intends to partner with six to ten additional project participants with a history of MIC, or areas of particular interest for use in laboratory simulation to assist in generating samples which will aid biomarker discovery.

FOSA encourages US Secretary of Transportation to advance pipeline rulemaking The Fiber Optic Sensing Association (FOSA), has written to the US Secretary of Transportation, Pete Buttigieg, to encourage his department to move forward with a pipeline safety rulemaking, to promote the adoption of technology enhancements.

In its letter, FOSA noted that the American Petroleum Institute (API) recently completed a two year project to update its leak detection Recommended Practice (RP) documents, specifically RP1130 (computational leak detection) and RP1175 (leak detection programme management).

FOSA Chairman, Dave Cunningham wrote: “We hope that PHMSA and other agencies around the world include these updates to the industry RPs in their continued reviews and updates of pipeline safety rulemaking, reflecting the technological progress that the industry is making to keep pipelines the safest mode of transportation for a

variety of products.”

The Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020 (P.L. 116-69), enacted into law on 20 December 2020, includes a requirement that DOT promulgate final regulations “not later than 1 year after the date of enactment” that require operators of regulated gathering lines, new and existing gas transmission pipeline facilities, and new and existing gas distribution pipeline facilities conduct leak detection and repair programmes. Section 113, Leak Detection and Repair, states that the regulations must include minimum standards that reflect the capabilities of commercially available advanced technologies; the leak detection and repair programmes must be able to identify, locate and categorise leaks; and must require the use of advanced leak detection technologies.

Ipieca launches membership principles Ipieca, the global oil and gas association for advancing environmental and social performance across the energy transition, has made support of eight Ipieca Principles a new condition of membership.

The Ipieca Principles are grouped under the association’s four strategic pillars of

climate, nature, people and sustainability.

Each thematic area includes two principles: the first provides support for a UN convention or initiative, the second is designed to advance the environmental and social performance of Ipieca member companies’ operations.

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CONTRACT NEWS EVENTS DIARY 5 - 8 September 2022 Gastech

Milan, Italy www.gastechevent.com

19 - 23 September 2022

IPLOCA 2022 annual convention Prague, Czech Republic www.iploca.com/events/annualconvention/2022-convention

22 - 23 September 2022

Subsea Pipeline Technology Congress 2022 (SPT 2022) London, UK www.sptcongress.com

27 - 29 September 2022 IPE 2022

Calgary, Canada internationalpipelineexposition.com

19 - 20 October 2022

Hydrogen Technology Expo Bremen, Germany www.hydrogen-worldexpo.com

24 - 30 October 2022 bauma

Munich, Germany bauma.de/en

31 October - 3 November 2022

Williams enters agreement with PennEnergy Resources Williams and PennEnergy Resources, LLC have announced they have entered into an agreement to support the marketing and delivery of certified, low emissions next gen natural gas. The agreement includes an independent, third-party certification process that verifies best practices are being followed to minimise emissions and produce natural gas in the most environmentally responsible manner. Through its Sequent business, Williams is building a marketing portfolio to sell low carbon next gen gas to utilities, LNG export facilities and other clean energy users.

“This is another exciting step in our multifaceted strategy to grow the delivery of next gen gas to markets across the United States as well as overseas,” said Chad Zamarin, Senior Vice President of Corporate Strategic Development for Williams.

The Appalachian-sourced natural gas is

ROSEN secures contract for Pan Malaysia ILI ROSEN Group, a global supplier of leading technology for pipeline integrity management has won three packages for the five years Pan Malaysia for pipeline inline inspection services for PETRONAS Group of Companies and petroleum arrangement contractor (PACs) (Pan Malaysia ILI) contract.

The contract includes ROSEN Group in Malaysia via H. Rosen Engineering Sdn Bhd with approximately 200 pipelines for inspection in the five years with diameters ranging from 4 - 48 in. The contract covers nationwide and cross-country pipelines with Thailand and Singapore.

ADIPEC

Abu Dhabi, UAE www.adipec.com

16 November 2022

Global Hydrogen Conference 2022 VIRTUAL www.globalhydrogenreview.com/ghc22

20 - 21 February 2023

Transportation Oil and Gas Congress 2023 Istanbul, Türkiye togc.events

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World Pipelines / AUGUST 2021

derived from PennEnergy’s 378 production wells in southwest Pennsylvania that have achieved Project Canary’s TrustWellTM certification. Every well pad inspected achieved Platinum status, the highest rating available.

Williams recently entered a partnership with decarbonisation technology provider Context Labs, as well as a collaboration with Cheniere Energy, Inc., the largest US producer of LNG to implement quantification, monitoring, reporting and verification (QMRV) of greenhouse gas (GHG) emissions at natural gas gathering, processing, transmission, and storage systems. Williams is also developing clean hydrogen, CCUS, solar and renewable natural gas projects as part of its focus on commercialising innovative technologies that support a clean energy economy.

THE MIDSTREAM UPDATE •

Pipeline Technique completes triple acquisition

•

Shell USA and Shell Midstream Partners reach merger agreement

•

Phillips 66 announces expansion open season for Seminoe Pipeline

•

PetroChad exports first oil via Chad-Cameroon pipeline

•

Howard Energy Partners announces expansion

Miros wins trio of sensor contracts As part of project requirements for the monitoring of wave and current to a water depth of 10 m, WaveSystem will be installed on three of Subsea 7’s pipelay support vessels – Seven Waves, Seven Rio and Seven Sun – alongside access to Miros Cloud services delivering real-time sea state data. The award for Miros follows an agreement between Subsea 7 and Petrobras in Brazil for new longterm, day-rate vessel contracts.

Each contract comprises a three year period plus a subsequent one year option. The contracts are due to commence between 1Q22 and 3Q22.

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

A reliable network is essential to the smooth operation of any business, and it’s especially important in critical infrastructure environments like pipelines, says Jori VanAntwerp, CEO and Co-founder, SynSaber, USA.

H

ow can you detect malicious or anomalous activity at the edge of your network, when your environment includes a pipeline or disparate facilities spanning thousands of miles?

Pipeline security has become a greater public concern in recent years, with increased media and regulatory attention after the Colonial Pipeline ransomware incident in mid-2021.

Colonial Pipeline’s lack of visibility into their OT environment, combined with ‘best practice’ policy for operations, shut down a pipeline for an extended period of time. These challenges are not Colonial’s alone; this incident showed us just how little visibility into these environments we have today, and the single points of failure within that limited visibility.

The threat landscape continues to evolve, now including issues such as ransomware as a service (RaaS) and increased mass scanning techniques, and new attacks are being developed every day. While OT networks may be more likely to be a victim of ‘splash damage’ rather than a direct attack, the risks to critical infrastructure are not disputed. As a result of the increased threat and awareness of potential risks, organisations are looking for ways to improve their visibility and their defences against these attacks.

9

Organisations are updating their security policies, reviewing operations, and implementing new security platforms as a result of governmental regulations and security directives.

That being said, the reactionary (and often rushed) regulatory policies can cause pipeline operators and owners increased administrative burden, without a tangible increase in security posture.

This article presents an overview of the current state of pipeline visibility and security challenges, including environmental and technical issues that come into play. In addition, it provides some guidance on how to improve visibility and detection at the edge of your networks, even if that ‘edge’ is thousands of miles from your main data centre.

Monitoring and environmental challenges Pipelines typically run over large geographical distances, through harsh environments, and with limited communications and power infrastructure available. In addition, pipelines must comply with increasingly stringent environmental, safety, and cybersecurity regulations, frequently without the ability to tackle physical threats. To address environmental and safety regulations, new operational and multiservice applications are being deployed to take advantage of increased bandwidths from developments in WAN technology. Modern cathodic detection, leak detection, video, audio, and remote collaboration solutions have integrated with each other to link pipeline stations and control centres while allowing for expansion in future technology.

The challenge now lies in integrating these technologies and services to provide real-time or near-real-time information about the status of the pipeline and its components. While some of these systems may be able to detect anomalies or failures, they cannot necessarily identify what caused the anomaly or failure. For example, if a pump station detects a fault, it will send out a message to the operator at the control centre. However, the operator often has no way of knowing whether the fault was due to a mechanical failure, a software bug, or something else entirely. Without the ability to access the data and correlate events between different sensors, operators are unable to determine which component failed first, and, therefore, which part needs maintenance or other attention.

In order to get a more holistic view of any problems, it’s helpful to collect data from multiple sources, integrate that data, and then use analytics to understand the cause of any anomalies or failures. Part of the reason why my Co-founder and I founded SynSaber was to help empower industrial operators with data from the OT edge in a vendor-agnostic platform. The solution gives them the ability to slice and dice the data however they prefer within their current workflows prior to sending it to their existing SIEM, SOAR, MSSP, or wherever the data is needed most.

The role of regulation in pipeline security Increased guidelines and directives are often some of the first steps taken by the government or authoritative bodies responsible for regulating various industries. After the Colonial Pipeline incident, it’s widely agreed that much of the new

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World Pipelines / SEPTEMBER 2022

regulation was reactive in nature and that the regulatory bodies could have benefited immensely from reaching out directly to the community for guidance and feedback prior to publication.

With the recent revisions to the TSA Pipeline Security Guidelines, we’re hopeful that collaboration between the administrative entities and the industrial community they’re regulating continues to improve.

Below is a list of some of the regulations that pertain to organisations managing pipelines: )) IEC 62443. )) NIST SP 800-53. )) NIST Framework for Improving Critical Infrastructure

Cybersecurity. )) ISO27001 Section A12. )) API 1164. )) NERC-CIP. )) TSA Pipeline Security Guidelines (updated in July 2022).

A crosswalk of these regulations does consider the unique implementations seen with industrial control systems (ICS), but relies incredibly heavily on segmentation and air gapping to separate the native insecurities of the systems and break chains of attack. While the basic sanitisation logic offered by these regulations does make it more difficult for attackers to cause impacts to the systems, pipelines are unique in their tolerance to the adoption of new technology and increased integrations with corporate environments. This shifting set of technologydriven threat vectors is difficult to effectively measure and develop a security culture around with a remote, isolated workforce.

Getting back to basics While there is no singular regulation or solution that can protect against all possible attacks, the following list provides a good starting point for developing a strategy to better secure your pipeline environment. The key is to start with the basics: )) Segmentation – Separate networks and devices based on function and location. )) Air-gapped networks – Separate networks based on

geographic distance. )) Physical access control – Limit access to only those who

have been granted authorisation. )) Log management – Monitor logs for suspicious activity. )) Network monitoring/IDS – Monitor network traffic for

unusual behaviour. )) Firewall – Block incoming connections to known malicious

sites.

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)) Vulnerability management – Remain vigilant and aware

of new vulnerabilities as they are reported. Understand the risk to your environment and patch vulnerabilities promptly (we know this can be tricky in ICS environments, but it’s still an important part of a robust security programme). )) Security awareness training – Ensure employees know how

to properly handle sensitive information.

While ICS and pipeline environments offer unique challenges, it’s important to start with a foundation of the basic security elements listed.

Technical challenges to increasing visibility Communication architectures must incorporate multiple applications and traffic types traversing over multiple wired and non-wired paths for primary and failover information exchanges. WAN, Ethernet, MPLS, DWDM, OTN, cellular, and wireless are all used as communication mediums with a budding collection of single-purpose hosts, applications, and protocols depending on the location and project requirements.

The power and space limitations make hardware deployment increasingly challenging, lending to embedded applications with complicated deployment strategies to be managed by limited staffing. Monitorable service-level agreements (SLAs) must be delivered with network security solutions accounting for sub-50-ms network reconvergence, traffic engineering for path redundancy and selection, bandwidth reservation, and quality of service changes that prioritise operations.

Another technical challenge that pipeline owners and operators face when trying to increase visibility in their networks is the form factor involved in their environments.

Often, the equipment boxes that manage leak detection, flow valves, PLCs, and other data points are very small. Asset owners are challenged to find a solution that can harness the data from those elements, with a form factor small enough to fit within the monitoring stations and locked equipment boxes.

This is a large focus for us at SynSaber, and it’s the reason we’ve developed a software sensor with an ultra-small footprint that only needs two cores and 2 GB of RAM to run effectively. Our goal is to empower industrial operators with the data they need from the edge of their networks without requiring costly and bulky hardware.

Mitigating future risks through improved edge visibility Adoption of a robust security and visibility programme can provide metrics that enhance understanding in performance management, accounting management, fault management, and configuration management. These operations provide a foundation of data that ultimately enhances reliability in systems that are mandated to perform in real-time, and with less downtime maintenance opportunities than other verticals.

Ultimately, visibility creates opportunities for CAPEX and OPEX savings with low footprint products that consider

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variable networks, deployment limitations, protocols, and project requirements in a growing technological reservoir.

Network visibility improves reliability A reliable network is essential to the smooth operation of any business, and it’s especially important in critical infrastructure environments like pipelines. When a network fails, it causes disruptions in the flow of information throughout the company. If a network does not work properly, then it could cause a loss of productivity and revenue (i.e., Colonial Pipeline shutting down the OT network as a result of ransomware on the IT side). Greater visibility helps to improve the reliability of the network and the reliability of the critical infrastructure environment itself.

Increased visibility drives innovation Visibility also provides a platform for innovation. It allows for the development of new metrics that will drive future growth. For example, it enables the creation of new tools and techniques that allow for better monitoring and analysis of the network infrastructure and operability. This includes the ability to monitor and analyse traffic patterns, detect anomalies, and correlate events across different layers of the network. With increased visibility, it becomes possible to create new methods for managing the network based on the needs of the organisation (i.e., stop sending Tim or Tammy in a truck down to a facility when you can view data showing the anomalous activity remotely).

Visibility provides insight into operational performance and efficiency Operational performance is one of the key factors that determine the success of any business. A well-designed operation should have high availability, scalability, and performance. To achieve these goals, the network has to be monitored and analysed regularly. By increasing visibility at the OT edge, you can get insight into how your entire operation performs, rather than a fraction of your overall environment. Identify bottlenecks, find out where there is congestion, and see if there are any problems with hardware, network, or systems.

The ultimate goals: safety and reliability Asset owners, operators, and analysts in critical infrastructure typically don’t want cybersecurity ‘just for cybersecurity’s sake’ – they want safety and reliability. While implementing foundational security basics, maintaining compliance with new regulations, and increasing visibility into the edge of your networks is important, it all comes down to safety and reliability.

International pipeline operations are a critical part of many other organisations, and consumers and regulatory entities will continue to maintain their focus on the reliability and security of the industry. Whether you choose to use a software solution like SynSaber or any other monitoring and detection platform, gaining visibility into the edge of your OT networks will help to reduce risk and improve uptime, reliability, and operational efficiencies.

Magnus Hammar, Global Segment Manager, ABB, USA, discusses how advances in technology are providing an alternative, cost-effective and flexible approach when setting up new oil and gas process control systems.

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S

etting up new process control systems in the oil and gas industry has traditionally been dominated by a critical path approach which has often added extra layers of time and complexity into projects.

The vital and multifaceted role of process control in oil and gas applications makes it important to get things right from the outset when it comes to getting new systems up and running. In larger projects in particular, the stakes are often extremely high to prevent project drift, and ensure that systems are brought online as quickly and effectively as possible without compromising functionality, reliability or safety.

To date, the design, development and commissioning of process control systems has had to follow a linear progression of critical path actions.

While this approach ensures that everything gets done that needs to be done, it can also often result in prolonged system delivery time and potentially costly project overruns, especially when elements of a project timeline rely on the successful completion of a preceding stage.

Much of this time is often associated with the work entailed in having to set up I/O systems with fixed addresses, fixed locations, fixed tags and fixed wiring, each of which have to be individually tested and installed. With each I/O dedicated to a particular function, making any future changes can be a difficult and costly exercise requiring additional time to carry out, and pushing up project costs and delivery schedules.

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Opening a new path Advances in digital capabilities are opening new alternatives to the traditional critical path approach, offering scope for substantial all-round savings by allowing tasks to be carried out in parallel rather than step-by-step.

ABB’s xStream Engineering and Commissioning approach separates field installation and testing from the application programming, which can now be carried out at the same

time as hardware configuration and installation. The whole I/O structure can then be imported into the master production system containing the application code. Where typically hardware and software are interdependent and configured in sequence, ABB’s xStream Engineering tools incorporated into System 800xA® allow both to be worked on separately until the very final stages of the installation, at which point they are seamlessly brought together. xStream Engineering takes advantage of the inherent functionality and flexibility of Select I/O, ABB’s single channel Ethernet solution.

Compared to traditional critical path project execution models, this new approach can save vast amounts of time and costs at the commissioning stage, while also facilitating continuous lifecycle improvement once installed. In addition, this also provides greater flexibility to accommodate late design changes, particularly within larger and more complex projects.

I/O flexibility The key to unlocking the benefits of this approach to automation project execution is in the flexibility of the I/O hardware. Each I/O channel can be individually characterised using a plug-in hardware module, providing the freedom to mix I/O types whenever necessary. Application programming can take place offsite at the same time as hardware configuration, with users able to configure and test I/O in the field without the need for the control application software or process controller hardware, while application software can be dropped in near the end of the project. By allowing multiple tests to be performed simultaneously and automatically on multiple devices in a fraction of the time needed for manual-based testing, this non-linear approach can help achieve potential time savings for I/O loop checks of up to 90%, greatly increasing engineer utilisation in a project.

Standardising the cabinet offers the dual benefit of eliminating the need to run new cables for each and every sensor, and having to ensure that sensor signals end up in specific cabinets, as they can be terminated into any equivalent cabinet. This also helps to reduce space requirements as well as the volume and complexity of cabling.

Hardware can effectively be shipped pre-wired, with the application software dropped in later, while field testing can be performed at the site or module yard. For larger projects with potentially thousands of I/O points, this can make a huge difference to project time and costs, while for smaller projects, the cabinet no longer has to be installed in a specific location, providing greater flexibility and optimising space even further.

Simplified application programming

Figure 1. Select IO both high integrity and intrinsically safe functionality.

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Applications are programmed using a cloud-based deployment environment, which can be configured via a single laptop without having to access the physical cabinet hardware.

Software checks can be tested virtually against emulated hardware and a simulated process to ensure that the code will perform as anticipated. Again, this can take place offsite, streamlining the process once the hardware and

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Figure 2. Select IO and Ethernet IO Fieldkit with xStream Commissioning.

application meet up onsite. Both the software and hardware are configured using the same unique signal names, with digital marshalling automatically converging the application engineering project with the field I/O configuration once the two are connected onsite. This removes the need for spaceconsuming marshalling cabinets, while also potentially helping to facilitate any late changes required.

ABB’s System 800xA includes an Ethernet I/O Field Kit software, which allows users to configure and test I/O in the field without the need for control software or process controller hardware. The Field Kit runs on a normal laptop or tablet, and can be used for onsite commissioning activities where the I/O is already installed in the field, or split-staging arrangements where the I/O cabinets are located in a panel shop or fabrication yard which reduce the engineering effort significantly.

Putting the benefits in context

Figure 3. Modular enabled System 800xA - orchestration of process modules.

Concepts like xStream Engineering facilitate a new approach to automation project delivery that allow multiple steps to be carried out discretely, even at completely different locations.

Documentation can be stored and shared via the cloud, allowing all parties access to the information they need to deliver their parts of the project and providing greater visibility over progress.

For facilities such as offshore platforms, factors such as remote locations and associated transportation logistics involved in getting engineers and equipment to site can mean that any delay to a project can be enormously costly, while late changes to an application can be difficult to implement at short notice. The lack of available space in many facilities, as well as safety considerations, can also create challenges. By utilising these new methodologies, and harnessing the latest developments in automation technologies, operators can vastly reduce the length of projects, and in turn significantly reduce costs.

The prospect of being able to decrease engineering hours through reducing time spent during I/O testing is also a major benefit for meeting the growing shortage of engineers facing many operators, allowing existing resources to be deployed more effectively.

An exciting future for project execution

Figure 4. Dashboard - ABB Ability™ Genix Industrial Analytics and AI Suite.

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In response to the growing demand for faster project delivery, ABB has developed an Adaptive Execution solution, which integrates teams, technologies and processes into a single operation using virtualisation to avoid delays and budget overshoots. ABB estimates that the system can reduce automation-related capital expenditure by up to 40%, compress delivery schedules by up to 30%, and reduce start-up hours by up to 40%.

The ability to reduce the time and cost needed to configure process control systems without risking safety or functionality presents an increasingly attractive option for companies across multiple sectors. As a way of achieving this, solutions such as the xStream Engineering concept represent an exciting future both for project execution and the long-term operation and management of process control systems.

P

ipeline pigging is the act of sending a tool down a pipeline to benefit that line’s production. That benefit can come in the form of an inspection tool checking for obstructions prior to startup, a cleaning tool removing paraffin buildup for better flow, an inline inspection (ILI) tool performing periodic damage inspection, or even a separator tool creating a barrier between different media running through the same line.

Regardless of the reason, pipelines and their operators rely

on these tools. The tools themselves can take the form of a sphere, a segmented cup design, or even a multisegmented framework of measuring and inspecting devices.

No matter the form these tools take, or function they serve, a simple fact remains; somehow, the tools need to enter the pipeline they are intended to service. Often, these entryways on the pipeline have names like launcher or receiver, being added branches onto the pipeline where the tools can be loaded (launcher) and received (receiver).

Quick opening closures are proven to be the current industry standard when safety and efficiency are most important, argues Morgan Sledd, Stark Solutions, USA.

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Once at these locations, the operators must open the branch and manipulate the tool in or out of the pipeline.

Historically the domain of flanged pipes and blind flanges, quick opening closures provide a better option by allowing the operator safe, fast access to the pipeline. Stark Solutions understands that quick opening closures are not a one size fits all commodity, and offer three styles to meet the industry’s needs.

The clamp ring One of the pipeline industry’s favourite quick opening closures is the clamp ring style, which is made up of a clamp that holds the hub and door components together.

Stark Solution’s Clamp Ring closure (the S-2000) can be provided in weld end, or come with a standard RF flange, or one-piece integral flange which lends itself to easy field installation. Once the pressure alert valve (PAV) is properly operated, these closures have rapid opening and closing times due to simple latch mechanisms providing the clamping and unclamping action. The S-2000 have an O-ring seal, allowing for many O-ring materials to be chosen, depending on what the application requires. Most often built to ASME B31.8, B31.4, and B31.3 pipeline requirements as a standard, the ability to U-stamp the door exists, as well as the option to have a fully code stamped closure should the application require it. The S-2000 closures are side hinged for right-hand or left-hand operation. Starting at 2 in. (DN50) in nominal size, and going up to 48 in. (DN1200), the variety of sizes ensures there is a correct fit for pigging applications. These closures are readily available for pressures ranging from full vacuum to 2220 psi (15.3 MPag).

Having a flat door face, these designs will be heavier than a threaded closure, another widely used style, on a sizeto-size comparison, but typically have an easier-to-operate singe pivot point hinge that makes opening simpler, and adjustments easy. The flat door also provides a large surface for additional port options and keeps the overall length of the closure shorter than the threaded style that we will now discuss.

The threaded Figure 1. S-2000 10 in.

Figure 2. S-2000 in service.

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Threaded closures, like Stark Solutions S-500, are easily identified by the fact the door (commonly called the cap) screws on to the mating portion welded or flanged to the pipe (commonly called the hub). The appearance of the cap and hub vary, but generally come with an O-ring seal and hinging to hold the cap’s weight, when the weight becomes a safety issue. Like most closures, they come with a PAV to prevent the cap from being opened while the closure is under pressure, keeping the operators safe from accidental or unintended pressure release. These closures can be used in applications sized from 2 in. (DN50) through 52 in. (DN1300), in a variety of pressure ranges from full vacuum to 3705 psi (25.5 MPag) operating pressure.

As the units increase in size, a variety of options become available. These include additional port openings for valves or sensors, as well as the ability to be specified in horizontal, vertical, inclined or declined applications. The ease of operation, and the intuitive nature of the opening and closing

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operations have helped to contribute to the popularity of this type of closure over the many years it’s been in the industry. Also helpful is the more cost-effective nature of this closure design, as it’s made up of only two pressure parts: the cap and hub. These parts are typically low weight as well, compared to the other closure types, making them preferred in applications where overall project weight is a consideration. The S-500 are designed to ASME B31.8, B31.4, and B31.3 pipeline codes, and the cap only, or both components can be provided with ASME BPVC Section

Figure 3. S-500 16 in.

VIII, Div.1 U-stamp should the application require it. The S-500 doesn’t allow for full stainless-steel construction as the threading and unthreading can gall or damage the threads. However, overlay of stainless or alloy materials can be provided when necessary for corrosive environments, greatly extending the useful life of the product.

The internal door Internal door closures, like the Stark S-3000, are characterised by a door that is inserted into the hub, and then a ring or series of ring-segments expand to prevent the door from being removed. The PAV is an integral part of the opening of the S-3000 as it is attached to the closure safety segment and must be removed before the locking ring contracts and the door can be removed from the hub. A great benefit to this design is that if the operation mechanism fails, the closure will not open due to the ring still being expanded in place. This is often referred to as a ‘fail-safe design’. To handle the weight of the door and ring, the hinging is usually more robust. The hinging on S-3000 horizontal units has more than one pivot point, allowing the door to be controlled more easily while being inserted into the hub. The S-3000 is offered with O-ring seals that ensure a positive seal with full vacuum and pressures up to 2220 psi (15.3 MPag), or with lip seals that work better in higher pressure applications up to 6170 psi (42.5 MPag), or higher. Because of this, the S-3000 closure lends itself nicely in applications where frequent use and high pressures are common. The flat door provides similar advantages as the clamp product does with regard to being able to add additional ports or vents. Furthermore, the hub can be supplied weld end, welded to a flange or one-piece integral flange. When corrosion resistant materials are requested, the S-3000 closure is robust enough to easily allow weld overlay, or can be made completely from the specialty materials like stainless steel. This design scales nicely, offering sizes ranging from 6 in. (DN150) up to 84 in. (DN2100) and beyond in pressure from full vacuum to 3705 psi (25.5 MPag). While the internal door style is often seen on filter vessels, this closure style also pairs well on launcher and receiver lines.

Stark’s S-3000 are designed to ASME B31.8, B31.4, and B31.3, with the ability to U-stamp the door only, or to have all pressure components certified to ASME BPVC Section VIII DIV.1 with U-stamp.

Conclusion

Figure 4. S-3000 12 in. with flange.

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While other methods of accessing the pipeline exist, quick opening closures are proven to be the current industry standard when safety and efficiency are most important. To ensure that the operator can access the pipeline for maintenance and pigging with ease, Stark Solutions provides customised solutions to help meet the operational demands regardless of size, pressure, or material requirements. The S-500, S-2000, and S-3000 are manufactured domestically with high quality materials and components made in-house. Regardless of your specifications, Stark Solutions has a quick opening closure that will meet your demands.

Brock Falkenhagen, Global Vice President, Fulkrum, USA, outlines one of the company’s recent pipeline projects in Guyana and the key areas of inspection, quality control, statistical analysis and expediting that were supported throughout the campaign.

ulkrum is a leading global inspection, expediting, auditing and technical staffing service provider that works in over 50 countries. The team has worked on a range of global pipe mills and pipeline projects including offshore S-Lay (shallow and deepwater), offshore J-Lay, offshore flexible pipelay and cable spooling, shore-pulls, and onshore (including trenching).

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Fulkrum’s technical experts work across the entire oil and gas supply chain and, as expected, there are challenges for owners and operators due to the stringent regulations for this industry. The complexity and criticality of projects Fulkrum has supported increases as resources take owners and operators further offshore, therefore pushing equipment and technology to advance and meet new requirements for quality and safety, making the initial inspection and quality control even more vital than before.

Attention to detail A recent project in Guyana involved the production of carbon steel pipes and multi-layer coating of pipes to be installed in water depths ranging from 1600 - 1840 m at six subsea drill centres that are tied back to an FPSO. With criticality of this level, it is essential that inspections and quality control are utilised to ensure that the manufacturer

meets the clients’ HSEQ and compliance requirements.

Although pipe procurement is a ‘behind the scenes’ scope of work, it is an essential part of the project that Fulkrum supports, witnessing mechanical testing, production, welding/cladding, non-destructive testing, dimensional verifications, pressure testing, stamping, and preservation, to ensure compliance to our client’s specifications, codes, and standards. This also includes creation and daily maintenance of pipe production trackers, documentation verifications, 3.1/3.2 certifications, ensuring closure of nonconformance reports (NCRs), production data and process capability analysis, and expediting suppliers for timely delivery.

Scope one: Production of carbon steel pipes

Following the work mentioned, the Fulkrum Technical Specialists witness the unloading of pipes at the Table 1. A snapshot of issues documented in an NCR regarding findings of an ultrasonic test (UT) piece used for calibration for inline UT of pipe port, movements of pipe to the coating yard, and they Description of Risk if not identified and/or Non-conformance inspect each length of pipe finding corrected identified thoroughly for damage and Failure to distribute the most Calibrating UT equipment on the Fulkrum inspector received contamination by oil, graphite, current drawing. incorrect test piece could lead to UT the drawing of a UT test piece or other environmental factors examination that would not allow for for inline calibration size detection of indications in the pipe encountered during vessel 406.4 mm OD x 35.0 mm WT wall. This could lead to a complete at the start of this project. or truck transport that may failure of the pipe while in-service.

However, during calibration negatively impact the steel Another pressing issue that was the inspector identified pipes surface. addressed through a CAR was how that the test piece did not The Fulkrum team then the supplier would ensure that all match his approved drawing. documents were approved by the ensures compliance of the After some investigation, it client and distributed to all parties was found that the supplier coating contractor during moving forward. revised the drawing before MPQT, all FBE and multi-layer the start of production and coating activities and testing, the revised drawings had not preservation, storage, and been distributed to the client loading to client site and or the inspectors. vessel. This assurance also includes documentation review Tolerance of manufactured Inspector found that the Calibrating UT equipment on an and approvals, NCR close-out, notch WT was out of test piece: 1 x 1 in. square improperly machined test piece could and tracking of all batch/lots of spec. notch for WT check, which lead to UT examination that would was inside surface of not allow for detection of indications materials used for coating each the test piece, has to be in the pipe wall. This could lead to piece of pipe.

Cladding defect detected during UT.

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machined at specified minimum WT (33.25 mm) and the machining tolerance under ISO 10893-12 shall be +/-0.06 mm for the wall thickness (tolerance: 33.19 - 33.31 mm). However, the mill prepared it with 32.94 mm which was out of the machining tolerance (33.19 33.31 mm).

a complete failure of the pipe while in-service.

Inspector found during UT examination that there was lamination in the cladding material that was deemed unacceptable.

Indications in cladding that are not corrected can lead to failure in the pipe cladding and shorten the life expectancy of the pipe. This could lead to a complete failure of the pipe while in-service.

World Pipelines / SEPTEMBER 2022

Scope two: Multi-layer coating of pipes Compliance is essential, so the focus for our inspection experts not only includes oversight during production of pipe to ensure that all mechanical properties, welding, cladding, dimensions, NDT, testing, and coatings are compliant to the codes and specifications, but also during installation to provide pipe traceability, verify field welding and coating processes,

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and ensure all safety protocols are followed during installation of a pipeline from a vessel or onshore.

Monitoring the production, process capabilities, and inspection process throughout manufacturing and installation can lead to identification of a number of compliance issues. The identified issues are then dispositioned and resolved by the supplier to meet the clients’ specifications, with Fulkrum monitoring the process and ensuring that the NCR is closed to the approved disposition.

Mitigation of risk, improving safety, and reducing the potential cost of non-quality is Fulkrum’s priority, and is a result of inspection oversight of the suppliers ensuring stringent adherence to the ITP and specifications during the manufacturing, production, or fabrication process.

Non-conformance reporting Figure 1. In-process dimensional gauging.

Figure 2. Surface finish verification after machining.

Figure 3. Pipes loaded out for transport to vessel.

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NCRs can document a number of different findings and issues, but most importantly they require evaluation and dispositions to ensure that the material is compliant, and the risk of recurrence is minimal. Table 1 shows a snapshot of issues documented in an NCR regarding findings of an ultrasonic test (UT) piece used for calibration for inline UT of pipe.

Additional non-conformances that the Fulkrum team of experts identified throughout the manufacturing and coating process included the suppliers lack of adherence to their internal process of heating the pipe after blasting, failures identified during mechanical testing (Charpy and Tensile), coating application at the incorrect temperature, and damage and contamination to the pipe surface during load-out and transportation.

In conclusion, inspection oversight (and the associated confidence that this provides the EPCIs, owners and operators that their supply chain was held to the highest standards of quality, safety, and equipment performance) adds an enormous amount of value by de-risking the project and ensuring timely delivery of the procured equipment.

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Carey Aiken, Online Electronics Ltd., UK, discusses making the most of improved technology and technological understanding within pig detection operations.

E

lectromagnetic (EM) pig locating and tracking allows an operator to detect and/or track the location of pigs along a pipeline. This is typically achieved by installing EM transmitters that generate ultralow frequency EM signals which can pass through the pipe wall. The signals are then received by an EM receiver outside the pipeline to allow the operator to determine the position of the transmitter and therefore the pigs they are installed within.

Applications such as the Online Electronics Android and Windows Bluetooth apps can provide advanced functionality, including simultaneous tracking of several frequencies and charts for signal visualisation.

A common question clients ask when selecting an EM system is “what range can I achieve?”, and what we are really talking about here is the detection envelope. The detection envelope is the standoff distance from the pipeline combined with the distance upstream and downstream of the EM transmitter location. Awareness of this concept and the ability to apply it to your individual pig detection operation can turn a rather challenging task into a far more straightforward one, and increases your chance of detecting a pig quickly, resulting in less downtime and/or vessel costs.

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The terms ‘pig locating’ and ‘pig tracking’ are often used interchangeably, despite being separate operations with their own specific goals. Indeed, pig tracking can turn into pig locating. For the purpose of this article, we will use pig detection as the catch-all term for any operation involving tracking or locating pipeline pigs.

Pig detecting operations When detecting pigs with an EM system, there are three typical operations with varying levels of complexity. The first, and probably the most straightforward scenario, is to confirm a stationary pig is or is not at the expected location, most commonly at the launcher and receiver. With a correctly specified EM transmitter, considering the pig design, wall thickness and pipeline size, and given that the operator knows the expected location of the pig, this should be straightforward.

The next scenario is to locate a stationary pig at an unknown location, what some refer to as a ‘lost pig’. If a pig stalls in the pipeline, the time taken to locate it could lead to cost implications, particularly for subsea ROV or diver operations.

The normal procedure to locate a stalled pig is to step methodically along the line, stopping at fixed intervals to try and detect a signal. If dealing

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with a long section of pipe, it may be tempting to take large steps, but this could result in the pig being missed. In contrast, taking very small steps could result in more steps and time taken than is necessary. The optimum size is normally about 50% of the detection envelope width. This dimension should guarantee that you do not miss the pig and find it in the most efficient timeframe.

The final scenario is confirming passage of a moving pig at a particular location or locations. The most common method of tracking a moving pig is ‘leapfrogging’ using two teams of operators. Upon detection of the pig, an operator ‘leapfrogs’ ahead of the rest of the team to the next location, ready to detect the pig as it passes again.

Tracking pigs in this way allows you to narrow down the search area in the event the pig was to stall. Ideally, the EM transmitter should be in continuous mode when tracking a moving pig. If the transmitter must be in pulsing mode due to lifetime constraints, this makes the operation more complex, and an understanding of the detection envelope will be critical to ensure that operators are separated by an appropriate distance and do not miss the passing signal.

Equally, it is possible that a pig considered stalled, is actually suffering from (unexpected) bypass, and hence travelling at a velocity lower than the medium velocity; this can be very challenging for any operator. Use of pig signallers and pig detection by leapfrogging can assist in limiting the length of pipeline necessary to be ‘searched’. It is more important than ever that the detection envelope is the maximum possible in this event.

Improving detectability There are several project specific factors that can affect EM transmitter detectability, including pipeline diameter, wall thickness, pig design, pig velocity, and if the pipeline is buried. However, something that is often overlooked is the impact the configuration of the transmitter itself can have on detectability. Often a standard specification is used, or Figure 1. Online’s range of electromagnetic transmitters allow a previous specification is then used on the next project – tracking and locating in any onshore and offshore pipeline. each project and pipeline should be reviewed on a case-by-case basis and the appropriate parameters selected.

The most obvious example of this is output power. Increasing the output power will expand the detection envelope in all directions, but this will reduce battery life.

EM transmitters should be configured with the minimum power output that achieves an effective detection envelope, whilst achieving maximum battery lifetime required Figure 2. The EMRx Applications provide a graphical representation of the received signal and can facilitate pig tracking and locating. for a project.

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World Pipelines / SEPTEMBER 2022

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Pulse rate and pulse length can also affect detectability.

As discussed, understanding pulse rate is critical, particularly if tracking a moving pig. In this situation, the operator is normally stationary with the receiver placed on the pipe wall. If the transmitter is in pulsing mode, it may not actually be transmitting at the point where the receiver is located – there may be ‘dead spots’ between pulses.

Increasing the pulse rate and/or pulse length will increase the size of the envelope, but at the expense of battery life. There is also the option of setting a transmitter in continuous mode, particularly for very fast-moving pigs. In continuous mode as opposed to pulse mode, and assuming a common power output, battery life is less but will result in an even larger reduction in battery life.

The industry standard frequency for EM transmitters used in pigging applications is 22 Hz, although the reason for this this does not appear to be backed by past research, testing, or data. After extensive testing, Online Electronics established that 22 Hz is not the

optimal frequency for pig detection and typically, lower frequencies will expand the detection in all directions. This improvement is relatively small when dealing with thin wall pipelines, but becomes significant when dealing with larger wall thicknesses.

The final thing to consider is the choice of EM transmitter model and size. It may seem acceptable to re-use or refurbish a transmitter from a previous project, but a different transmitter model may be more appropriate for your next operation. Due to the pig design, it may be less complicated to select a smaller model than what is optimal when a larger transmitter with a stronger signal will improve detectability. There may be a cost difference, but compared to vessel costs accumulated due to uncertainty of pig launch, receipt, or location, it is insignificant.

Case study A client based in the Middle East recently ran a rescue pig to allow them to locate a pig that had stalled somewhere at an unknown location in a 30 km pipeline. This situation was further complicated by the fact the pipeline was buried at a depth of 2 - 3 m.

The rescue pig was fitted with an Online 3007 EM Transmitter. Prior to launch, the location of the pig was confirmed at the reducer using an Online EMRx EM Receiver. As the MOV was being opened, the client’s operators were ready to detect the signal prior to the pipe passing through the swan neck to its buried depth, with the signal being easily detected. Two groups of operators carried out the remainder of the tracking operations, which involved detecting the EM signal at every kilometre point.

The detection capabilities of the receiver, along with the transmitter being optimally configured and sufficiently powerful, allowed the signal to be clearly received despite the pipeline being buried. Additionally, the client was armed with the knowledge required to carry out the operation in a methodical and efficient way, allowing them to recover both pigs without a large delay and the associated costs.

Conclusion

Figure 3. The EMRx Receiver was used to track the signal from a 3007 EM transmitter located inside a buried pipeline.

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World Pipelines / SEPTEMBER 2022

Until recent years, EM pig detection was considered a complicated and involved process, and relied upon personnel with years of experience to make informed judgements and decisions.

However, there has been a shift with a larger focus now placed on the science behind pig detection, increased testing, and therefore available data. This has led to the process becoming de-risked, and procedures in place to allow any operator to carry out the job effectively with the correct equipment.

Enhanced technology and product capabilities also facilitate the overall operation, making equipment more capable to carry out the task. This, combined with the knowledge of how to improve detectability and looking at each project individually, will ultimately enhance the speed and reliability of detection and pigging assurance.

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Ryan Lacy, Engineering Project Manager, and Aaron Crowder, Director of Commercialisation, MMT, USA, discuss achieving TVC records for pipelines in a non-destructive manner.

o obtain material properties, and determine pipeline material grade, operators use either destructive or non-destructive evaluation (NDE).

Until recently, destructive material verification techniques have been the most accurate in obtaining this data. Destructive methods require a sample to be removed from the pipeline, otherwise known as a cut-out. However, modern NDE technology utilising frictional sliding is more accurate than previous methods and when used, a cutout is not required. These advanced methods also include

advanced analytics which generate the same material properties as destructive testing, while leaving the pipeline uninterrupted, intact and in operation.

Looking at gas transmission assets in the US as an example, the Pipeline and Hazardous Materials Safety Administration (PHMSA), now requires traceable, verifiable and complete (TVC) records as a part of the Mega Rule.

This is a large step from the expected pipeline properties and historical records of the pressure capacity that was previously required.

33

In situations where the Mega Rule requires material properties, including material grade, operators must perform: )) Opportunistic material verification when the pipeline is exposed and the material testing records (MTRs) are not TVC. )) Re-confirmation of the pipeline maximum operating

pressure (MAOP).

Without the TVC records, default low values must be assumed. These default values can reflect a significant decrease in mechanical properties from the actual values, often having a significant impact on pipeline operation, and reduction in product throughput.

Understanding material grade The American Petroleum Institute (API) created standardised specifications for pipelines in 1928. Since then, the API-5L has undergone a series of gradual revisions, with the most recent in 2018. Despite the number of revisions, the sampling frequency for tensile properties of pipes 6 - 12 in. has remained one or two tests per lot, where a lot containing at most 200 lengths for pipes. Using 40 ft as a typical length, a lot of pipes could cover up to one and a half miles. Larger diameter pipes require twice as much testing.

For both large and small diameter pipes, the destructive tensile tests are used to determine a material grade for the entire lot of pipes. This is justified by the fact that each lot comes from the same raw materials and has the same resulting material properties, as a result.

What is TVC through in-situ testing per the Mega Rule

Figure 1. Actual material probability distribution.

Defining pipeline populations is a key step in achieving TVC records. CFR § 192.607 dictates the required testing frequency for each population of pipelines to meet the TVC specifications. Pipeline can be grouped into a population if the following criteria are the same across each individual segment: • Nominal wall thickness.

• Material grade.

• Manufacturing process.

Similarly, both the manufacturing date and construction date need to be within a two year window for the segment to be considered part of the population.

Once populations have been determined, PHMSA specifies the testing frequency options for each population.

Operators can either perform: • One examination per mile of a population, up to 150 miles.

• An alternative sampling plan, designed to achieve at least 95% confidence.

When testing to achieve TVC records, the Mega Rule specifies that NDE technologies must: • Have validation by subject matter experts.

• Conservatively account for measurement inaccuracy and uncertainty.

• Be properly calibrated.

Making the case for greater accuracy in the ditch

Figure 2. Non-destructive material verification tester, known as the HSD.

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World Pipelines / SEPTEMBER 2022

While the Mega Rule dictates the need to account for measurement inaccuracy, it is in the best interest of operators to also understand the impact of the resulting conservative shift. Most understand that

IT IS MY DUTY to safeguard my family, my

community and the environment by keeping product in the pipe.

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Our commitment to serving pipeliners, communities and the industry remains our promise to you as we greet the coming year.

For the life of your pipeline tdwilliamson.com

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accurate equipment is more likely to provide results reflective of the actual values than less accurate counterparts. With accurate tools, operators can trust that results are reflective of the actual values.

To better understand this concept, we can apply some representative numbers to a pipeline asset which has an expected grade of X52. To meet X52 grade, the material has a yield strength at or above 52 ksi. Suppose one tool, with measurement error of +/-3 ksi at 80% confidence, measures the yield strength of the material at 55.5 ksi. This results in a

conservative shift to 52.5 ksi. If a second tool measures the same 55.5 ksi, but has a measurement error of +/-4 ksi at 80% confidence, the conservatively shifted minimum is 51.5 ksi.

While the range of possible actual values at 80% confidence is wider, the less accurate tool includes the cut-off for an X52 material grade within the 80% confidence interval. The more accurate tool does not include the X52 cut-off within the confidence interval, and is more likely to measure near the actual material value.

Figure 1 shows the potential actual values and probabilities for a pipeline sample using high and low accuracy tools.

With a lower accuracy tool, there is a wider range of Sample Properties Final NDE Result API 5L Grade Verification total probabilities, and a higher chance that the measured Measured xmin xmin Test ID value is not representative of the actual material value. To Y (ksi) Y (ksi) Y (ksi) confirm grade, the actual value must be above 52 ksi. In Population 1 - 1963, X46 (Ymin = 46 ksi): No MTR this scenario, the probability of an actual material value D1-J1 54.8 ----being below 52 ksi is twice as large for the low accuracy D1-J2 50.3 35.3 -7.4 tool compared to the high accuracy tool.

D2-J1 47.7 41.9 28.5 There are also various costs associated with tool D2-J2 47.6 43.1 34.8 accuracy, with more accurate tools often costing more D3-J1 57.7 44.3 35.4 on a per-sample basis. However, when comparing D3-J2 50.9 45.2 38.1 results between samples on a given line, equipment D4-J1 54.7 46.1 39.9 with increased accuracy will have less scatter. Accurate D4-J2 52.5 46.6 41.2 tools will result in a lower spread between samples, and Population 2 - 1963, X42 (Ymin = 42 ksi): Lab Y = 53.2 ksi higher confidence for a population with a given number D5-J1 52.9 ----of samples tested. Similarly, when testing with higher D5-J2 50.3 40.4 15.7 accuracy tools, fewer samples need to be tested to D7-J1 47.5 42.7 32.6 achieve a specified confidence level and meet the Mega D7-J2 53.7 44.8 37.9 Rule specifications.

Population 3 - 1999, X42 (Ymin = 42 ksi): MTR Y = 64.8 ksi Ultimately, while the cost is higher on a per-sample D6-J1 67.5 Y = 59.6 and T = 75.2[2] basis for accurate equipment, the overall cost to confirm D6-J2 62.6 the grade of a population is lower than when testing Grey cells indicate samples tested prior to verification of material grade. If all tests with lower accuracy. Figure 4 shows both the number of are shaded, more samples would be needed to further reduce sampling uncertainty.

Population 3 was less than 1 mile, so statistical analysis is not required. The samples required for equipment of varying accuracy in a measurement uncertainty was subtracted from the minimum population NDE bar chart format and the estimated overall cost to achieve measurement (D6-J2). a specific level of confidence for each accuracy.

Figure 3. Summary of NDE results and API 5L yield strength verification in ksi.

Figure 4. Comparison of number of digs required to achieve the specified confidence level for relative tool accuracy levels.

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World Pipelines / SEPTEMBER 2022

A case study: achieving TVC records through in-ditch NDE Focusing on in-ditch NDE testing to supplement existing records on three different pipeline populations, for each dig, two pipe joints were tested on either side of the girth weld to sample more pipe joints with less excavations.

Populations 1 and 2 were both constructed by the same manufacturer in 1963, but had different expected grades, whereas Population 3 was part of a relocation project in 1999 that had MTRs available. No MTRs were available for Populations 1 and 2, but the latter had lab tensile tests performed in 1995 on two pipe joints in close proximity to the NDE excavations that are assumed to be from the same population.

Within each population, the strength results were consistent for the joints tested, and in close agreement with the destructive tensile test measurement when lab data

was available for comparison. All pipe joints tested were determined to have an HFN ERW seam based on the evident PWHT during the weld macro etch, except for the test labelled D2-J1 where a seam could not be located during the inspection. NDE measurements on D2-J1 indicated that this joint may actually be a fourth population, because it had an unusually high UTS and a chemical composition that showed large differences compared to the other joints tested, although no records could be found to verify this finding. The grade analysis in Figure 3 shows the influence of the different criterion for evaluating lower bound strength properties. The lower bound population mean _min) was found to exceed the expected grade requirements for both yield and UTS after seven samples for Population 1, and four samples for Population 2. Applying the tolerance interval (x_min), both populations would require additional testing before the lower bound strength estimates would exceed the grade requirements due to the higher sampling uncertainty. Population 3 is an example of a line segment where statistical analysis is not necessary because the entire section is less than 1 mile, and sampling guidelines of § 192.607(e) (2) requires only one test.

For this population, Figure 3 shows that the measured NDE values can be decreased by the measurement uncertainty and compared to the minimum grade requirements to verify material properties.

Conclusion While regulations differ by pipeline product type and region, in order to enable the life extension of the asset, better manage threats, ensure safe operations, and optimise performance, pipeline operators must invest in an accurate and reliable material verification technology. Validating the material properties of pressurised pipelines

is a critical step for safe operation, and an important component of an integrity management programme.

Not all pipelines are accompanied by the original MTR reflecting the strength and grade of the material or seam type of the pipeline asset. Thankfully, technologies have evolved in a way that pipeline operators can now accurately verify material properties in a non-destructive manner without having the disruption or costs associated with shutting down to perform destructive testing. The total cost of developing or validating TVC records can be reduced through obtaining more accurate measurements at fewer locations.

40

Matching the seal material to the environment is crucial to prolonging the life of seals in oil and gas applications, says James Simpson, Global Segment Director Oil & Gas and Energy, Trelleborg Sealing Solutions, UK.

A

s oilfields move further into ultra-deep water locations, the requirements for seals used in oil and gas applications increase. They must withstand the harsh conditions, extreme heat and intense pressures experienced in these high pressure, high temperature (HPHT) environments.

Safety is a key priority for the operators of offshore oil and gas facilities. The risk of leakage or the potential for outbreaks of fire increases in HPHT environments, and the consequences can be serious. Selecting the right sealing material for an application is vital in mitigating these risks.

Now more than ever, the oil and gas industry is under extreme scrutiny, with more reliable sealing solutions required to recover oil and gas in a safe and responsible manner.

Reducing emissions and protecting the environment is paramount, with companies required to comply with a range of global industry targets and requirements regardless of operating conditions.

Extreme temperatures and pressures There are often hundreds of valves and seals controlling the flow of oil from the reservoir through the wellhead and

associated infrastructure between the oil reservoir and the production system. Standard operating temperatures range from -21°C to +121°C (-5°F to +250°F), with pressures up to 690 bar (10 000 psi). Now though, seals used in the latest HPHT applications must sustain elevated temperatures in excess of +177˚C (+350°F) and pressures greater than 1400 bar (20 000 psi). This is creating a demand for new technology.

Safety To counter the risk of fire in HPHT oilfields, safer waterbased, fire-resistant, HFC hydraulic fluids protect people, the environment, and resources. Ideal for use in offshore installations, whether on surface equipment such as motion compensation cylinders on subsea equipment when used as a control fluid to operate valves and blowout preventers (BOPs), the fluids can contribute to better fire safety, offering more time to initiate fire-fighting measures and bring people to safety in the event of an accident. However, HFC fluids can present significant sealing challenges.

To ensure sealing performance is maintained in water-based hydraulic fluids, it is imperative that operators understand the effects of exposing sealing materials to these fluids at

41

high temperatures to prolong the service life and integrity of equipment, and identify the most compatible sealing material for the conditions.

Subsea blowout prevention One of the main causes of a subsea blowout, a failure in the pressure control system, is equipment malfunction. The resulting uncontrolled release of oil and gas has the potential to be life-threatening. The latest technology to prevent this includes a BOP, a specially designed safety-critical device, with a component that will seal and isolate the well, should a significant change in wellbore pressure occur.

The BOP is the last line of defence against wellbore pressure spikes to maintain control of the well. For this reason, BOP equipment is designed and heavily tested to perform with multiple redundancy systems. Seal compatibility with the hydraulic valve and control fluid is paramount to the operation of the system. Safe, reliable and predictable seal performance is critical to preventing any potential failures.

Extensive material compatibility testing is performed on the seal and expected hydraulic fluids to confirm physical properties remain within an optimal range. Once proven, equipment designers confirm sealing performance through laboratory testing and ensure compliance with industry standards.

Reliability Unplanned maintenance and downtime costs can quickly run into millions of dollars, with intervention vessels often required to remove and replace damaged equipment.

Improving seal longevity through innovative seal design and material formulations can greatly reduce this and extend planned maintenance intervals, ensuring operations can safely run for longer. Selecting the right material for the application and operating conditions is crucial to ensure seal reliability.

Rapid gas decompression is a major concern for the oil and gas industry. It occurs when applied system pressure is released, causing absorbed gas to expand, potentially damaging elastomer seals. Material selection should include rapid gas decompression (RGD) resistance to mitigate against this phenomenon.

Extended oil production Approximately 25 - 30% of the available oil reserves from a reservoir are accessed before the geological parameters change, requiring a shift in operations and further investment in equipment. Sometimes viewed as financially unviable, this can lead to abandonment. Operators are increasingly looking to extend oil production to a higher rate of above 45%. Long-term seal reliability ensures systems can operate for longer to maximise efficiencies and support enhanced oil recovery processes, improving return on investment (ROI).

Extending production from existing assets safely positively impacts the environment, removing the need to explore new locations.

Regulatory requirements Compliance with a range of regulations is a necessity for the oil and gas industry. All equipment must be tested to ensure it meets with the relevant American Institute of Petroleum (API) or ISO standards prior to use. Current API standards include API 6A, API 16C, API 17 and API 17G, with a material’s operating temperature and pressure checked and rated.

NORSOK M-710 is the qualification for non-metallic sealing materials that requires all sub-components of oilfield equipment to be compliant to the stated specification. This typically means individual seal materials must be rigorously tested and proven, including for RGD.

Selecting the right material for the application

Figure 1. Seals must be resistant to the extreme temperatures and pressures they come into contact with.

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World Pipelines / SEPTEMBER 2022

Matching the seal material to the environment is crucial to prolonging the life of seals in oil and gas applications and to ensure safe and effective operation. Seals must be resistant to extreme temperatures and pressures as well as the chemicals and media they come into contact with.

One of the most commonly used materials for seals in oil and gas is hydrogenated nitrile butadiene rubber (HNBR), an elastomer with oil resistant properties. This material type is widely known for its physical strength, abrasion resistance and compatibility with both polar and nonpolar media.

Compounds can withstand long-term exposure to heat, oil and chemicals. However, the material’s operating temperature range from -30°C to +140°C (-22°F to +284°F), making it unsuitable for use in HPHT applications.

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Figure 2. Selecting the right sealing material for HPHT applications is critical to preventing any potential failures.

For higher temperatures, fluoroelastomer (FKM) is widely used in high temperature oil-based applications up to +200°C (+392°F). The use of FKM materials in contact with water-based hydraulic fluids is not recommended, as the combination of water and temperatures in excess of +50°C (+122°F) can impact the integrity of a seal.

The most resilient material for use in water-based hydraulic applications is perfluoroelastomer (FFKM). Though seemingly more expensive than other seal material types, its compatibility with virtually all media makes it an ideal seal solution for HPHT oil and gas applications, its extended life lowering the overall total cost of ownership for the operator.

One company leading the way with HPHT material development is Trelleborg Sealing Solutions. It’s XploRTM FFKM material range is renowned within the oil and gas industry, providing sealing solutions that are resistant to RGD and aggressive process media. Developed especially for oil and gas applications, the advanced elastomer range meets important industry-specific standards and approvals such as NORSOK, NACE, API and Total.

XploR FFKM compounds combine the chemical composition of a PTFE material, with the elasticity of an elastomer, and provide chemical resistance at temperatures up to +280°C (+536°F). It is therefore the preferred choice in oil and gas applications where chemical treatments flush out debris and buildup in pipelines, providing a future-proof solution regardless of the chemicals or treatments used.

Recent developments of the Trelleborg XploR range include the XploR S-Seal and XploR FS-Seal custom-engineered, spring-energised elastomer seals. These offer the benefits of an integrally supported component with the flexibility of an elastomer seal in static applications. They provide maximum extrusion resistance in HPHT sealing environments and, unlike typical O-ring and back-up ring or T-seal solutions, these seals are single-piece components, making installation easier and safer. This is particularly so in closed grooves where multiple back-up rings, which require correct placement in the housing, are no longer needed, reducing the likelihood of damage.

In the XploR S-Seal and XploR FS-Seal, two corrosionresistant metallic anti-extrusion springs are moulded into the

44

World Pipelines / SEPTEMBER 2022

elastomer profile seal to facilitate high pressure operation through a temperature range of -45°C to +260°C (-49°F to +500°F), ensuring uniform pressure transmits in all directions across the seal footprint.

The anti-extrusion springs provide strong extrusion resistance to the seal, while the elastomer element maintains a gas-tight seal when un-pressurised. During operation, the springs work with the pressure to increase the sealing effect.

As system pressure increases, the anti-extrusion springs are forced into the extrusion gap, providing a robust and reliable seal.

The XploR S-Seal has a rectangular body and rounded seal surface. The seal replaces an O-ring and back-up rings or T-seal in HPHT static applications. The XploR FS-Seal profile has a concave feature on the base with a rounded sealing surface. This allows for increased compression in HPHT situations, specifically for large diameter clearance requirements.

High temperature thermoplastic polytetrafluoroethylene (PTFE) seals provide an alternative to elastomeric seals. An inert material, PTFE demonstrates outstanding low-friction characteristics, minimising wear. This makes it ideal for dynamic applications such as gate and ball valves, actuators, and long-term downhole completion valves as well as BOP actuation, where stick slip can be a major concern with elastomer seals.

As PTFE has limited elasticity, an elastomer O-ring or a spring usually energises PTFE seals. In oil and gas applications, the elastomer must be compatible with the temperature and pressure requirements of the environment. For ultimate temperature and chemical resistance, metal spring-activated PTFE seals can utilise NACE compliant alloy springs, such as UNS 30003 Alloy. These are resistant to all RGD and virtually all chemical degradation effects, and can operate in a wide temperature range from -60°C to +200°C (-76°F to +392°F).

When using metal spring-energised PTFE seals instead of elastomer solutions, greater consideration to the gland hardware, surface finish and installation process is needed to ensure optimum seal life and performance.

Looking to the future More than ever, companies want to increase the safety of their systems, while at the same time aim to reduce maintenance, lower the cost of unexpected downtime and protect the environment. Accelerated by environmental concerns around coal and oil, demand for natural gas is expected to grow in the coming years as we transition away from fossil fuels to greener energy. This transition brings new challenges to the industry as the creation of new methods of making renewable energy more consistent, reliable and at a lower cost, evolve. Natural gas can aid the transition if it is produced in a sustainable method utilising carbon capture and storage (CCS) technology while reducing fugitive emissions across all areas of production, transportation and processing.

The growth of hydrogen and hydrogen derivatives such as e-ammonia and e-methanol produced from renewable sources will be essential as a way of storing and releasing energy from renewable sources.

Hifi provides turnkey distributed fiber optic sensing systems specifically engineered for monitoring of pipeline assets.

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Masateru Ito, Evident Corporation, Japan, explores improving videoscope measurements of pipe welds using 3D modelling.

P

ipe weld inspections are critical to check for defects that can impact the structural integrity of a piping system. Cracks can occur in welds due to internal stress (e.g., high temperatures), while a pipe weld can corrode due to its reaction with its environment. Identifying and fixing these defects at an early stage can prevent costly and catastrophic weld failures.

One useful tool for pipe weld inspections is the videoscope, a remote visual inspection (RVI) tool with a video camera at the end of a flexible optical tube. As a non-destructive testing (NDT) technology, videoscopes can be inserted into hardto-reach inspection areas without damaging the equipment being tested.

An image of the inspection area is transmitted through the scope to a screen. Here the inspector can view the interior diameter (ID) of a pipe and measure any cracks, the heat affected zone (HAZ), and corrosion on the welds.

The challenges of measuring pipe welds using 2D videoscope images Yet, the curves of pipes can make it harder to obtain accurate measurements during videoscope inspections. Many videoscopes today produce 2D images that complicate the visual inspection process of curved, complex shapes.

2D videoscope images require you to find the highest and deepest point manually. However, the dimensions of the weld are often unclear on the 2D image, making it hard to place the measurement and

47

reference points accurately and confidently. This can lead to rework and add time to the visual inspection.

An easier way to make videoscope measurements of curved components, such as welds, is to employ 3D modelling.

An overview of 3D modelling 3D modelling is a videoscope feature that enables you to visualise the shape of complex components with various 3D views. The 3D view is shown next to the 2D view of the target. With a side-by-side comparison, you can obtain greater information about the target and confirm measurement points are in the correct location.

Various 3D modelling views aid in point selection. For instance, components shown in a 3D model can be sliced to remove unwanted objects from the view, providing a

better look at the object of interest. 3D models can also be rotated to check the placement of measurement and reference points on the component. Colour mapping is another useful feature of 3D modelling; it helps you see differences in depth at a glance by visually mapping it out with colours.

Colour mapping is particularly useful for weld inspections, as you can evaluate issues like undercuts faster. An undercut is a groove melted into the base metal at the weld toe. These defects make the welded area weaker and more likely to crack. Detecting these grooves is easier with colour-coded visuals that enable you to measure distances relative to a reference plane.

Figure 2 shows an example. The area below the reference plane defined by the triangle is red (the undercut). In contrast, the area in line with the reference plane is green. These clear visuals help you confirm the points on the left stereo image.

More confident point selection from 3D modelling has many benefits; it can help you reduce the risk of misalignment, minimise the need to remeasure, and inspect areas faster.

Applying 3D modelling to pipe weld measurements

Figure 1. Olympus IPLEX™ NX videoscope delivers high-resolution images of inspection areas.

3D modelling is a helpful tool to measure weld dimensions, such as the width, height, and pitch (ratio of width and height). The 3D views provide visual verification that speed up and improve the accuracy of measurements compared to using only 2D videoscope images.

To provide an example, imagine a videoscope user is measuring the height of a weld on a pipe’s ID. Depth measurements are performed relative to a flat plane provided by the videoscope user. However, it is challenging to create a plane with a thin enough width to lay flat on the curve of the ID. With 3D modelling, the user simply needs to rotate the 3D model to check how close the plane is to the curvature to confirm its placement. This important information cannot be obtained with a 2D image.

As mentioned earlier, 2D videoscope images require users to find the highest and deepest point manually. 3D modelling greatly simplifies this process.

The deepest and highest points can be automatically displayed as △▽, eliminating the need to manually search for the measurement points.

These 3D modelling features help inspectors take measurements of weld dimensions efficiently and confidently for a shortened inspection time.

Conclusion

Figure 2. Left: Stereo image of a weld captured using an IPLEX NX videoscope. Right: 3D model of the weld with colour mapping. The colours show the location of the undercut at a glance. Green: in line with reference plane (ref). Red: below the plane (undercut).

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World Pipelines / SEPTEMBER 2022

We live in a three-dimensional world, so 3D modelling is a powerful tool to visualise the nuances of pipe weld corrosion, and other complex defects. 3D modelling can help inspectors take accurate videoscope measurements of pipe welds for midstream oil, process piping, refineries, and many other applications.

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Unmatched Performance and Proven Results

This emissions recovery system exceeds expectations for pipeline depressurisation, says Adam Murray, Vice President of Performance Products, WeldFit, USA.

Figure 1. Ogden, Iowa. 7.6 miles of 30 in. pipeline, depressurised: 585 380 psig, estimated depressurisation time: 20:30, actual time: unknown, CO2e savings: 1211 t, emissions reduction: 89.976%.

50

ike many other pipeline operations, when a midstream operator in the central plains of North America had to perform updates and tie-ins to a newly acquired 136 mile section of 16 in. natural gas pipeline, they already were facing multiple challenges. Not only were they focused on the day-to-day tasks associated with transporting product safely and efficiently, but they were also striving to respond to growing public and investor demand – not to mention their own goals – to minimise greenhouse gas (GHG) emissions. And they had to find ways to accomplish all of those things while achieving the overriding objective of all businesses: remaining profitable.

With pipeline depressurisation an important part of this project, they turned to WeldFit’s ReCAPTM emissions recovery system to avoid venting or flaring. Until recently, those were the only options for releasing all of the natural gas in an isolated line so maintenance, testing, or other projects could safely be conducted, but both came at a

cost in terms of emitting methane into the atmosphere – something the operator was eager to avoid.

Rather than perform costly double block and bleed line stops at multiple main line valve stations and tie-in locations, the operator decided to depressurise the entire pipeline section and conduct numerous operations simultaneously. Using WeldFit’s ReCAP equipment to depressurise the pipeline segment, recapture its more than 35 million ft3 of natural gas, and transfer the methane from the depressurised section to an adjacent pressurised system, saved the EPA equivalent of: ) The GHG emissions from more than 3500 gasolinepowered passenger vehicles driven in one year. ) The CO2 emissions from more than 1.8 million gal. of

gasoline consumed.

) The carbon sequestered by almost 20 000 acres of

forest in one year.

51

CALCULATION: 164,520

Metric Tons of Carbon Dioxide (CO2) equivalent

This is equivalent to greenhouse gas emissions from:

35,449

gasoline-powered passenger

vehicles driven for one year <https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#vehicles>

408,372,883

miles driven by an average

gasoline-powered passenger vehicle <https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#miles>

This is equivalent to CO2 emissions from:

18,512,453

gallons of gasoline consumed

<https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#gasoline>

16,161,117

gallons of diesel consumed

<https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#diesel>

182,026,635

pounds of coal burned

<https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#lbscoal>

2,178

tanker trucks' worth of gasoline

<https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#tankers>

20,723

homes' energy use for one year

<https://epa.gov/energy/greenhouse-gases-equivalencies-calculatorcalculations-and-references#houseenergy>

Figure 2. Source: epa.gov calculator.

52

World Pipelines / SEPTEMBER 2022

The entire operation took only days, limiting downtime considerably compared to other interventions.

The company’s ability to achieve operational objectives and realise ESG goals simultaneously with ReCAP was not a one-off occurrence. Since WeldFit introduced the system in August 2021, pipeline operators throughout the US have been successfully using it to depressurise their lines and recover their gas before beginning maintenance, repairs, modifications and other common pipeline projects. The work has been accomplished safely and quickly, and ReCAP has consistently captured more than 99.5% of their emissions.

As of early August, ReCAP has recaptured a total of 381 753 462 ft3 of methane emissions. Keeping that natural gas from being vented is the equivalent of protecting the atmosphere from 164 520 t of CO2. And that is comparable to the emissions from: )) 35 449 gasoline-powered passenger vehicles being driven for one year. )) 408 372 883 miles driven by one average gasoline-

powered passenger vehicle. )) 16 161 117 gal. of diesel being consumed.

“Our ability to go to zero emissions safely and efficiently is pretty unmatched in the industry right now, and customers really appreciate that,” WeldFit President of Pigging & Performance Products, Eric Heinle said. “They’re very excited about the potential of it.”

What’s more, in the majority of these cases, using ReCAP has allowed operators to recover the costs of their emissions management.

“The natural gas being burned or released into the atmosphere has a value,” Heinle said. “When operators use ReCAP to recapture their gas, there’s significant savings, a significant impact on their profit and loss statement.”

In fact, many operators come out ahead on costs when they compare the value of the gas they retain to the cost of using ReCAP. And operators don’t have to be working on a 136 mile section of pipeline for ReCAP to pay off. Even in projects where the volume of gas recaptured is smaller, recompression enables operators to significantly reduce their voluntary methane emissions, which is becoming increasingly important.

Methane’s powerful punch During the last year, natural gas’ contributions to climate change have taken centre stage in climate-related discussions and policies.

While natural gas produces less CO2 than coal or crude oil, gas releases a potentially more harmful GHG: methane.

According to the US Environmental Protection Agency (EPA), during 100 years, one ton of methane in the atmosphere has nearly 30 times the warming impact of one ton of CO2 – but in the first 20 years, that ton of methane has about 80 times the warming impact of a ton of CO2.

Methane’s potential for rapid, intense warming – and the fact that climate experts believe reducing methane emissions

Figure 3. Carlsbad, New Mexico. 13 000 ft of 8 in. pipeline, depressurised: 150 - 0 psi, estimated depressurisation time: 1:47, actual time: 1:37, CO2e savings: 16 t, emissions reduction: 99.898%.

will yield immediate benefits to the climate – has drawn the attention of policymakers. The EPA, for example, has proposed a rule that, in addition to strengthening requirements for new sources of methane emissions, would also require the regulations of hundreds of thousands of existing methane emissions sources.

This growing focus on methane has sparked a sense of urgency among midstream pipeline operators to curtail their most frequent sources of emissions: voluntary gas flaring and venting. Until recently, though, coming up with a cost-effective, reliable means of working on gas pipeline without releasing the gas first seemed to be easier said than done. Even after WeldFit released ReCAP emissions recovery technology nearly one year ago, operators wondered if they could trust it on their assets. Because it was new and different, some operators waited to see how the technology would work in the field, while others were eager to give it a try. Since then, ReCAP has produced solid results.

“We’ve done everything from small jobs to massive jobs,” Heinle said. “We’ve seen just about every type of application in every type of environment, from extreme cold to extreme heat, rain, shine, and snow. ReCAP is safe; it’s efficient; and it’s proven.”

Far-reaching environmental benefits The volumes of gas operators have been recapturing with ReCAP have been significant – and impactful.

When an operator relied on ReCAP to depressurise a 30 in., 7.59 mile section of pipeline in Iowa, for example, WeldFit’s crew recaptured 65.19 t of methane, or 1335 t of carbon dioxide equivalent (CO2e).

By choosing an alternative to voluntary flaring and venting, the operator protected the atmosphere from the equivalent of 322 passenger vehicles driven for one year or 3 715 724 miles of driving by an average passenger vehicle.

Another way to look at it is, 65.19 t of methane is the CO2e of: )) Consuming 166 365 gal. of gasoline or 145 234 gal. of diesel.

Figure 4. Griffin, Georgia. 24 miles of 14 in. pipeline, depressurised: 280 - 0 psig, estimated depressurisation time: 92:10, actual time: 72:00, CO2e savings: 1098 t, emissions reduction: 99.99%.

)) Burning 1 634 144 lb of coal. )) One year’s worth of energy usage in 269 homes. )) Charging 179 846 739 smartphones.

The benefits achieved by recapturing that methane are notable, too. The carbon sequestered by keeping 65.19 t of methane out of the atmosphere is the equivalent of 24 447 tree seedlings grown for 10 years or 1811 acres of US forests in one year.

These results have been getting operators’ attention.

And in many cases, after the ReCAP crew is done, they hear something like, “I can’t believe that you removed all of the gas, and you did it so quickly,” Heinle said.

Figure 5. Killeen, Texas. 29 040 ft of 8 in. pipeline, depressurised: 250 - 0 psig, estimated depressurisation time: 13:03, actual time: 10:55, CO2e savings: 81 t, emissions reduction: 99.97%.

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World Pipelines / SEPTEMBER 2022

Speed and simplicity ReCAP’s performance is largely due to the system’s patentpending XR technology. It ensures a constant gas-transfer

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rate, meaning natural gas quickly and efficiently moves out of the isolated pipeline section and into the adjacent pressurised system during projects. That rate consistency is unaffected by pressure differentials from 1440 psi and down, providing operators with reliable outcomes.

One operator saw ReCAP’s efficiency in action as they prepared to conduct a tie-in project in New Mexico. ReCAP depressurised an isolated 2.5 mile section of gas pipeline to 0 psig in less than two hours – and moved nearly 52 000 ft3 of methane to another line.

WeldFit frequently hears from operators who ask what kind of results ReCAP can produce for them, and what the solution will cost them. In response, WeldFit has created an online calculator that’s available upon request. Users enter their project parameters, and the calculator displays an estimated cost and time to depressurise.

“Our units are highly automated, reliable, and very predictable,” Heinle said. “When we’re doing a depressurisation event for a customer, we can predict hour by hour, the progress we’re going to make. That allows customers to plan and control their costs much more efficiently.”

Since ReCAP was introduced, Heine added, its depressurisation times consistently met, or came in under, the WeldFit team’s estimates. For example, when ReCAP depressurised 29 040 ft of 8 in. pipeline for a utility company in Killeen, Texas it took less than 11 hours to go from 250 psig to 0 psig – two hours quicker than the project’s estimated time. The project prevented the equivalent of 81 t of CO2e from being released.

Additional examples of operators’ experiences with ReCAP include: )) A utility company in Georgia used ReCAP to depressurise 24 miles of 14 in. gas pipeline, depressurising it from 280 psi to 0 psi in 72 hours, and preventing the equivalent of 1098 t of CO2 from being released into the atmosphere. )) During a project for a pipeline operator in north Texas,

ReCAP depressurised 136 miles of 16 in. gas pipeline with a starting pressure of 530 psig in just under six days, preventing 5929 t of CO2e from being released. )) ReCAP allowed a Texas utility company to bring 2.4 miles

of 8 in. pipeline from 660 psig to 0 psig in 3.5 hours, preventing 16 t of CO2e from being released.

Safe solution

Figure 6. Pittsburgh, Pennsylvania. 4 miles of 16 in. pipeline, depressurised: 300 - 0 psig, estimated depressurisation time: 10:14, actual time: 9:47, CO2e savings: 59 662 t.

Figure 7. Mansfield, Louisiana. 4000 ft of 8 in. pipeline, depressurised: 1200 - 0 psig, estimated depressurisation time: 6:59, methane recaptured: 116 554 ft3, CO2e savings: 49 t, emissions reduction: 99.953%.

56

World Pipelines / SEPTEMBER 2022

Not only has ReCAP been delivering reliable depressurisation and gas recovery results, it’s been keeping people safe in the process. During ReCAP’s first year in use, no one has been hurt, and no pipelines have been damaged. The system was engineered with multiple safety features, including systems that prevent pipeline over-pressurisation during gas transfers.

What’s more, ReCAP’s simplicity and ease of use promote safety; the ability to hook up and operate the system in three steps mean minimal worker involvement – and fewer opportunities for people to be harmed. And, because operators’ employees are not venting natural gas, they’re not exposed to the personal hazards of being near pressurised pipeline contents.

Customer-driven WeldFit’s decision to develop ReCAP ties in with the company’s overall approach to business, Heinle said, talking with midstream operators about their day-to-day challenges and working to solve them.

“Customers are facing external and internal pressures to reduce their carbon footprint and stop releasing methane into the atmosphere, whether they’re large public operators with shareholders and environmental sustainability initiatives, or local operators and technicians who live in the town where they operate,” he said. “What ReCAP offers is a safe and reliable way to keep methane inside customers’ pipelines. We allow them to achieve their objectives – and to do it safely and efficiently.

“We’ve been very deliberate in the way we designed the technology and the capabilities that technology brings to bear,” Heine added. “It’s all a matter of meeting our customers’ needs.”

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Allan ‘Chip’ Edwards IV, President, Allan Edwards Inc., USA, explores the absence of a universal sleeve manufacturing specification, and its industry implications. ull encirclement steel sleeves have been a popular repair solution for over a century and are widely used by pipeline operators. Yet, despite their common acceptance and steady popularity, there is no manufacturing specification governing the fabrication of steel repair sleeves either recognised or enforced by any regulatory body in the pipeline industry.

A lack of unified standards While plenty of regulations detail usages and applications for full encirclement sleeves, as well as minimum standards for their installation, there is no formal baseline that sleeve manufacturers must abide by when fabricating repair sleeves. In short, this means that there is no standardised method for operators to verify the quality of manufactured sleeve material they receive from a sleeve vendor, aside from a visual inspection and any required documentation, like material test reports (MTRs).

Regulations such as API 1176 dictate the types of defects that repair sleeves can be used to reinforce. Other documents, such as ASME B31.8 and ASME PPC-2 recommend welding procedures when installing repair sleeves as well as minimum wall thicknesses, design pressures, lengths and grade requirements that vary per pipeline anomaly. However, aside from visual inspection, heat number logging and MTR traceability, there is no acceptance (or rejection) standard used to assess the quality of manufactured repair sleeves, nor

61

Figure 1. Steel repair sleeves bundle.

is there a required set of engineering tests that sleeves must undergo. Manufacturing requirements and quality assurance testing have been left to individual fabrication shops to determine – unless operators provide their own unique sleeve specifications.

What constitutes a repair sleeve?

Aside from the absence of a universal manufacturing specification, an interesting discussion point has arisen in recent years centring around the definition of a welded repair sleeve. Some operators interpret a full encirclement sleeve exclusively as two pieces of split half pipe. By this definition, steel repair sleeves manufactured from rolled plate would not be considered a repair sleeve. This distinction is marked by the intensive hydrostatic testing and other engineering tests that in-service pipelines – and, by extension, split half pipe sleeves – must undergo to qualify for service. These rigorous testing requirements alone act as somewhat of a manufacturing spec.

Because of their stringent testing requirements – and the lack of a universal sleeve manufacturing standard – some operators prefer split half pipe sleeves to repair sleeves manufactured from rolled plate. Unfortunately, this type of repair sleeve can be extremely expensive for operators, results in substantial waste, and contributes to fit-up problems during installation.

The complications of using split half pipe sleeves The fundamental issue with constructing sleeves from split pieces of half pipe is that the ID of the 180˚ sleeve half will not fit effectively over the OD of the same size pipeline. For example, attempting to fit a 24 in. half pipe

62

World Pipelines / SEPTEMBER 2022

sleeve over a 24 in. pipeline will result in a fit-up gap because the pipe OD is larger than the ID of the split pipe sleeve. To account for this ID/OD differential, the sleeve halves must each be cut to cover a minimum of 185˚ of the pipe surface, or 370˚ of the total circumference. Loosely translated, twice the amount of pipe is needed to complete a single split pipe sleeve repair compared to ordering the exact required amount of manufactured repair sleeves. Even if a larger-diameter split pipe sleeve was used, it would have to be re-rounded to fit the smaller pipeline – a scenario not possible in the field. Fit-up issues are common with split pipe sleeve repairs, as the sleeve halves have not been made to fit together well.

Understandably, the blurred regulatory clarity on sleeve manufacturing standards, as well as the differing opinions on what constitutes a repair sleeve, has led some operators to stay away from steel repair sleeves altogether, whether constructed from split pipe or manufactured from rolled plate.

What now?

Here is the bottom line: it is assumed that steel repair sleeves have a comparable integrity to pipeline steel. It is also assumed that steel repair sleeves are an effective long-term repair solution to reinforce pipeline defects – but, unlike pipeline steel, repair sleeves require no product validation testing to qualify them as a viable repair option. While steel repair sleeves are presumed to provide the same reinforcement and pressure capacity as the pipeline steel they are repairing, sleeve manufacturers are not required to show any proof that this is true. Why? Because there is no industry-recognised universal product manufacturing standard or specification for steel repair sleeves. As noted previously, this had led some pipeline operators to exclusively use sleeves constructed from split pieces of half pipe, despite their high costs and pervasive fit-up problems. While it is unrealistic to expect manufactured sleeves to be held to the identical testing standards of pipeline steel, there should be a unified standard to which repair sleeves conform. Currently, there is none.

Do you think there should be?

PIPELINE MACHINERY review World Pipelines’ quarterly pipeline machinery focus, featuring American Augers.

Richard Levings, Product Manager, American Augers, USA.

A

uger boring has been a staple in the construction industry for decades. However, the global environmental push to reduce emissions has caused many manufacturers to reconsider how they power their machines.

With electrical equipment starting to gain popularity in many parts of the world, the industry is seeing the beginnings of major change. While the adoption of electrical equipment, like electrical auger boring Figure 1. American Augers Electric Auger Boring Machine helps pipeline contractors machines, might be slow, the benefits will reduce jobsite emissions and enhance operator performance. prove advantageous in the future.

In fact, many cities around the world already have significantly quieter than traditional diesel-powered regulations in place that limit or ban the use of dieselmachines. This helps operators stay on the jobsite longer powered cars. Now, some cities are eyeing similar without violating noise ordinances. An EAB machine also regulations to reduce the use of diesel-powered saves costs by reducing the need for air monitoring or construction equipment. Contractors, however, shouldn’t circulating equipment. only consider a shift to using electric equipment as a The innovative electric motor allows for speed and matter of compliance. Electric equipment can deliver torque adjustment during operations, boosting operator many on-the-job benefits – from quieter and safer productivity and manoeuvrability. In other words, worksites, to enhanced equipment performance. regardless of RPMs, the machine lets operators adjust their American Augers’ new 36/42-600E electric auger torque accordingly so they can conquer difficult areas in boring machine (EAB) is designed with all this in any soil condition. It also features a torque limiter to help mind. Built with a WEG 460V electric-driven motor, prevent damage to critical components so contractors can the 36/42-600E EAB machine is emissions-free and stay efficient on the jobsite.

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To increase visibility, the 36/42-600E features a wireless remote control that allows the operator to get off the rig or even out of the pit to operate the machine. In addition, this gives operators more freedom of movement and reduces on-machine distractions during use.

One company that has been a pioneer in green underground construction options, and has already made the jump to electric equipment, is the Swedish company Riggtech. Their purchase of the American Augers 36/42-600E made Riggtech the first company in Europe and only underground construction company in the area with an electric auger boring machine.

As environmental standards and regulations on noise pollution continue to expand, the 36/42-600E allows them to bid on jobs that no other company can. “The electric auger boring machine is a differentiator for us. The public really appreciates that we offer an environmentally friendly option, and many cities are now requiring crews to meet carbon-footprint or noise-pollution standards. Since we’re the only company that owns an electric auger boring machine, we are the only company that can meet many of those regulations,” said Anders Olsson, Owner and Business Manager of Riggtech.

The 36/42-600E goes beyond just allowing Riggtech to win bids. The machine’s durability, remote-control operation and sound-reduced operation help Riggtech to quickly and quietly complete some of the most challenging jobs in the area, including a recent storm sewer installation in Gothenburg, Sweden’s Central Station.

Early adopters of the industry’s first available electric auger boring machines are discovering how the machines can reduce their jobsite emissions and improve their operations. From increased operator visibility to machine productivity, electric machines give contractors the ability to stay competitive in the marketplace and meet a broader range of bid requirements.

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