World Pipelines October 2025

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C O NTENTS

03. Editor's comment

05. Pipeline news

Updates from Sempra, Enbridge, TAP, and Plains All American Pipeline L.P.

KEYNOTE: THE MENA REGION

10. Trials and tribulations: a MENA regional report Gord Cope, Contributing Editor, surveys the energy landscape in the Middle East and North Africa (MENA) region, with particular focus on the midstream infrastructure, geopolitical risks, and the transition towards low-carbon energy.

17. Fostering pipeline safety with advancing infrastructure

Kapil Garg, MarketsandMarkets.

INTEGRITY AND INSPECTION

24. Addressing anomalies

Angel Martinez, Engineer, Frederick Mallari, Engineer, Sean Knight, Workgroup Lead, ROSEN Group.

31. A resilient monitoring strategy

Kaidy Kho, Vice President - Business Development (Sales), Atmos International, UK.

35. Turning risk into value

Pushpendra Tomar, Dynamic Risk.

EXTREME OPERATING CONDITIONS

39. From blackout to breakthrough

Carol Johnston, VP Energy, Utilities, and Resources at IFS.

ENGINEERING

45. Engineering excellence

Mike Eason, Chief Technology Officer at John Crane.

PIPELINE SERVICES

49. Modern problems require modern solutions

Stuart Mitchell, CTO, PipeSense.

53. Decisions, decisions, decisions

Trung Ghi, Prakarsa Mulyo, Ir. Syed Fazal, Harish Chhaparwal, and Arindam Das, of Arthur D. Little.

COMPRESSOR TECHNOLOGY

59. Powering compression beyond the grid

Alex Flournoy, Vice President of Business Development, Baseline Energy Services.

TRENCHLESS TECHNOLOGY

63. Enabling offshore pipeline construction

Anne Knour, Tracto Technik.

PIPELINE SENSING

68. LVDTs importance in pipeline applications

Mike Marciante, Applications Engineer, NewTek Sensor Solutions.

AERIAL INSPECTION AND INTEGRITY

75. UAV survey: a Q&A

World Pipelines interviews Aliaksei Stratsilatau, Founder and CEO of UAVOS about transforming UAV-based midstream, survey, and security operations.

Winn & Coales International Ltd has specialised in the manufacture and supply of corrosion prevention and sealing products for over 90 years. The wellknown brands of Denso and Premier offer cost-effective, long-term corrosion prevention solutions, including Viscotaq™: the ultimate range of viscoelastic coatings for effective pipeline protection.

EDITOR’S COMMENT

CONTACT INFORMATION

MANAGING EDITOR

James Little james.little@worldpipelines.com

ASSISTANT EDITOR

Emilie Grant emilie.grant@worldpipelines.com

SALES DIRECTOR

Rod Hardy rod.hardy@worldpipelines.com

SALES MANAGER

Chris Lethbridge chris.lethbridge@worldpipelines.com

SALES EXECUTIVE

Daniel Farr daniel.farr@worldpipelines.com

PRODUCTION DESIGNER

Siroun Dokmejian siroun.dokmejian@worldpipelines.com

HEAD OF EVENTS

Louise Cameron louise.cameron@worldpipelines.com

EVENTS COORDINATOR

Chloe Lelliott chloe.lelliott@worldpipelines.com

DIGITAL EVENTS COORDINATOR

Merili Jurivete merili.jurivete@palladianpublications.com

DIGITAL CONTENT COORDINATOR

Kristian Ilasko kristian.ilasko@worldpipelines.com

JUNIOR VIDEO ASSISTANT

Amélie Meury-Cashman amelie.meury-cashman@worldpipelines.com

SENIOR WEB DEVELOPER

Ahmed Syed Jafri ahmed.jafri@worldpipelines.com

DIGITAL ADMINISTRATOR

Nicole Harman-Smith nicole.harman-smith@worldpipelines.com

ADMINISTRATION MANAGER

Laura White laura.white@worldpipelines.com

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SENIOR EDITOR Elizabeth Corner elizabeth.corner@worldpipelines.com

Incentivisation is a crucial part of the midstream sector, whether you’re talking about getting pipeline projects built, attracting companies to operate them, or keeping them safe and efficient. It’s a word that policymakers and industry leaders tend to return to, since pipelines are capital-intensive and safety-critical, and none of the magic happens without financial or regulatory carrots and sticks.

The passage of US President Trump’s signature ‘Big Beautiful Bill’ in July brings changes in how companies, and state and local governments, allocate their capital investments. The new law, along with an extension of the 2017 tax cuts, and new provisions to allow immediate expensing of capital investment in the US including real property, may lead to unlocking projects throughout the US. The emphasis here is on regulatory reform and tax relief as a stimulus to private investment.

Chris Lloyd, Senior Vice President at McGuireWoods Consulting LLC, recently spoke to me about this, saying: “Clearly, the One Big Beautiful Bill sent a strong signal of support for fossil fuel energy sources and deemphasising emerging energy sources like hydrogen, which will boost the need for new pipeline infrastructure to deliver oil and gas to markets. While there are certainly some financial incentives for such projects contained in the bill, the most significant impact is likely to be in the regulatory reform and streamlining activities in the bill and through executive orders issued by President Trump.”

Of course, the US has successfully used this formula before. Look at the LNG build-out of the past decade: Gulf Coast terminals and the pipelines feeding them were unlocked by regulatory streamlining, export authorisations, and favourable tax treatment that made private capital flow more freely. Incentivisation came in the form of clearing bottlenecks and signalling policy certainty. The US has become the world’s largest LNG exporter, a position attained via midstream infrastructure financed largely by private investors responding to clear, consistent incentives. Canada, by contrast, has struggled to replicate the same model. Canada has been slow to capture a share of the global LNG market, despite being the world’s fifth largest gas producer. A mix of high costs, regulatory and permitting hurdles, and persistent opposition (particularly around Indigenous rights and environmental concerns) has delayed projects and raised investor risk. LNG Canada, the country’s flagship liquefaction project, has faced technical problems as it ramps up, while negative gas pricing highlights the strain of oversupply with limited export capacity. Together, these factors have left Canada lagging in the race for global LNG market share. According to a PolicyOptions analysis, Canada is “late to the game” and has infrastructure costs that far exceed industry norms.1

The contrast is even starker when you consider Canada’s troubled Trans Mountain Expansion project (TMX), where the government has already spent more than CAN$35 billion rescuing a pipeline that private investors walked away from. When governments subsidise projects, they seek to ensure energy security but sometimes end up cushioning projects that might otherwise have fallen on harder ground. Incentives can unlock infrastructure but also risk masking projects with weak fundamentals. Recently, some private interests and public officials are calling for government funding to construct more pipelines across Canada to enhance oil export, but Mark Kalegha, IEEFA Energy Finance Analyst argues: “Oil infrastructure development, once seen as a financial boon, is beset by rising costs and lower price trends … As the Canadian government experiences pressure to pay industry infrastructure costs from public coffers, it’s time to step back and take a hard look at the energy questions Canada faces.”

In the US, we can see how domestic policy certainty (even without perfect alignment) helps investors move. In Canada, the ‘unknowns’ make risk margins widen and leave many projects struggling to clear investment hurdles. Internationally, Trump-era policy is unpredictable (tariffs, trade disputes, sanctions) but at home, regulatory streamlining and tax relief have provided enough certainty for private capital to commit to midstream build-out.

1. https://policyoptions.irpp.org/2025/04/lng-exports

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WORLD NEWS

Sempra sells US$10 billion infrastructure stake & greenlights Port Arthur LNG Phase 2

Sempra has agreed to sell a 45% equity interest in Sempra Infrastructure Partners, one of North America’s leading energy infrastructure platforms, to affiliates of KKR, a leading global investment firm, with Canada Pension Plan Investment Board (CPP Investments). Subject to adjustments, the transaction proceeds of US$10 billion implies an equity value of US$22.2 billion and an enterprise value of US$31.7 billion for Sempra Infrastructure Partners.

The transaction is expected to close in Q2 - Q3 2026. Upon closing, a KKR-led consortium will become the majority owner of Sempra Infrastructure Partners, holding a 65% equity stake, while Sempra will retain a 25% interest alongside Abu Dhabi

Investment Authority’s (ADIA) existing 10% stake.

In addition, Sempra Infrastructure Partners has reached a final investment decision to advance the development, construction and operation of Port Arthur LNG Phase 2. This new phase will include two natural gas liquefaction trains, one LNG storage tank and associated facilities with a nameplate capacity of approximately 13 million tpa of US-produced LNG. Incremental project capital expenditures at Phase 2 are estimated at US$12 billion, plus an approximate US$2 billion payment for shared common facilities, with commercial operations expected in 2030 and 2031 for Trains 3 and 4, respectively.

Enbridge announces two gas transmission projects, capitalises on growing natural gas demand

Enbridge Inc. has signed commercial agreements for the Algonquin Reliable Affordable Resilient Enhancement project (AGT Enhancement) which is expected to increase deliveries on Algonquin Gas Transmission pipeline to existing Local Distribution Co. (LDC) customers in the US Northeast.

In addition, through its Matterhorn joint venture, the company reached a final investment decision on the Eiger Express Pipeline (Eiger), an up to 2.5 billion ft3/d pipeline from the Permian Basin to the Katy area to serve the growing US Gulf Coast LNG market.

“We continue to deliver on the US$23 billion of gas transmission opportunities we laid out at our Investor Day in March. Today’s project announcements highlight the benefits of Enbridge’s scale and demonstrate our ability to support growing natural gas demand in the US Northeast, and LNG exports from the US Gulf Coast,” said Cynthia Hansen, Executive Vice President and President, Gas Transmission. “These investments add visibility to, and extend, our growth outlook through the end of the decade.”

Once completed, AGT Enhancement will deliver

IEEFA: EU pipeline gas imports continue to fall

The EU cut its pipeline gas imports by 9% year on year in the first half (H1) of 2025, as the bloc increased its reliance on LNG and benefited from ongoing efforts to lower demand for the fuel (reports IEEFA).

The latest decline comes after EU piped gas imports fell by more than one-third between 2021 and 2024. Energy efficiency measures and the growth of renewables helped reduce the bloc’s gas consumption in recent years, according to IEEFA’s updated EU Gas Flows Tracker from the Institute for Energy Economics and Financial Analysis.

Combined EU gas pipeline and LNG imports grew 3.4% year on year in H1 2025. IEEFA expects EU gas imports to continue falling from 2026.

“EU gas demand is in structural decline. But this year’s slight rise in gas imports should be a wake-up call for Member States falling short of their energy efficiency and renewables targets,” said Ana Maria Jaller-Makarewicz, Lead Energy Analyst, Europe, at IEEFA.

“Faster deployment of solar, wind and heat pumps, as well

approximately 75 million ft3/d of incremental natural gas, under long-term contracts, to investment grade counterparties in the US Northeast. Natural gas is a key component of the energy mix in the region. This project is designed to increase reliable supply and improve affordability by reducing winter price volatility for customers. Enbridge expects to invest US$0.3 billion in system upgrades within, or adjacent to, existing rights-of-way. Subject to the timely receipt of the required government and regulatory approvals, Enbridge fully expects to complete AGT Enhancement in 2029.

Eiger is designed to transport up to 2.5 billion ft3/d of natural gas through approximately 450 miles of 42 in. pipeline from the Permian Basin in West Texas to the Katy area. Upon anticipated completion of Eiger in 2028, Enbridge expects to own a meaningful equity interest in up to 10 ft3/d of long-haul Permian Basin egress pipeline capacity that is connected to key storage facilities and LNG export hubs along the US Gulf Coast. This project is complementary to the Whistler Parent JV assets and is backed by long-term contracts with predominantly investment grade counterparties.

as rapid grid modernisation, will reduce EU countries’ vulnerability to LNG supply disruptions, improve energy security and protect consumers from volatile gas prices.”

The research reveals that since the beginning of 2022, EU countries have spent about €380 billion on pipeline gas imports, €83 billion of which was from Russia.

The end of Russian gas transit via Ukraine on 1 January 2025 contributed to the decrease in EU gas pipeline imports in H1 2025. Some EU countries shifted their gas flows and used existing infrastructure to guarantee security of supply.

The EU plans to gradually stop the import of Russian oil and gas by the end of 2027. But the bloc’s imports of Russian pipeline gas via Türkiye have increased in recent years.

The top-three sources of EU pipeline gas imports in H1 2025 were Norway (55%), Algeria (19%) and Russia via Türkiye (10%).

EU gas pipeline imports from Azerbaijan, Libya and Norway decreased year on year in H1 2025, while those from Algeria, Russia via Türkiye, Türkiye and the UK slightly increased.

WORLD NEWS

Milestone: TAP delivers 50 billion cubic metres of natural gas to Europe

IN BRIEF

Canada

Pembina Pipeline Corp. has announced that the Canada Energy Regulator (CER) has approved the negotiated settlement between Alliance Pipeline Ltd Partnership and shippers and interested parties on the Canadian portion of the Alliance Pipeline.

Australia

Northern Territory Chief Minister Lia Finocchiaro announced the finalisation of a pipeline permit for APA to construct and operate the Sturt Plateau Pipeline (SPP).

UK

Energy network SGN and UK tech company Utonomy have completed a six month trial demonstrating how advanced pressure control can significantly reduce methane emissions from Britain’s gas grid.

Egypt

Egypt’s petroleum minister has affirmed the key role of the state-owned Petroleum Pipelines Company (PPC) in enhancing Egypt’s position as a regional energy trading hub, citing its capacity to transport and store crude oil from the Red Sea to the Mediterranean. He presented a package of projects implemented to replace, renew, and upgrade petroleum product transport lines nationwide, with a total cost of about EGP 3.3 billion (US$69 million).

Tanzania

Aminex announced that Tanzania’s pipeline from the Ntorya gas field to the Madimba plant is progressing, with equipment procurement underway, construction starting in September 2025, and completion targeted for July 2026.

The Trans Adriatic Pipeline (TAP) has transported its 50th billion m3 of natural gas to Europe since the start of commercial operations.

This significant achievement demonstrates TAP’s role in ensuring a reliable, diversified gas supply to Europe, while enhancing competition and contributing to decarbonisation efforts across South-Eastern Europe.

TAP, as the European segment of the Southern Gas Corridor, brings natural gas from Azerbaijan to European markets. Since it began commercial operations in late 2020, TAP has delivered: over 41.7 billion m3 to Italy, over

4.8 billion m3 to Greece, and over 3.2 billion m3 to Bulgaria.

Luca Schieppati, TAP’s Managing Director, commented: “Reaching 50 billion m3 is more than a milestone – it’s a clear demonstration of TAP’s strategic role in strengthening Europe’s energy security and supporting climate goals [...] Looking into the future, we are ready to further contribute to these goals. In fact, the first level of TAP’s capacity expansion – set to add 1.2 billion m3 of longterm capacity per year from the start of 2026 – is already underway and will enable us to do even more.”

IEA forecasts rapid rise in global oil supply

The International Energy Agency (IEA) has indicated that global oil supply is set to increase more swiftly this year, with a surplus potentially growing by 2026.

This is due to both OPEC+ members boosting their output and the growth of supply from non-OPEC+ countries.

The IEA, which provides guidance to industrialised nations, noted a projected supply rise of 2.7 million bpd to 105.8 million bpd by 2025, and an additional increase of 2.1 million bpd to 107.9 million bpd the following year.

The OPEC+ group, comprising the eight countries of Algeria, Kazakhstan, Kuwait, Iraq, Oman, Russia, Saudi Arabia and the United Arab Emirates, has agreed to augment its production.

Following a decision on 7 September to commence unwinding its second tranche of supply cuts, the group plans to elevate its output target by 137 000 bpd in October.

At this rate, it would take one year to fully implement the 1.65 million bpd tranche of cuts, leaving 2 million bpd of cuts still in place.

The IEA’s analysis suggests that supply is increasing much faster than demand, even though it has revised its global demand growth

forecast this year to 740 000 bpd, highlighting strong deliveries in advanced economies.

The IEA said: “Oil markets are being pulled in different directions by a range of forces, with the potential for supply losses stemming from new sanctions on Russia and Iran coming against a backdrop of higher OPEC+ supply and the prospect of increasingly bloated oil balances.”

Benchmark crude oil prices experienced a decline in August, with ICE Brent futures dropping by approximately US$2/bbl monthon-month to US$67/bbl.

The IEA anticipates that global inventories will see an ‘untenable’ average increase of 2.5 million bbl/d in the second half of 2025, as supply substantially exceeds demand.

Additionally, China’s continued stockpiling of crude is contributing to keeping Brent crude prices for immediate delivery higher than those for future contracts, a market condition referred to as backwardation.

IEA added: “There are a number of potential twists and turns ahead – including geopolitical tensions, trade policies and additional sanctions on Russia and Iran – that could yet alter market balances.”

Plains to acquire 55% interest in EPIC Crude Holdings, LP

Plains All American Pipeline, L.P. and Plains GP Holdings have announced that a wholly owned subsidiary has entered into a definitive agreement to acquire from subsidiaries of Diamondback Energy, Inc. and Kinetik Holdings Inc., a 55% non-operated interest in EPIC Crude Holdings, LP, the entity that owns and operates the EPIC Crude Oil Pipeline.

The transaction is valued at approximately US$1.57 billion, which is inclusive of

approximately US$600 million of debt.

Additionally, Plains has agreed to a potential US$193 million earnout payment should an expansion of the pipeline to a capacity of at least 900 000 bpd be formally sanctioned before year-end 2027.

The EPIC Pipeline provides long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi.

MITIGATE

AC

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CONTRACT NEWS

McDermott awarded deepwater subsea contract by PTTEP in Malaysia

8 - 10 October 2025

Carbon Capture, Utilization and Storage (CCUS) Conference

Houston, USA

https://www.woodmac.com/events/carboncapture-utilization-storage-conference/

21 - 23 October 2025

Carbon Capture Technology Expo

Europe

Hamburg, Germany

https://www.carboncapture-expo.com/

3 - 6 November 2025

ADIPEC

Abu Dhabi, UAE

https://www.adipec.com/

11 - 13 November 2025

1st Pipeline Technology Conference

Asia

Kuala Lumpur, Malaysia

https://www.pipeline-conference.asia/

19 - 23 January 2026

PPIM 2026

Houston, USA

https://ppimconference.com/

11 - 15 February 2026

78th Annual PLCA Convention

Phoenix, Arizona

https://www.plca.org/annual-convention-events

15 - 19 March 2026

AMPP Annual Conference + Expo

Houston, USA

https://ace.ampp.org/home

27 - 30 April 2026

Pipeline Technology Conference (PTC)

Berlin, Germany

https://www.pipeline-conference.com/

4 - 7 May 2026

Offshore Technology Conference

Houston, USA

https://2026.otcnet.org/

McDermott has been awarded a large offshore subsea contract by PTTEP Sabah Oil Limited (PTTEP) for the Block H gas field expansion project, located offshore Sabah, in East Malaysia covering the Alum, Bemban and Permai deepwater fields.

Under the scope of the contract, McDermott will deliver engineering, procurement, construction, and installation (EPCI) services for a carbon steel pipeline, along with transportation and installation of key subsea umbilicals, risers and flowlines (SURF) components. The infrastructure is part of a broader system designed to support the delivery of additional feed gas to the Petronas Floating Liquefied Natural Gas Dua (PFLNG DUA) facility, which has been producing from Block H’s Rotan and Buluh fields since 2021.

“This award reflects PTTEP’s continued trust in McDermott’s expertise to deliver

TechnipFMC awarded two flexible pipe contracts by Petrobras

TechnipFMC has been awarded two subsea contracts by Petrobras for flexible pipe for use in multiple basins.

The first award is a substantial contract to design, engineer, and manufacture flexible gas injection risers. This hightechnology solution will sustain reservoir pressure and enhance production efficiency through high-capacity gas reinjection in presalt formations in the Santos Basin.

The second award, which followed a competitive tender, is a significant contract to design, engineer, and manufacture flexible risers and flowlines for deployment on assets in the Campos Basin.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “As Petrobras unlocks Brazil’s energy resources, we are proud to provide technology and expertise that support some of their most technically challenging projects. TechnipFMC is a subsea innovation leader and continues to advance flexible technology to support new projects and enhance value for its clients.”

Manufacturing will be fulfilled exclusively at TechnipFMC’s flexibles manufacturing facility in Açu, Brazil. For more than 40 years, TechnipFMC has delivered advanced technological solutions while supporting the development of local economies in Brazil.

complex subsea infrastructure,” said Mahesh Swaminathan, McDermott’s Senior Vice President, Subsea and Floating Facilities. “Leveraging our proven subsea engineering and marine construction capabilities, we are well-positioned to build on our strong track record of successful project execution for PTTEP. The expansion of Block H represents a pivotal development in Malaysia’s energy landscape, and our work on this project further reinforces McDermott’s strategic presence, anchored by our Kuala Lumpur office – our hub for global deepwater project delivery.”

Engineering and project management will be led from McDermott’s Subsea and Floating Facilities team in Kuala Lumpur, while offshore installation will leverage the company’s versatile marine construction fleet.

ON OUR WEBSITE

• Rystad Energy: China’s oil stockpiling explained

• FET launches new ROV control system

• Wood Mackenzie: Growth in LNG supply running up against concerns over Chinese demand

• EIA: Growing natural gas deficit leads Egypt to ramp up natural gas imports

• Thyssengas begins the realisation of cross-border hydrogen line between Netherlands and Germany

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

Gord Cope, Contributing Editor, surveys the energy landscape in the Middle East and North Africa (MENA) region, with particular focus on the midstream infrastructure, geopolitical risks, and the transition towards low-carbon energy.

The Middle East and North Africa (MENA) are essential to the world’s energy sector, supplying immense amounts of oil, gas, and refined products to energy-hungry customers. They are also at the vanguard of the surge toward a low-carbon hydrogen economy, touting billions of dollars in potential production investments.

But MENA is also the most volatile region in the world, a hotbed of armed hostilities that continuously threaten disruption to the movement of fossil fuels. While the midstream sector is often the victim of geopolitical aggression, it can also offer solutions to the turmoil and volatility.

North Africa

Algeria has been a vital ally to Europe as it pivots away from Russian gas supplies. Conventional gas reserves are approximately 159 trillion ft3, with another 230 trillion ft3 of potential shale gas reserves. Gas production, pegged at 9 billion ft3/d prior to the Ukraine war, has risen to 10 billion ft3/d with major expansions in the Hassi Bahamou field and the Hassi R’Mel LD2 complex. Further increases at existing and new fields are in the works.

Algerian production is delivered to the continent through a combination of LNG plants and major gas lines, including the 575 km, 10 billion m3/y MedGaz line from Algeria to Spain and the 2475 km, 32 billion m3/y TransMed line running from Algeria via Tunisia, to Sicily and mainland Italy.

The EU is actively exploring the use of trans-Mediterranean gas lines to reduce its carbon footprint. In June, 2025, the European Climate, Environment and Infrastructure Executive Agency awarded US$24.7 million to the Italian H2 Backbone project, which is part of a 3300 km dedicated pipeline that is expected to deliver up to 4 million tpy of green hydrogen from North Africa to Europe by 2030. The project would source green hydrogen from solar and wind-rich Algeria and Tunisia and transport it via a trans-Mediterranean line that would cross Sicily before connecting up in mainland Italy and extending into Germany. Much of the project would rely on existing gas infrastructure ROW, and Tunisia and Algeria have so far announced plans to create approximately 300 000 tpy of green capacity by 2030. A caveat; studies suggest that unless the EU initiates significant policy support, the cost of producing green hydrogen in Africa (€4.2 kg - €4.9 kg), would be far too expensive to attract European users (who currently spend between €1 kg - €2 kg).

In late 2022, Morocco and Nigeria signed a memorandum of understanding (MOU) to build the Nigeria-Morocco gas pipeline (NMGP). Although the project has been touted for several years, the Ukraine war, higher gas prices (and Morocco’s desire to eliminate Algeria’s strangle-hold on supplies), has given the National Nigerian Petroleum Co. (NNPC) and the Moroccan Office of Hydrocarbons and Mines (ONHYM) new impetus. The ROW for the US$25 billion project would travel offshore for 7000 km through the jurisdictions of 13 African countries, and deliver up to 3 billion ft3/d of gas to Morocco, where it would hook up to the (currently) inactive Maghreb Europe line and the European gas network. In late 2024, Morocco announced that it would be seeking tenders for the initial phases of the project throughout 2025, with further engineering phases in 2026. Greece, Israel, and Cyprus are promoting the Eastern Mediterranean (EastMed) project, an 1800 km gas pipeline. The ROW will start in Cyprus and connect to Greece, and then to Italy, running roughly 1200 km offshore and 600 km onshore. The line would deliver up to 10 billion m3/y from fields discovered over the last decade, including Israel’s Leviathan field (22 trillion ft3), and Tamar field (10 trillion ft3), as well as Cyprus’s Aphrodite field (7 trillion ft3), and the Calypso discovery region (10 trillion ft3). New discoveries continue to bolster the project; in July 2024, ExxonMobil and partners reported penetrating a 350 m gas column at its Pegasus-1 exploration well, located in Cyprus waters.

The Middle East

For several decades, the Kurdistan Regional Government (KRG) had been shipping 450 000 bpd of crude through the Iraq-Turkey pipeline that runs to the latter’s Mediterranean port of Ceyhan, obviating the need to pass through Iraq territory. Iraq filed a complaint with the International Chamber of Commerce, arguing that the flow should have Baghdad’s approval. In March, 2023, the Chamber ruled in favour, which resulted in operators shutting down production in Kirkuk oil fields. In early 2025, Iraq announced that it was ready to allow resumption of crude flow in the pipeline, but operators within Kurdistan are reluctant to contract export space until formal payment agreements are in place. In the meantime, members of the Association of the Petroleum Industry of Kurdistan (Akipur) including UK-based Gulf Keystone and Norway’s DNO, rely on local demand to keep their fields producing.

In April, 2025, Turkey and Iraq announced the Development Road project, a US$17.9 billion initiative to build a major energy logistics infrastructure between the two countries. The largest portion of the project will be a 2.25 million bpd pipeline that will run from Basra in southern Iraq to the border town of Silopi in Turkey, and thence to the Mediterranean port of Ceyhan. Plans are also underway to eventually reverse 5 billion m3/y flows of natural gas along the ROW.

The proposed Basra-Aqaba pipeline between Iraq and Jordan, which has been in limbo for a decade, is suddenly far more viable. The project involves a 1700 km pipeline that would run from Iraq’s oil-producing region in Basra to the Jordanian port of Aqaba, located on the northern end of the Red Sea. The US$9 billion line would carry up to 2.2 million bpd; Jordan would have the right to buy 150 000 bpd as feedstock for the Jordan Petroleum Refinery Co. in Zarqa. The project was opposed by numerous groups, including Iran-backed militias that could pose a threat to the infrastructure. In the last year, Iran has seen its proxy militias crushed but still remains a significant threat to the Strait of Hormuz. In early 2025, the Iraqi federal government earmarked approximately US$5 billion toward advancing the pipeline. While the Trump administration has yet to weigh in on the project as of press time, it would be a viable shipping alternative to the US and its regional allies should Iran close the Strait.

Egypt is a major energy hub in the eastern Mediterranean, with significant domestic production as well as the transportation of oil and gas through both the Suez Canal and a series of pipelines within its jurisdiction. In August, 2025, the country greatly expanded its imports of natural gas for both domestic consumption and eventual LNG exports when it signed an agreement to buy 130 billion m3 of gas from Israel’s Leviathan field. The US$35 billion deal will see expansion of the Leviathan platform by operator NewMed Energy, and the investment of US$400 million by Egypt into increased pipeline capacity.

Green energy

MENA countries are keen to take advantage of their abundant solar and wind resources to participate in the pivot to renewable fuels. Saudi Arabia is building an immense green ammonia plant in the NEOM project, a futuristic Greenfield development in the

country’s northwest. In June, 2025, NEOM partner Air Products announced that the US$5 billion plant was 80% complete. When it enters production in 2027, the facility will produce up to 650 tpd (240 000 tpy), primarily for export.

Since March,2024, the Egyptian government has signed over US$30 billion in renewable energy investments in the Suez Canal Economic Zone (SCZone), a waterway vital to global marine traffic. The agreements include a deal between Norway’s fertilizer giant Yara and India’s Acme Cleantech, which involves the latter supplying up to 100 000 tpy of renewable ammonia. In June, 2025, Lloyd’s Register and Germany’s DAI Infrastruktur entered into an MOU to develop a large-scale, green ammonia plant in East Port Said, Egypt. Project Ra is expected to produce up to 1.65 million tpy of green ammonia when it starts up in 2029.

Abu Dhabi is positioning itself as a major international player in low-carbon energy by leveraging carbon sequestration. In late 2024, construction began on the greenfield Hail and Ghasha Offshore Development. When it enters production in 2028, the project will yield 1.5 billion ft3/d, which will be piped ashore where facilities will sequester up to 2 million tpy of CO2 while producing low-carbon hydrogen. Also in late 2024, stateowned ADNOC announced the formation of a new firm with a multi-facet business strategy. XRG, with over US$80 billion in financial reserves, will focus on producing specialty petrochemicals, natural gas and low-carbon energy. ADNOC noted that the demand for green ammonia is expected to reach 70 - 90 million t by 2050.

The Omani government’s Hydrom, with a US$49 billion budget and 2300 km2 of land for renewable energy development, has the goal of reaching net-zero by 2050. In May, 2024, the government agency signed two new green hydrogen agreements worth US$11 billion. France’s EDF Group and London-based Yamni will build a 178 000 tpy green hydrogen plant, with an estimated start-up date in 2030. Output from the plant will be used to produce 1 million tpy of green ammonia in a facility to be built in the Salalah Free Zone.

Problems

In June, 2025, an Israeli offensive against Iranian nuclear assets also targeted conventional energy infrastructure, striking a fuel depot in northern Tehran and the nearby Shahr Rey oil refinery, as well as the South Pars gas field.

The hostilities between Israel and Iran are changing the geopolitical calculus in the region on an almost daily basis. During its strike against Iran, Israel ordered Chevron to shut down its operations at the giant Leviathan offshore gas field, shutting off supplies to Egypt. The order was in response to Iranian barrages of missiles and drones directed at Israeli assets. The field, which contains almost 23 trillion ft3 of recoverable gas, regularly ships almost 1 billion ft3/d to Egypt through the EMG pipeline. The move left Egypt scrambling to meet high seasonal demand through LNG imports.

But most stakeholders are concerned over the Strait of Hormuz. With a minimum navigable width of 40 km in some points, the Strait serves as a maritime chokepoint for the 20 million bpd of crude that passes through. Iran has long threatened to close off the passage in the event of hostilities,

but even the interference in GPS systems that the vessels use to ensure safety can cause disruptions, as was seen in June, 2025, during the height of Israel’s strikes against Iran’s nuclear facilities.

In order to ensure that its own exports would be safeguarded, Iran built the Goreh Jask crude pipeline, which runs overland for 1000 km from producing fields near Goreh to the port of Jask in the Gulf of Oman. The US$2 billion project, which skirts the contentious Strait of Hormuz, has a capacity of 1 million bpd. Since its commissioning in 2021, however, the terminal has seen limited activity; it wasn’t until late 2024, that the first VLCC supertanker was loaded with 2 million bbl of crude, as Iran was mainly relying on its primary oil export facility on Kharg Island. In any event, should Iran close the Strait, Israel, with over-powering air superiority, has the option to cripple the Jask terminal.

Iran’s opponents are weighing their own pipeline alternatives. Saudi Arabia has the 5 million bpd Petroline crude pipeline that runs from the Abqaiq oilfield on the Gulf coast in the east to the Red Sea port of Yanbu in the west, and the UAE operates the 1.5 million bpd ADCOP pipeline linking its onshore oilfields to the Fujairah oil terminal. The Saudi pipeline is vulnerable to Houthi attacks from Yemen, however; in addition, Kuwait and Qatar have no viable alternatives to the Strait.

Hostilities may also spur major LNG producers like Qatar to seek alternatives for the 85 million tpy of LNG that pass through the Strait. In 2023, New Delhi-based South Asia Gas Enterprise (SAGE) consortium began promoting a 2000 km line that would transport natural gas offshore from Oman to India. The US$5 billion line would gather 11 billion m3/y from Qatar, Iran, UAE and Saudi Arabia. The Indian government is keen on the project, estimating that it would save Indian consumers over US$800 million annually. Up until now the proposal has received little impetus from ME producers, but the route, which would bypass the Strait, greatly reduces geopolitical risk.

While green energy offers tremendous opportunities to MENA, it is also facing uncertainty. The EU, one of the prime potential customers, is struggling to make the transition to a hydrogen economy, primarily due to a lack of firm commitment from industrial and utility customers. The Trump administration is rolling back incentives and subsidies, undermining efforts in the US. The international move towards green ammonia as a marine transportation fuel remains as a bright spot in consumption, however.

In conclusion, MENA’s tremendous energy assets are in a state of flux as countries struggle to deal with regional hostilities, an evolving market and domestic unrest. Some jurisdictions, such as Qatar, Egypt, and Abu Dhabi, are encouraging NOCs and international investors to transition their reliance on traditional fossil fuel exports to green energy. Others, like Iran, must prioritise geopolitics, corruption and domestic unrest. For the coming decade, MENA will offer complicated challenges and enticing opportunities for the midstream sector.

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Kapil Garg, MarketsandMarkets, examines the role of ultrasonic testing in ensuring safety, compliance, and reliability within the oil and gas industry, with a particular emphasis on pipelines and infrastructure in the Middle East and Africa.

Oil and gas infrastructure includes, among other things, production facilities, liquefaction plants, refineries, pipelines, and storage tanks. As oil and gas companies increasingly prioritise safety and quality, regulatory bodies have implemented rigorous standards to ensure that products meet specific safety

criteria. These regulations mandate regular inspections and non-destructive testing (NDT) methods like ultrasonic testing (UT) to identify material flaws without compromising the integrity of the components. Organisations such as the American Society for Non-destructive Testing (ASNT) and the American Petroleum Institute (API) set high benchmarks for NDT practices, compelling manufacturers to adopt advanced testing techniques to comply with safety standards. This compliance mitigates risks associated with equipment failure and enhances product reliability, fostering consumer trust. The Pipeline and Hazardous Materials Safety Administration (PHMSA), through the Pipeline Safety Act and other regulations, requires regular inspections of pipelines to detect corrosion, cracking, and other structural weaknesses. Additionally, recent amendments, like the 2021 updates to the Pipeline Safety Act, emphasise the need for advanced, NDT techniques, such as UT, to ensure pipelines meet stringent safety standards, especially in high-risk areas near population centres or ecologically sensitive regions. Failure to comply could lead to significant penalties, as was evidenced by a case in 2022 in which a major US pipeline operator faced millions of dollars in fines following a spill attributed to insufficient inspection practices.

Central African Pipeline System (CAPS) 30 billion 6500

Nigeria-Morocco Gas Pipeline 25 billion 5600

Trans-Sahara Gas Pipeline (TSGP) 13 billion 4128 African Renaissance Pipeline Project 6 billion 2600

East African Crude Oil Pipeline (EACOP) 3 billion 1443

Ajaokuta-Kaduna-Kano Gas Pipeline

2.8 billion 614

Source: Secondary Research, and MnM Knowledge Store.

Furthermore, many countries, including the US, Germany, Japan, the UK, and Canada, are enforcing more stringent environmental and safety regulations as global industrialisation accelerates, necessitating ultrasonic testing technologies. The increasing complexity of manufacturing processes and materials and the demand for higher quality assurance have led industries to rely heavily on UT for routine inspections, maintenance, and quality control. As a result, companies are investing in UT equipment and services to meet these regulatory requirements while striving to improve operational efficiency and reduce downtime. This trend is expected to continue as regulatory frameworks evolve and expand across various sectors, solidifying ultrasonic testing’s critical role in ensuring compliance with stringent industry standards and enhancing overall market growth.

Ultrasonic testing provides a reliable means of detecting flaws and assessing material integrity without compromising the structural components. It is essential for maintaining operational safety in offshore settings where environmental conditions can be harsh and unpredictable. Regular ultrasonic inspections identify potential issues before they escalate into catastrophic failures. This proactive approach helps avert costly downtimes and aligns with stringent regulatory frameworks that mandate regular inspections to prevent leaks or accidents that could have severe environmental repercussions.

What is ultrasonic testing?

Ultrasonic inspection requires utilising sound waves that travel through various materials at a constant velocity specific to each material. When these sound waves encounter an interface between two different materials, a portion of the wave is transmitted while the remainder returns to the source. This technique is employed for flaw detection and material evaluation. A beam of ultrasonic sound is directed at the object being tested; if there are any discontinuities in the wave path, energy is reflected as echoes to a receiver.

Three ultrasonic inspection techniques are used to detect flaws in materials. These are pulse-echo, angle beam, and contact and immersion methods.

oil and gas industry.

Among these, the pulse-echo technique is the most widely used for detecting internal defects, assessing material thickness, corrosion inspection, and evaluating full penetration groove welds. Recent developments in inspection services have enhanced the effectiveness of ultrasonic testing in recent years. Companies have begun integrating artificial intelligence into their ultrasonic testing systems to automate data analysis and interpretation, making inspections fast and accurate.

Advancements in ultrasonic testing technologies, such as phased array ultrasonic testing (PAUT) and

Figure 1. Ultrasonic testing market trends in the

Table 1: Africa: key recent and upcoming pipeline projects Project name Investment (US$) Pipeline operation length (km)

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automated ultrasonic testing (AUT), enhance inspection capabilities by providing faster and more accurate assessments. These innovations enable operators to conduct comprehensive inspections in real time, which is beneficial in offshore environments where accessibility can be challenging. The combination of increasing exploration activities, stringent safety regulations, and technological advancements is creating a robust demand for ultrasonic testing services in the offshore oil and gas industry. As companies prioritise asset integrity management and preventive maintenance strategies, the ultrasonic testing market is expected to experience sustained growth.

Major concerns in Middle East and Africa

There have been major terrorist activities and cybercrimes in the Middle East and Africa in the last two decades. Military adversaries, organised oil smugglers, and armed rebels also create threatening situations. Political unrest, internal disputes, and governmental instabilities in countries in the Middle East and Africa regions have significantly hampered the overall production of oil and gas and have created potential threats to oil and gas plants and pipelines carrying these media. The majority of conflicts are due to economic issues and the failure of parties to agree on the terms of transit, expenses sharing, and taxes. Cross-border pipeline operators face tax risks, although the governments involved sign pipeline agreements. Also, the government laws proposed internationally for cross-border pipelines are becoming more complex.

Nigeria is world’s seventh largest exporter of oil and is expected to export 1.7 million bpd in 2025. However, in the past few years, oil and gas production has been hampered in Nigeria, due to the attack on oil and gas infrastructure by militants. Oil theft has also been a major issue faced by the oil and gas market in Nigeria, which has led the operating companies in the country to incur huge losses. Lack of infrastructure, uncertainties in regulations, and security concerns have led Nigeria to underutilise its refining capacities, thereby pushing the country to become a net importer of refined petroleum products. Nigeria’s oil and gas sector, facing aging infrastructure, also necessitates regular inspections. The country’s National Oil Spill Detection and Response Agency (NOSDRA) has encouraged non-destructive testing methods to mitigate environmental risks, promoting UT for pipeline integrity assessments.

Nigeria’s 614 km Ajaokuta-Kaduna-Kano (AKK) gas pipeline is the anchor of a north-bound transmission spine aimed at gas-to-power, industry, and city-gas growth. In July 2025, the operator completed the River Niger horizontal crossing – a technically and symbolically significant milestone on the central segment. Another positive news surfaced in mid-2025, authorities and trade outlets highlighted a June ‘100% crude-pipeline availability’ achievement. But the investors and insurers will look for sustained, independently verifiable throughput and lower

loss factors over multiple quarters before they re-price risk. The AKK milestone and reported availability are steps in that direction; the proof will be consistent flow and reduced disruptions.

Market outlook

The region consists of major oil and gas producing countries such as Saudi Arabia, the UAE, Iran, Qatar, and Nigeria which have some of the largest petroleum reserves in the world. Countries such as Saudi Arabia, UAE, Iran, and others export most of their production to neighbouring Asian countries such as China and India, which have high energy demand. Likewise, increasing oil and gas demand in other developing countries and the augmented demand for pipeline monitoring due to improved pipeline infrastructure offer excellent opportunities to this market.

According to a regional analysis of oil and gas construction projects, the Middle East and Africa region has the largest share of projects, by value, with projects worth US$1.23 trillion in the pipeline accounting for approximately 45% of all projects in the pipeline globally. The quest for enhancing safety protocols and ensuring the resilience of energy infrastructure has sparked a revolutionary transformation in the maintaining pipeline integrity. Experts, armed with advanced techniques and technologies, have spearheaded a new era in safeguarding pipelines, thereby significantly mitigating the risks associated with potential hazards.

Upcoming oil and gas developments to fuel the pipeline growth

The African region possesses approximately 140 billion bbls of proven oil reserves as of 2024. There are new exploration activities undertaken in many African countries such as Libya, Namibia, Angola, and Uganda in recent years. Uganda, a country with proven oil reserves for the past 20 years is expected to start oil production from Tilenga project by 2025. The heavy investment in developing the infrastructure will lead ways to pipeline monitoring market.

Middle East being the region with the highest petroleum reserves in the world is poised to maintain its dominating share in exports to Europe and Asian countries in future as well. Saudi Aramco has targeted to produce 0.65 billion m3/d of natural gas by 2028 and is expected to develop unconventional gas reserves in North Arabia, South Ghawar, and the Jafurah Basin, east of Ghawar.

The maintenance of pipeline integrity via monitoring also faces further hurdles in face of skilled workers. Another significant challenge lies in the extensive network of existing pipelines, posing difficulties in conducting comprehensive monitoring. Furthermore, factors such as aging infrastructure, remote locations, and harsh environmental conditions contribute to accessibility challenges. To surmount these barriers, it is imperative to foster collaboration among stakeholders – i.e. Governments, pipeline operators, and technology providers must unite to formulate efficient strategies.

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Lead, ROSEN Group, consider how to address rogue pipes, outliers, and unknowns as part of an Integrity Management Plan (IMP).

As transmission pipelines age, the challenge of identifying rogue pipes, outliers, and unknown segments has become a growing concern for operators. These discrepancies – whether undocumented, misidentified, or outside expected specifications – can compromise pipeline safety and reliability. Without proper verification of material properties, as mandated by 49 CFR §192.607, operators risk operating pipelines under unsafe conditions.

To address these risks, pipeline operators are increasingly turning to advanced inline inspection (ILI) technologies for detecting unknown and rogue pipes. This enables operators to accurately assess material properties across their pipeline systems. Services like ROSEN’s RoMat PGS Service can measure key attributes such as diameter, wall thickness, pipe grade, and pipe type – data that is essential for informed decisionmaking and effective risk mitigation. By comparing expected vs measured pipe properties, operators can identify discrepancies and take corrective actions, from adjusting operating parameters to planning targeted repairs or replacing segments altogether. These proactive measures help maintain safe operating conditions and reduce the likelihood of incidents.

This article explores the role of material property verification in modern pipeline integrity management. It outlines a methodology for achieving full verification using ILI and complementary sampling techniques, and highlights how tools like PGS support the identification of rogue pipes and unknown segments – ultimately enhancing the safety and reliability of pipeline operations.

The need for accurate material properties

According to the Pipeline and Hazardous Materials Safety Administration (PHMSA), approximately 61% of gas transmission lines and 39% of hazardous liquid lines in the US were installed in 1979 or earlier.1 Most of these pipelines were constructed between 1950 and 1969, making much of the nation’s transmission infrastructure more than 55 years old. This presents

a significant challenge for operators working to maintain safe and efficient systems through their Integrity Management Plans (IMPs).2

As pipelines continue to age, the need for a reliable, efficient, and tailored IMPs becomes increasingly significant. However, without verified knowledge of the pipeline’s material properties, developing an accurate and effective plan becomes difficult. This is especially true when rogue, outlier, or undocumented pipe segments are present, elements that can compromise the integrity of the system and reduce the effectiveness of risk mitigation strategies. Over time, as ownership changes hands and maintenance or replacement activities are carried out, these records can be lost, degraded, or rendered insufficient. Without accurate documentation, operators may be forced to operate at reduced pressures and throughput to maintain safety.

This challenge has been further amplified by the implementation of PHMSA’s ‘Mega Rule’ (49 CFR §192.607), first enacted in 2020 and updated in 2023.3 This is one of the stricter regulations PHMSA has implemented aimed at reducing the likelihood of future incidents after past catastrophes. These regulations include requirements for Maximum Allowable Operating Pressure (MAOP) reconfirmation, expanded compliance standards under CFR 192.9, and improved corrosion control measures. Current regulatory requirements state operators must achieve 50% MAOP reconfirmation (in terms of mileage) by 2028, and 100% by 2035.4

While there are several methods to meet these requirements, including hydrostatic pressure testing and pressure reduction, ILI offers a comprehensive and less disruptive solution. Hydrostatic testing requires the pipeline to be filled with water and taken offline for hours, resulting in costly downtime. A pressure reduction, while less disruptive, limits throughput and prevents full operational capacity. In contrast, ILI tools allow operators to continue normal operations while collecting detailed material property

information in a non-destructive manner. These tools can help to identify rogue and unknown pipes, verify material attributes across the entire line, and support MAOP reconfirmation, all without interrupting service. The data gathered through ILI also contributes to achieving traceable, verifiable, and complete (TVC) documentation, another aspect of the current regulatory requirements and a necessary component of a reliable IMP. By integrating ILI data into their integrity programmes, operators gain a deeper understanding of their pipeline systems.

Pipe Grade Sensor (PGS) background

As previously discussed, technologies like ROSEN’s PGS play a critical role in the material verification process, but how do they actually work? The PGS tool, shown in Figure 1, combines eddy

current principles with magnetic flux leakage (MFL) to create a magnetic field induced in the pipeline.5 This method allows the tool to detect subtle variations in material properties across the pipeline. Once collected, this data is analysed by engineers to delineate pipe segments into populations based on measurable differences in attributes such as yield strength, wall thickness, joint length, and pipe type. Then, the measured properties can be compared to the expected values to help identify rogue or outlier pipes that deviate from expected specifications. Discrepancies may not be evident through visual inspection or legacy records alone, making a tool like PGS a valuable asset in uncovering hidden risks.

The ability to detect and differentiate pipe populations in-line, without interrupting operations, adds significant value to integrity management programmes. It enables operators to validate assumptions about their pipeline systems, reconcile discrepancies in documentation, and build a more accurate understanding of asset conditions. This, in turn, supports MAOP reconfirmation, enhances TVC documentation, and strengthens the overall IMP.

Material property verification process

Verifying miles of pipeline may seem like a daunting task, especially when dealing with ageing infrastructure and incomplete records. However, recent advancements in ILI technology and validation standards have made comprehensive material verification both achievable and cost-effective. When paired with validation in accordance with API 1163, ILI tools enable operators to assess entire pipeline segments with significantly fewer excavations than in years past. This reduces disruption while maintaining confidence in the data.

The material property verification (MPV) process involves analysing the data from the PGS tool to group pipe segments into populations of pipes with similar material properties. This information is then aligned to the information that is stored in the operator’s GIS database to find rogue and unknown pipes, as well as identify discrepancies by comparing what properties the operator expected to what the tool measured. Furthermore, the TVC status can be determined for the properties in each population, which will aid in determining the location and number of field verifications required.

When field verifications confirm the properties measured by the tool, it validates the accuracy of the ILI system and strengthens confidence in the broader dataset. This methodology underpins an API 1163 Level 2 validation, which requires both an ILI run and subsequent field verification to confirm tool performance.6 Performing tests on any populations that have discrepancies or non-TVC material properties will allow the operator to confidently assign the appropriate material properties to every segment of pipe, enabling proactive management and enhanced safety across their pipeline networks. Finally, once all discrepancies have been rectified, the operator can

Figure 2. Measured yield strength vs log distance for population A1 and A2.

Figure 3. YS vs log distance graph showing distinct differences in strength of the different seam types.

Figure 1. ROSEN tool that combines eddy current principles and magnetic flux leakage (MFL).

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achieve TVC status and meet the regulatory requirements for material properties.

Case studies

The following case studies illustrate how ROSEN’s RoMat PGS service can be used to identify and trace rogue pipe segments within a transmission system. In this first example, the pipeline in question is an NPS 16 in. line with segments constructed in 1974, 1983, and 1987. The section of line constructed in 1987 was documented as 0.250 in. wall thickness and a grade of X60, operating at 963 psi. After conducting the ILI run using PGS, the majority was confirmed to have a yield strength greater than 60 ksi. However, a single joint of pipe with lower yield strength measured at 55 ksi was identified, shown in Figure 2. This pipe segment was below the SMYS, and when excavated, did not have similar characteristics to population A1. It was a clear outlier that had found its way into the system.

This type of undocumented discrepancy is a prime example of a rogue pipe, one that deviates from expected specifications and lacks traceable documentation. Identifying such segments is critical for maintaining pipeline integrity and ensuring safe operations. With the data provided by PGS, the operator is able to isolate the outlier and follow the verification process to close the gap.

This second example shows another advantage of using ILI technology, as the operator had insufficient records pertaining to the seam type of their line segment. There were two known seam types, Low Frequency Electric Resistance Weld (LF-ERW) and Double Submerged Arc Weld (DSAW), but several verifications resulted in different seam types than expected. It’s imperative to understand the seam types present in vintage pipelines, as certain seam types, like LF-ERW, have unique risks associated with them that must be managed accordingly. After utilising the PGS tool, the different seam types were easily distinguished due to the clear difference in yield strength and other attributes, as shown in Figure 3.

The LF-ERW pipes were populations A2 and B1, with lower strength. Population A4 is the DSAW pipe that the operator had documented. Strength, in this case, shows the distinct difference in seam type for the populations, which then allowed the operator to manage the threat of LF-ERW pipes appropriately. Populations A2 and B1 are different because of wall thickness, but even the strength values are different enough to identify that they are unique populations. Furthermore, the tool was also able to identify a separate population of flash-welded pipe by noticing the characteristic 40 ft joint lengths of the population. The operator did not have any record of this seam type, which is important because flash-welded pipe has its own unique risks separate from LF-ERW, which must be managed. Measuring strength with ILI is critical to determining populations because pipes made to the same WT will not always be different enough to identify, and pipes with similar joint lengths could be separate populations. Therefore, WT and joint lengths alone are not reliable enough to identify populations. However, different heats of steel will give a unique response for the ILI tool to identify. As a result, using additional ILI datasets like wall thickness and differing joint lengths provides further

confidence that populations are unique based on strength measurements.

Both of these cases highlight the value of advanced ILI tools in uncovering hidden risks and supporting compliance with regulatory standards. It also demonstrates how data-driven approaches can enhance IMP execution by providing actionable insights that may not be accessible through traditional recordkeeping or visual inspection alone.

Conclusion

Material property verification is a foundational element of any effective Integrity Management Plan (IMP), directly influencing whether a pipeline can operate safely and efficiently at its intended capacity. With the implementation of PHMSA’s Mega Rule in 2020 and subsequent updates in 2023, accurate material verification has become more critical than ever. The new regulatory requirements’ emphasis on MAOP reconfirmation, with key deadlines approaching in 2028 and 2035, underscores the urgency for operators to fully understand the physical characteristics of their pipeline assets. As the average age of transmission pipelines continues to rise, operators face increasing challenges in verifying material properties. Ownership transfers, reliance on legacy physical records, and inconsistent documentation during repairs or replacements can introduce segments of unknown, rogue, or outlier pipes. These undocumented discrepancies pose risks to safe operations and complicate regulatory compliance. Advanced ILI technologies, such as ROSEN’s RoMat PGS Service, offer a powerful solution to these challenges. By collecting detailed material data without interrupting operations, PGS helps operators identify undocumented segments, verify pipe properties, and detect rogue joints that may otherwise go unnoticed. When paired with API 1163 Level 2 system validation, operators can close the TVC loop, achieving full material verification with significantly fewer excavations.

As the industry continues to evolve toward data-driven integrity management, the integration of ILI technologies and validation standards will play a central role in maintaining safe, efficient, and compliant pipeline operations. By embracing these tools and methodologies, operators are better equipped to meet regulatory demands, mitigate risk, and ensure the longterm integrity of their pipeline networks.

References

1. Pipeline and Hazardous Materials Safety Administration. (2025, August). By-Decade Inventory. Retrieved from US Department of Transportation: https://www.phmsa. dot.gov/data-and-statistics/pipeline-replacement/decade-inventory

2. Rosenheld, J. F. (2012, November 8). The Role of Pipeline Age in Pipeline Safety. Retrieved from The INGAA Foundation, Inc.: https://ingaa.org/wp-content/ uploads/2012/11/19307.pdf

3. Pipeline and Hazardous Materials Safety Administration. (2022, October). Title 49 CFR Part 192: Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments. Retrieved from Department of Transportation: https://www.federalregister.gov/ documents/2022/08/24/2022-17031/pipeline-safety-safety-of-gas-transmissionpipelines-repair-criteria-integrity-management

4. Title 49 CFR Part 192 Subpart J. (2025, August). Retrieved from Code of Federal Regulations: https://www.ecfr.gov/current/title-49/subtitle-B/chapter-I/ subchapter-D/part-192/subpart-J

5. ROSEN. (2023). RoMat PGS Service Sales Flyer. ROSEN.

6. American Petroleum Institute. (2013, April). API Standard 1163: In-Line Inspection Systems Qualification. Retrieved from API Energy: https://www.api.org/~/media/ files/publications/whats%20new/1163%20e2%20pa.pdf

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Microbial Control and H2S Suppression

Microbiologically influenced corrosion (MIC) poses a significant threat to the integrity of oil and gas pipelines, primarily driven by biofilm formation and hydrogen sulphide (H2S) generation. These microbial processes accelerate corrosion, promote fouling, and disrupt flow assurance, resulting in increased maintenance costs and operational downtime. Controlling MIC typically involves a combination of mechanical cleaning and targeted chemical treatments. MIC is primarily driven by sulphide- and iron-reducing bacteria, resulting in pitting, iron sulphide deposition, and the generation of hazardous hydrogen sulphide (H2S). The formation of biofilm including extracellular polysaccharides (EPS) creates a protective matrix around microbial communities, shielding them from conventional treatments and thereby accelerating corrosion damage while increasing safety and operational risks.

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Biocides are a critical component of MIC mitigation strategies; however, their effectiveness depends on their ability to penetrate the biofilm matrix and reach the microbial cells. Mature biofilms consist of complex mixtures of waxes, sediments, minerals, and extracellular polymeric substances that impede biocide access. Consequently, combining mechanical cleaning with biocide application is strongly recommended to ensure optimal microbial control.

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Kaidy Kho, Vice President - Business Development (Sales), Atmos International, UK, emphasises the importance of a single-ended leak detection for tanker loading and unloading pipelines, to ensure a resilient monitoring strategy for challenging offshore environments.

Offshore tanker loading and unloading pipelines are a vital link in the global energy supply chain. They operate in some of the harshest and least forgiving environments, often exposed to ocean swells, anchor strikes, corrosion and limited access for maintenance. When these pipelines are compromised by leaks, the consequences can be severe: environmental damage, reputational loss, costly cleanup operations, and regulatory penalties. Leak detection is therefore not simply a technical challenge but a business-critical requirement.

Conventional dual-ended leak detection systems, which rely on synchronised instrumentation at both ends of a pipeline, can be impractical in these contexts. Offshore

monobuoys and single-point moorings rarely provide the necessary infrastructure, power or communications. This is where single-ended leak detection offers a resilient and practical alternative. Building on both simulated and fieldproven performance, single-ended leak detection enables operators to maintain high standards of safety and compliance without the need for costly offshore instrumentation upgrades.

The case for single-ended leak detection

Tanker loading and unloading operations are inherently complex. They involve flexible subsea lines, short transfer distances and transient flow conditions as pumping starts and stops. Conventional monitoring approaches, which compare

measurements at both pipeline ends, are hindered by the absence of offshore instrumentation. This creates blind spots in leak detection, leaving operators exposed to risks.

Single-ended leak detection systems address this challenge by relying solely on measurements at the accessible end, usually located onshore or on a nearby platform. Through advanced signal processing, pressure and flow data can be analysed with sufficient resolution to identify anomalies that indicate leaks. By eliminating reliance on offshore instrumentation, single-ended leak detection provides a pathway to resilience and regulatory compliance in challenging marine environments.

Technical framework

The technical approach to single-ended leak detection builds on well-established pressure and flow monitoring principles. At its core, the system leverages high-frequency data acquisition at the onshore terminal, applying statistical and transient analysis to distinguish leaks from normal operational events.

Key elements of the framework include:

) Data acquisition: capturing flow and pressure signals with sufficient frequency to detect small deviations.

) Signal conditioning: filtering noise to account for turbulence, pump vibrations, and valve operations.

) Event detection: identifying specific signatures that indicate the onset of a leak.

) False alarm minimisation: applying thresholds and adaptive algorithms to avoid unnecessary operational interruptions.

This methodology ensures that even under highly variable conditions, single-ended leak detection maintains sensitivity while delivering reliable results.

Case study: real-world performance

One operator in Latin America implemented a leak detection solution for a short offshore to onshore diesel transfer pipeline which presented a number of technical and logistical challenges. The 1 km pipeline, partly subsea and partly onshore, was used for unloading fuel from ships to storage tanks.

The operator originally considered ship-side instrumentation to support monitoring, but this proved impractical due to vessel variability, safety restrictions, and space limitations. Instead, a single-ended system was deployed using instrumentation installed onshore, eliminating the need for offshore equipment and simplifying the project.

Despite the short length of the line and the corrosive marine environment, the solution delivered reliable results by applying negative pressure wave analysis and high-resolution data processing. This approach allowed for accurate leak detection and compliance with international best practice (such as API 1130) without requiring significant modifications to the existing infrastructure.

Key findings included:

) High sensitivity: detection of very small leaks, with a location accuracy of approximately 0.25% of pipeline length.

) Low false alarm rate: ensuring operational confidence and minimising unnecessary shutdowns.

Figure 1. Atmos Wave’s single-ended solution on the diesel pipeline transporting fuel from ships offshore to tanks onshore and Atmos Wave Flow on the flushing pipeline.

) Rapid implementation: the system was retrofitted without complex or costly modifications.

Operators reported increased assurance in their unloading operations, noting that the system was ready to collect data immediately and optimised their compliance processes.

Operational benefits

The adoption of single-ended leak detection brings several operational advantages. These can be grouped into safety, compliance, efficiency and cost:

) Safety: single-ended leak detection reduces the risk of undetected leaks, protecting the marine environment and ensuring public trust.

) Compliance: by meeting and often exceeding regulatory detection thresholds, operators can demonstrate due diligence.

) Efficiency: simplified infrastructure requirements reduce downtime and accelerate deployment.

) Cost-effectiveness: single-ended leak detection avoids the expense of installing and maintaining offshore instrumentation providing long-term savings.

Taken together, these benefits highlight single-ended leak detection as a pragmatic solution that balances technical performance with commercial realities.

Wider implications for the industry

Single-ended leak detection aligns with the industry’s push toward operational excellence and sustainability. By lowering the cost barrier to effective leak detection, it enables operators to extend best practices to assets that might otherwise remain vulnerable. The scalability of the approach means lessons learned in one deployment can be applied across multiple facilities, multiplying the impact.

Shaping the future of offshore pipeline safety

As offshore energy logistics evolve, the demand for resilient, practical and cost-effective monitoring strategies will only increase. Single-ended leak detection has proven itself as a credible alternative to conventional systems in challenging offshore environments. By combining advanced signal processing with pragmatic infrastructure use, it delivers safety, compliance and efficiency without the need for extensive offshore modifications.

For operators facing the dual challenge of maintaining pipeline integrity and controlling costs, single-ended leak detection offers a compelling solution. Its successful deployment in real-world case studies provides confidence that this approach can bridge the gap between technical aspiration and operational reality. As the industry looks to the future, single-ended leak detection is well placed to play a central role in advancing marine logistics safety.

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Pipeline operators face a persistent challenge when planning integrity budgets: how to allocate limited capital across competing priorities while safeguarding safety, compliance, and operational efficiency. Integrity management programmes are critical to preventing failures, yet their budgets often struggle to gain approval against growth projects, acquisitions, or operational upgrades. Traditional requests often rely heavily on technical justification, such as risk matrices, inspection data, and regulatory obligations, but these rarely resonate.

The capital allocation dilemma

Every capital cycle forces executives to weigh investment options:

) Should the company expand its system to capture new throughput?

Pushpendra Tomar, Dynamic Risk, addresses turning risk into value with financial quantification for smarter integrity budgets.

) Should it acquire an asset to increase market share?

) Or should it prioritise long-term reliability through integrity projects?

Growth and acquisition proposals are supported by clear financial metrics, projected revenues, IRRs, and net cash flows. By contrast, integrity proposals are often presented as technical necessities, framed around safety risk or regulatory compliance, without a clear estimate of financial return.

The result? Integrity projects risk being underfunded or deferred, creating exposure to safety incidents, environmental damage, regulatory fines, and costly unplanned outages.

A more effective approach translates integrity risk into financial outcomes, showing not only why investment is essential but also when it is a sound financial investment.

Defining risk in economic terms

At its core, risk is the combination of two elements:

) Likelihood of Failure (LoF): the probability that a threat –such as corrosion, cracking, or geohazards results in a failure event within a given timeframe.

) Consequence of Failure (CoF): the impact of that event in terms of safety, environment, reputation, and financial loss.

Quantitative risk assessment (QRA) and probabilistic risk assessment (PRA) methodologies provide robust ways to calculate LoF and CoF. But while technically rigorous, their outputs (risk matrices, probability distributions) are not easily translated into the language of finance. This is where the capital optimisation methodology comes into play.

The capital optimisation methodology

The capital optimisation methodology converts risk results into standard financial metrics, enabling integrity budgets

to be compared on equal footing with other corporate investments. It is built on four key elements:

) Investment: the cost of prevention, such as inspection, repair, or mitigation.

) Expected cash inflows/avoided outflows: revenue earned or the avoided costs of a failure, such as lost product, emergency response, fines, and reputational damage.

) Timeframe: the expected degradation curve, identifying when a failure is likely to occur.

) Discount rate: reflects the company’s cost of capital or the expected rate of return.

The net present value (NPV) of any integrity investment is calculated from these key elements. Where:

) Positive NPV: investment in prevention is financially viable, as the avoided future costs exceed the current investment.

) Negative NPV: investment in prevention is not yet economically justified, though future reassessment may change the outcome.

This framework converts integrity spending requests into familiar financial metrics, supporting objective, transparent, and data-driven budgeting.

From degradation curves to decision points

A key step in the methodology is the use of degradation curves, which model the probability of failure for each pipeline segment over time.

By estimating the mean failure year, or through a similar measure, such as the point at which failure is most likely, operators can quantify when future costs will occur. These projected failure costs are then adjusted for inflation and discounted back to their present value, allowing for a direct comparison against today’s prevention costs.

For example, if preventing a failure today costs US$1 million, while the discounted value of the failure cost in 28 years is US$1.25 million, the NPV is positive. Therefore, the investment is economically justified. However, if a higher discount rate is required, it reflects greater tolerance for risk or a higher opportunity cost of capital. In that case, the discounted value of the failure cost may fall below US$1 million, making the investment in prevention economically nonviable.

This nuanced approach allows operators not only to justify budget requests but also to optimise the timing of investments, as well as identify the most effective mitigation strategy. Integrity teams can demonstrate when prevention becomes financially compelling, supporting long-term maintenance planning.

Practical applications

The benefits of capital optimisation extend across multiple integrity decisions, including but not limited to:

) Inspection scheduling: optimising pigging intervals and tool selection to balance cost with risk reduction.

) Repair strategies: weighing extensive digs against operational changes such as reduced pressure.

Figure 1. Translating risk into financial metrics the four elements of the financial investment methodology.

Figure 2. Degradation curves help identify the mean failure year and optimal timing for investment.

Figure 3. Applying NPV to integrity investments a data driven basis for budget decisions.

) Replacement vs repair: determining when full replacement is economically preferable to ongoing mitigation.

) Long-term projects: evaluating investments in new ILI technologies or participation in joint industry research.

Case study: repair vs replace

An operator needed to raise throughput to meet the expected increase in demand. The decision: repair an ageing 50 year old pipeline to restore maximum operating pressure (MOP) or construct a new line at substantial cost.

The existing pipeline was operating at reduced operating pressure due to corrosion and linear indications. Therefore, to maintain capacity, the operator was relying on costly drag reduction agents (DRA).

Using the capital optimisation methodology, annual cash flows were modelled under three scenarios: operating at MOP, at 80% MOP, and at 40% MOP. For each scenario, degradation curves, failure probabilities, and repair costs were calculated on a 12 m segment basis. The assessment also ensured that a required safety factor is maintained across the pipeline.

The results showed that repairing the existing line was more economical than building new infrastructure in all three scenarios. By quantifying the avoided costs of failure and comparing them to prevention costs, the operator gained clarity and confidence in its integrity investment decisions.

Bridging the gap between engineers and executives

The power of the capital optimisation approach lies in its ability to bridge the communication gap. Engineers think in terms of probability, defect growth rates, and safety margins. Executives think in terms of cash flows, IRR, and shareholder value.

By converting technical risk assessments into financial metrics, integrity teams can speak the language of capital decision-makers. This not only strengthens the case for integrity budgets but also ensures that investments are allocated to the areas of greatest economic and safety impact.

Conclusion

Pipeline integrity is not only about compliance and safety; it is about protecting the financial health and long-term viability of operations. Yet integrity teams often struggle to secure adequate funding because their

proposals lack the financial framing used in other corporate investments.

By applying the capital optimisation methodology, operators can reframe integrity projects as economically sound investments. This enables objective comparisons across competing projects, optimises short- and long-term spending, and ensures that limited budgets deliver maximum value.

As the industry faces growing challenges, aging infrastructure, increasing regulatory scrutiny, and rising sustainability expectations, the ability to make financially robust integrity decisions will be a defining factor in achieving safe, profitable, and responsible pipeline operation.

High voltage Holiday Detector

Detects holidays, pinholes, and other discontinuities using continuous DC

n Lightweight, one-piece ergonomic design provides comfortable all-day use

n One wand covers the entire voltage range from 0.5 to 30 kV

n Up to 16 hours of battery life—powerful Li-ion batteries fit neatly within the compact wand handle eliminating the need for a separate battery box

n Built-in Certified Voltmeter and Voltage Calculator feature

n Industry standard connectors and adaptors provide compatibility with nearly all existing electrodes

Since 1948, Tinker & Rasor has been a trusted name in holiday detection, relied upon by pipeline professionals worldwide. For over 76 years, our holiday detectors have set the benchmark for performance and reliability, ensuring the integrity of protective coatings by detecting coating flaws with precision. With a legacy of innovation and toughness, Tinker & Rasor continues to lead the industry, delivering cutting-edge solutions to safeguard pipeline coatings and maintain quality standards across the globe.

Recent widespread outages across Europe – which shut down energy supply chains, disrupted transport and communications, and halted operations – signal a harsh new reality. Infrastructure once built for stability is now being stress-tested by unpredictability. This article, puts today’s climate challenges for the oil and gas industry into perspective, to explore how technology is improving industry resilience, and mitigating the consequences of climate change.

Throughout 2024 and the start of 2025, several European countries have been affected by severe floods caused by prolonged heavy rains. Damage has been widespread, with overflowing river basins and landslides causing catastrophic damage. Globally, weather events in locations such as Canada, Spain, and wider Europe, that we once called one-in-100 or one-in-1000-year events, are now happening every year, sometimes multiple times a year. In North America, hurricanes and wildfires have dominated headlines –resulting in outages to key resources across large areas.

With an outdated, vastly distributed network, the damaging effect of changing weather conditions can be huge when it comes to downtime. From a financial perspective, the implications are huge for the bottom line. Non-productive time (NPT), whether due to equipment failure, weather

Carol Johnston, VP Energy, Utilities, and Resources at IFS, details how oil and gas can resurrect ageing pipeline infrastructure and build climate resilience.

conditions, or logistical issues, is costly. In the oil and gas sector, the average cost of downtime doubled in 2022 to £37 000+/h.

Oil and gas organisations need to be more strategic; this means assessing critical assets before and after a storm, investing

where it matters, and planning for better resilience and restoration.

It is no longer about how to play the defence game against climate change, it is how to build a reliable future.

Infrastructure will only keep getting older – a recipe for disaster

Peak-performing equipment works in tandem with productivity. When equipment runs efficiently, projects get done on or ahead of schedule. A decline in productivity is often a precursor to asset failure. Equipment efficiency requires oil and gas companies to stay on top of equipment maintenance and servicing to ensure assets are in ‘optimal, like-new condition’.

With some UK oil and gas pipelines being 50+ years old, much of today’s infrastructure is near the end of typical lifecycles. Despite being outdated, these assets are still operating. They are under immense pressure and struggling to match supply with demand. Extreme weather conditions are only causing aging assets to fail more frequently. These assets are not designed to operate in extreme conditions and frequent outages are having huge impacts on reliability. Beyond the UK, Spain, and Portugal recently suffered one of the largest blackouts in history – a blackout authorities say will require ‘trillions of dollars’ of infrastructure investment into an ageing power grid and lack of energy storage capacity to avoid again.

Cracks in the pipeline: the impacts of extreme weather

Prevention to the point of zero risk is financially impossible. But the cost of doing nothing is now higher than the cost of mitigation. The cost is now in human life, material damage, service supply, reputation, and the ability to secure insurance.

Extreme weather events, such as hurricanes, floods, heavy snowfall, or high winds, can trigger pipeline failures and lead to widespread disruptions. Extreme heat temperatures can cause soil corrosion and pipelines to crack, while freezing temperatures can result in expanded pipelines, that can burst. Oil and gas companies need to break this down by regions, assess common weather events, and consider what mitigation risks can be put in place to reduce risk.

Time to exploit the predictive power of meteorological data

Traditionally, the utilities sector has implemented solutions like undergrounding lines in hurricane-prone areas, but with storms now veering into previously unaffected regions and lingering longer over land, even these mitigations are being outpaced. Hurricanes are changing their paths. They are bringing floods to areas that never used to flood. Previous mitigation strategies need to step up to a new plate, one filled with meteorological data and trends. Both utilities, and the oil and gas industry need to work much more closely with the meteorologists to uncover what are the forecasts, and what these new trends are and will bring.

Figure 3. Extreme heat temperatures can cause soil corrosion and pipelines to crack, while freezing temperatures can result in expanded pipelines, that can burst.

Figure 2. With some UK oil and gas pipelines dating back to 50+ years old, much of today’s infrastructure is near the end of typical lifecycles.

Figure 1. Throughout 2024 and the start of 2025, several European countries have been affected by severe floods caused by prolonged heavy rains.

Tailor-made

Fittings

Outstanding

Highest

From

Global

Now it is down to businesses with infrastructure and asset mitigation strategies

While energy generation facilities – especially centralised ones such as nuclear plants – are generally well-protected, the transmission and distribution (T&D) networks remain highly vulnerable. As energy generation becomes more distributed with the likes of solar and wind, the threat landscape is becoming even more complex.

While a transition to renewables is necessary, energy companies must consider grid reliability and cost. Saving the planet is often tertiary because overall, people do support green initiatives, but their primary motivations are about saving money and avoiding inconvenience.

As the grid becomes the weakest link, renewables and carbon capture step up

For the oil and gas sector, reducing emissions has been placed at the forefront, and doing so through renewables is an established strategic goal. While distributed generation doesn’t prevent natural disasters, with careful planning and design, it does offer greater flexibility and resiliency.

Wildfires in 2024 alone emitted more carbon than was reduced by all industries’ decarbonisation efforts. We need carbon capture initiatives, not just footprint reduction, and this carbon capture must complement emission reduction to address climate change in a timely and holistic manner.

Industrial AI: predicting with certainty Technology, particularly AI, is now playing a pivotal role in helping adapt. From asset investment planning to predictive maintenance, Industrial AI solutions are allowing operators to better allocate resources, effectively oversee workforces, and manage risks proactively.

Oil and gas companies need to ensure that assets are constantly monitored to manage and predict risk. These assets must be maintained at a high level to comply with industry regulations.

Advanced Maintenance Planning and Scheduling (MPS) systems fully digitalise all aspects of the planning and maintenance environment. This provides oil and gas companies real-time data for timely oversight and pre-emptive identification and investigation of system-wide anomalies. As a result, companies have the confidence to take action to convert failures into fixes. To better manage assets and operations, many businesses have turned to risk-based predictive asset maintenance and monitoring technologies. For example, preventive maintenance helps businesses ensure equipment assets run according to manufacturer guidelines. Poorly performing parts are updated, and remaining assets are maintained to perform at a steady level of productivity throughout the year. The use of predictive maintenance can help identify potential issues before they occur, allowing for timely interventions and reducing the risk of unexpected downtime.

In today’s climate, companies can’t rely on ‘business as usual’ and hope the problem will resolve itself. To better manage their assets and operations, new developments in risk-based AI-predictive asset maintenance are increasing the reliability of assets and the supply of renewable energy.

Emergency management – is the sky blue, grey, or are the black clouds gathering?

The use of ‘black sky’ planning helps energy and oil and gas companies prepare for large-scale outages and it’s now starting to become standard practice. Unlike ‘blue sky’ daily operations or ‘grey sky’ seasonal spikes, black sky scenarios involve total grid restarts (cold starts) after major disasters.

EDF Renewables UK and Ireland, the leading renewable energy company specialising in wind, solar, and battery technology, has chosen IFS Cloud to deliver Enterprise Asset Management (EAM) to support its ambitious growth plans to increase total green energy output produced by their onshore and offshore operations.

Using a single data model supported by key value drivers such as Asset Performance Management, IoT, mobile work execution, live dashboards, and KPIs, EDF Renewables will benefit from end-to-end visibility across multiple organisational structures and business units.

Pre- and post-event restoration

The use of Industrial AI can aid strategic investment planning with tools such as Copperleaf AIP, combined with IFS Cloud’s Project Portfolio Management, Supply Chain Management, Asset Management, Scheduling, and Mobility solutions. Together, these offer full asset lifecycle management. Underpinned by Industrial AI, it enables asset-intensive customers to strategically monitor optimal asset performance.

This identifies critical assets and their risks, and supports predictive maintenance instead of routine scheduling. Copperleaf customers have reduced planning times by up to 50% with improved asset sustainment and 30% reduced risk. Copperleaf helps incorporate ESG metrics into everyday decision making, and supports the modelling of embodied and operational greenhouse gas (GHG) emissions and integrates this into an organisation’s asset investment, planning, and management system. These emissions can be modelled at an asset level to consider whole lifecycle GHG emissions and create a baseline emissions profile for the organisation.

In addition, the coordination of complex restoration of activities after major disruptive events, emphasises the need for different scheduling strategies. Here’s where powerful Planning and Scheduling Optimisation (PSO) solutions ensure restoration can be managed alongside normal daily operations.

The AI-enhanced toolkit is ready

Aging infrastructure and changing weather-related threats makes it clear: business-as-usual is no longer an option. Mitigation strategies must go beyond outdated traditional practices, and instead leverage technology where AI has a key role to play in predictive analytics, risk analysis, and fast-acting PSO strategies.

The future of oil and gas is bright for those businesses willing to innovate and adapt. With the right technology and maintenance planning solutions, oil and gas companies can adapt to challenging weather conditions and climate change.

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Mike Eason, Chief Technology Officer at John Crane, argues that in a changing energy landscape, the oil and gas industry needs engineering excellence more than ever.

Today, oil and gas companies operate in an evolving energy landscape. The industry faces mounting pressures to operate more sustainably, to meet decarbonisation targets and control fugitive emissions. At the same time, there is a global drive towards the adoption of alternative and renewable energy sources. The transition is well underway – in 2024, renewables

accounted for 38% of growth in total energy supply globally, while growth in oil demand slowed to 0.8%.1

Oil and gas companies must adapt to this new landscape, managing risk while seizing new opportunities in the energy transition. Crucially, getting the fundamentals right has never been more important. Organisations must meet increasingly stringent standards, ensuring the safety, reliability, and efficiency of their operations. This goes beyond the question of compliance – excelling in these areas is vital to operating a profitable business.

Nowhere is this more apparent than in the case of downtime. Unplanned downtime costs the industry an estimated US$50 billion annually, 2 with equipment failure accounting for 42% of this lost time. In the oil and gas sector, this can result in losses of up to US$42 million per facility each year. 3 The cost of unreliable or faulty equipment cannot be understated.

Ultimately, this comes down to engineering. Quality solutions designed to operate under the high pressures and temperatures of the oil and gas industry can be relied

upon to remain operational in challenging conditions and to enhance the lifespan of critical assets. They help ensure better environmental outcomes, too (e.g. by reducing waste and fugitive emissions).

Equally, innovation in digital technologies has a role to play in enhancing the performance and reliability of hardware solutions. While they aren’t a turnkey solution for every challenge, digital platforms and sensors can help firms protect their critical assets and improve the overall health of their operations. And in a period of rapid change, oil and gas companies will need to use all the tools at their disposal to thrive.

Precision matters in critical equipment

It goes without saying that the reliability of equipment depends on the quality of its design and manufacturing. Knowing the impact of unplanned downtime, industrial machinery – particularly in mission-critical applications – is engineered for enhanced reliability and productivity.

This level of precision is essential in demanding environments. Nowhere is this more true than on offshore platforms and in gas transportation pipelines. On offshore platforms, where space is limited and operational downtime can be costly, advanced sealing technologies help improve uptime and reduce maintenance challenges. In gas transportation pipelines, reliable seals are critical for preventing leaks, protecting both the environment and the integrity of the supply chain.

To reach the high standards required in these environments, micro-machined patterns and engineered features are used on dry gas seals. Selecting the right separation seal technology can deliver benefits in terms of uptime, asset protection, and efficiency. Take John Crane’s Type 93AX: its compact, robust design helps maintain seal integrity and reliability in high-demand environments. In testing, this seal was found to reduce nitrogen consumption by up to 80%. compared with conventional separation seal designs. This is a win-win situation: it lowers operational expenditure while also supporting broader sustainability goals.

Enhancing reliability through digital innovation

The World Economic Forum projects that digital technologies could cut emissions by 20% across energy, materials, and mobility by 2050. 4 With such impressive projections, it’s easy to assume that technologies like AI and advanced analytics operate in a vacuum. But their impact is contingent on how they interact with the real world, whether that’s a car or an offshore platform. Technology can help optimise and safeguard assets – but the performance of those assets still depends on engineering excellence.

This relationship between digital and physical infrastructure is at the heart of smart diagnostics and condition monitoring solutions. These technologies use sensors to monitor the physical environment, paired with advanced platforms capable of providing near real-time insights. This gives organisations greater visibility of their operations and has a wide range of applications, from

Figure 1. Organisations must meet increasingly stringent standards, ensuring the safety, reliability, and efficiency of their operations.

Figure 2. On offshore platforms, where space is limited and operational downtime can be costly, advanced sealing technologies help improve uptime and reduce maintenance challenges.

Connecting What’s Needed with What’s Next™

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improving cost efficiency and minimising waste to enabling maintenance strategies that reduce unplanned downtime and increases the lifespan of critical assets.

What does this look like in the oil and gas industry? Given its tendency to operate in hazardous zones and deploy difficult-to-reach assets, the benefits of remote monitoring and management cannot be overstated. Both wired and remote solutions can deliver value in these environments, providing visibility of critical equipment without the need for constant on-site intervention. Smart diagnostics and condition monitoring solutions can help identify issues across their operations and safeguard critical assets. For example, John Crane Sense® Turbo – a wired sensor solution – uses sensors embedded into dry gas seals to perform continuous data collection. This reduces the need for manual seal inspections, saving companies time, money, and employee bandwidth. And data from the sensors can be used by analytics systems and industry experts to recommend actions to ensure optimal operating conditions.

The results in the field are impressive. A world-leading LNG producer lacked the insights they needed to understand dry gas seal performance; they were relying on seal vent detection to monitor health. Because of this lack of visibility, they shut down operations every time they saw highvibration measurements on the compressor to avoid damage. But once they installed John Crane Sense Turbo, it became apparent that most of the measurements were unrelated to the seal and were leading to unnecessary shutdowns – each of which cost a week of lost production. With accurate near real-time insights on seal health, the LNG producer was able to reduce this unplanned downtime by eight days, saving an estimated US$4 million in lost production.

Success in the new energy landscape depends on a holistic approach to operational excellence. Oil and gas companies must tap into the latest digital innovation, while

equally getting the fundamentals of engineering and maintenance right. Used in conjunction with comprehensive support and reliability programmes, diagnostics, and monitoring solutions can improve equipment lifespan and reduce unplanned downtime and the total cost of ownership.

The bigger picture

Changing market conditions are undeniable. As the IEA puts it, “oil and gas becomes a less profitable and a riskier business as net zero transitions accelerate.”

In response, there are changes the oil and gas industry can make today to reduce fugitive emissions and increase efficiency. But these changes should take place in parallel with a shift towards new, more sustainable energy markets. Looking forward, LNG is widely seen as a bridge fuel that emits less CO 2 than other hydrocarbons. And the innovation in gas transportation that it heralds can be adapted and applied to hydrogen – a more sustainable fuel, if produced from renewable power sources. There are still engineering and commercial questions to be answered, but the direction of travel is clear: the industry must evolve to meet the demands of a low-carbon future.

So how do we foster a new wave of innovation and engineering excellence that can meet these challenges? Collaboration between industry and academia is one way to accelerate innovation and bridge knowledge gaps across the sector. An example of this is John Crane’s partnership with the University of Sheffield, which includes three PhD projects focused on gas compression technologies. There is exciting work underway on hydrogen-compatible materials, high-speed seal applications, and advanced simulation techniques. These partnerships both support global sustainability goals and furnish the next generation of engineers with the skills and experience needed for the transition ahead.

Strong engineering fundamentals are the key to both the oil and gas industry’s present and its future. Precise, efficient designs and rigorous maintenance have underpinned its success for decades. Now, new innovations can help to optimise the way equipment is operated, as well as develop solutions to complex challenges. But, make no mistake, this innovation rests on a bedrock of technical excellence.

References

1. https://www.iea.org/reports/global-energy-review-2025/global-trends

2. https://partners.wsj.com/emerson/unlocking-performance/how-manufacturerscan-achieve-top-quartile-performance/

3. https://www.iot-now.com/2018/10/05/88969-offshore-rig-monitoring-truereflection-iot/

4. https://www.weforum.org/stories/2022/05/how-digital-solutions-can-reduceglobal-emissions

Figure 3. Smart diagnostics and condition monitoring solutions can help identify issues across their operations and safeguard critical assets.

Stuart Mitchell, CTO, PipeSense, discusses how to revolutionise the hydrotesting process, after half a century of uncertainty within the industry.

For more than 50 years, hydrotesting – a cornerstone of pipeline commissioning and integrity verification – has remained largely unchanged. Operators have long relied on manual logs, spot pressure readings, and basic temperature correlations to evaluate their test results. The industry has quietly tolerated inefficiencies, delays, and occasional false test results. Now, that’s changing.

The hydrotest status quo: manual, slow, imperfect

Traditional hydrostatic testing walks a predictable, though laborious, path. Pipelines are filled, pressurised, held under observation, depressurised, and dewatered. Along the way, operators attempt to observe whether pressure holds steady as temperature drifts. Any slight pressure decline causes uncertainty – an uncertainty that can even lead to retesting.

It’s a process plagued by:

) Delayed detection, with hours and hours needed to interpret what pressure movement really means.

) Temperature-driven ambiguity, where thermal contraction mimics leakage or can appear to mask real micro-leaks.

) Administrative lag, as engineers sync paper logs, interpret data, and make go/no-go decisions, sometimes leading to uncertainty and unnecessary re-tests.

Data collection

Intermittent pressure readings, manual logs

Temperature handling Approximate, manual corrections

Leak detection

Leak localisation

Test approval

False positives

Downtime/cycle time

Reactive, subtle leaks easily

Often manual and laborious

Post-hoc, sometimes delayed by hours or not at all

Relatively frequent due to thermal effects

Often extended by retreats or investigation

High-frequency sampling, automated logging

Real-time temperature measurement and corrections

Instant AI detection and trend base assessment, even for tiny new leaks

Real-time location typically within ±30 yd

Real-time assessment and approval as the progresses

Dramatically reduced through precise analytics

Minimised thanks to accurate, live data

) Downtime and cost escalation, when ‘blown’ tests mean re-pressurising, dewatering and refilling, and pushing schedules.

The result? A hydrotest process that remains mired in mid-20 th -century protocols, even as surrounding technologies evolve. Operators have long yearned for clarity, speed, and confidence – but lacked tools to deliver it.

Common sense meets cutting edge

PipeSense has reframed hydrotesting entirely with its PipeTest service, most notably through the introduction of the HydroView Dashboard, officially launched in June 2025. This marks the first time operators can monitor a hydrostatic test live remotely – pressure, temperature, stabilisation status, and leak events – all in real time.

PipeTest’s approach is built around four core innovations:

) Ultra-high-frequency pressure sampling: rather than take sparse manual readings, the system captures pressure trends with precision – every second, not every hour.

) Temperature-corrected pressure floor: real-time ground temperature data is integrated with total thermal input to correctly assess temperature effects, eliminating false positives or negatives driven by thermal contraction or expansion.

) AI-driven leak detection and localisation: the system automatically flags newly formed leaks – in under 2 minutes – and provides locational accuracy often within ± 30 yards.

) Interactive dashboard visualisation: supervisors, inspectors, and engineers can view rolling 15-minute, hourly, and test duration trends, understand stabilisation progress, and validate leak detection – all from phone, tablet, or computer, anywhere, anytime.

A statement from PipeSense

CTO Stuart Mitchell: “To succinctly sum it up, PipeSense clients will now have certainty of outcome with their hydrotest.”

Solving the problem

) Put an end to blown tests: pacing pipelines and eyeballing pressure logs no longer suffice. With data trending and a true temperature corrected pressure floor, operators can distinguish real leaks from thermal drift. This powerful visibility eliminates time-intensive retests and disruptions.

Table 1: Hydrotesting vs PipeTest

Figure 1. PipeSense solutions provide full certainty anytime, anywhere.

) Approve tests in real time: no more waiting. With HydroView, examiners can approve or fail a test with confidence – saving hours, sometimes days of chasing a faulty test outcome. Instant feedback means faster turnarounds and greater control.

) Locate micro-leaks before they grow: traditionally, tiny micro-leaks could go undetected until after depressurisation or, worse, dewatering – and only then if the leak reveals itself during operation. PipeTest spots them as they occur and shows you exactly where they are.

) Reduce resource drain: with clarity comes efficiency. Streamlined staffing, streamlined reporting, reduced retesting, and less downtime add up to real operational savings.

Why the industry needs this change now Hydrotesting is critical not just to operational readiness, but also to regulatory compliance, safety, and environmental protection. High-consequence areas (HCAs) –such as sensitive corridors or populated regions – are increasingly under regulatory scrutiny. The Pipeline and Hazardous Materials Safety Administration (PHMSA) is tightening enforcement, requiring better leak detection and verification protocols. PipeTest’s modernised transparency directly supports compliance, reduces risk, and enhances operators’ social license to operate. Moreover, for downstream contractors and integrated pipeline operators, shortened test cycles and improved reliability translate to cost savings and fewer project delays. In a world where meeting schedules and budgets is ever more challenging, PipeTest offers a clear edge.

Engineering transparently

HydroView didn’t spring from a lab – it was born from ongoing operator feedback and real field frustration. Development is iterative, grounded, and driven by realworld conditions. Engineers pilot prototypes in full-size test facilities located in Katy, Texas, and Clearbrook, Minnesota, where they stress-test sensors, pressure surges, temperature shifts, and pigging scenarios. Only when a feature consistently outperforms in these environments does it earn the PipeSense Certified seal.

PipeSense’s innovation cycle is structured around listening to operator pain points, prototyping with real hardware, field testing, refining, and then repeating. This four-step loop informed both PipeGuard (permanent leak detection) and PipeScan (pig-based leak/blockage detection), as well as the new PipeTest HydroView functionality.

Implications for the pipeline sector:

Enhanced safety and environmental protection

By distinguishing genuine pressure losses from temperature fluctuations, operators avoid the risk of missing small leaks while catching real leaks faster. This means no more missed leaks, reducing spill volumes, and minimising environmental impact.

Smarter asset management

Real-time hydrotest insights provide operators with precise data to decide whether to proceed or to stop and take action. That clarity boosts confidence in the end test result.

Operational efficiency

Contractors armed with HydroView can test multiple assets more rapidly, reduce manpower hours, and shorten turnaround times. Efficiency translates into financial savings and better use of capital.

Regulatory advantage

Transparent, auditable records from HydroView dashboards support PHMSA compliance, speeding certification and passing inspection more readily.

Early outcomes and market response

In 2024, PipeSense began expanding hydrotest services as part of broader deployments of PipeGuard across highconsequence pipeline networks – including the Permian Basin and Midwest systems.

Since the launch in June 2025, pipeline operators have reported:

) Reduced retesting frequency, because those small troublesome leaks are caught early and confirmed, eliminating false ‘blown’ outcomes.

) Shorter hydrotest cycles, with real-time decisionmaking replacing manual delay.

) Improved stakeholder confidence, thanks to objective, visual data that engineers and inspectors can review live or post-test.

Looking ahead: elevating integrity across the pipeline lifecycle

The impact of PipeTest HydroView extends beyond a single test. It’s part of PipeSense’s broader vision –seamless, data-rich integrity monitoring – from pigtracking, to permanent leak detection, to locating obstructions and blockages. By tackling these issues together, it creates an ecosystem of operational clarity and risk management across pre-commissioning, commissioning, and live operations.

And because tools are AI-powered and field-validated, operators don’t just get data – they get confidence.

Conclusion: hydrotesting, meet the 21st century

Hydrotesting hasn’t needed reinvention for half a century. It needed modernisation. PipeSense, through its PipeTest HydroView dashboard and supporting technology stack, provides precisely that: real-time hydrotest visibility, predictive insight, and quick, accurate decisions.

For engineers, operators, and contractors striving to reduce downtime, drive compliance, and enhance safety, the message is clear: the era of hydrotesting guesswork is over. With the real-time dashboard and common sense platform, hydrotests aren’t just conducted – they’re understood, approved, and trusted.

Trung Ghi, Prakarsa Mulyo, Ir. Syed Fazal, Harish Chhaparwal, and Arindam Das, of Arthur D. Little, consider the decisions that need to be made during oil and gas asset decommissioning in order to achieve net zero and energy security.

Oil and gas companies are keen to decommission older assets, replacing them with cleaner energy sources – such as renewables, low-carbon fuels, and energy-storage systems – to deliver

on decarbonisation goals. However, governments and businesses must balance achieving net zero with energy security and stability – and legislation and expectations vary across the globe. This article examines how stakeholders can create a balanced strategy that meets the industry’s changing needs.

Decarbonisation options

As the world moves toward net zero, energy businesses and governments must balance conflicting requirements. Governments understand the importance of decarbonising and moving away from fossil fuels, but they must ensure energy security to keep the lights on in an uncertain world, even as they look to preserve economic and company stability (jobs and incomes) in fossil fuel industries. Companies – and countries – must strategically transform their business models and operations to balance these critical areas, adopting multiple strategies including implementing carbon taxes and credits, enhancing energy efficiency, using renewable energy and low-carbon fuels, adopting carbon capture and storage (CCS) to reduce lifecycle emissions from fossil fuel production, and decommissioning fossil fuel assets.

The decommissioning landscape

Oil and gas assets are a major contributor to greenhouse gas (GHG) emissions, making their phase-out essential to meeting stated net zero targets. However, we should not underestimate the scale of the decommissioning challenge.

There are more than 5500 oil and gas assets in the North Sea, the Gulf of Mexico, and the Asia-Pacific region, many of which are approaching end of life (Figure 1). Global oil and gas decommissioning spend is projected to reach approximately US$190 billion between 2020 and 2039, driven by activity in Europe (primarily the UK and Norway) and the US (Figure 2).

Public perception of oil and gas as non-green energy sources has led to a challenging regulatory environment, adding to the pressure already felt by operators. Most existing infrastructure is aging and reaching the end of its operational lifespan, necessitating increased decommissioning efforts. Decommissioning expenditure has already increased significantly over the past few years, influenced by regulatory, economic, and technical factors.

For example, on the UK Continental Shelf, actual spending in 2024 increased by approximately 94% compared to pre-pandemic levels (2019) (Figure 3).

Timing is everything

Timing of asset decommissioning is the main issue governments and businesses grapple with to minimise economic, environmental, and energy-security risks.

The risks of decommissioning too early

Rapid retirement of oil and gas assets can negatively impact the economy, affecting governments, investors, operators, and the supply chain, especially in developing regions. Governments will likely see decreased tax revenues due to a drop in oil and gas incomes and a slowdown in economic activity and growth from job losses and ecosystem disruption. These cannot be offset by the insufficiently developed clean energy sector. Governments will also likely encounter income reductions that prevent investment in subsidies or funding to help clean energy projects commercialise.

Developers and project investors face financial risks if assets are decommissioned while they are still productive and before a full ROI is realised. Similarly, operators may find themselves with assets that have yet to achieve break-even or deliver their desired economic returns requiring substantial funds to decommission. Many businesses rely on current income from oil and gas activities to fund the higher costs of developing clean energy technologies, which will not be possible with full decommissioning.

The risks of decommissioning too late

Waiting too long to retire oil and gas assets presents a different set of risks. Some governments will not be able to achieve their Nationally Determined Contributions (NDCs) under the Paris Agreement because of the number of fossil fuel assets in place and the time it takes to decommission them. Continued reliance on fossil fuel price volatility, which is expected to worsen as supplies reduce, will impact economic growth and energy stability. Lower incomes from fossil fuel taxes will impact national budgets.

For businesses, retaining fossil fuel assets makes it more difficult to meet their stated net zero and climate commitments, and the economic returns from assets themselves may decrease because of rising carbon taxes. There is a real risk they will be stuck with assets that operate at a loss and cannot be economically decommissioned within net zero time frames.

Stakeholder sentiment must also be considered: as banks focus on more sustainable investments, funding streams could dry up, and public anger could drive boycotts that imperil operating licenses.

Figure 1. Oil and gas operating assets nearing end of life that will require decommissioning.

Expect A Higher Standard

Understanding geographic differences around decommissioning

Government approaches to decommissioning vary widely based on asset maturity, fossil fuel dependence, and economic development priorities. This diversity has led to a variety of pathways across the globe, each shaped by regional attitudes and strategies toward decommissioning:

Accelerated pathway (e.g. EU, UK)

Driven by ambitious climate goals and the desire to reduce carbon emissions, developed countries have set aggressive targets to phase out fossil fuels. Governments in these regions are implementing carbon taxes and offering significant financial incentives to promote clean energy projects.

Gradual pathway (e.g. Southeast Asia, India, Africa, Latin America, Middle East)

In developing or key producing countries, the focus is on balancing energy security with economic growth, resulting in continued reliance on oil and gas. These nations tend to have gradual decarbonisation targets and provide limited incentives for clean energy projects, although some earlystage efforts are underway in Brazil, South Africa, and Thailand in the form of oil-rig decommissioning. In the Middle East, nations remain reliant on oil and gas exports, which are central to their economic strategies. However, decarbonisation efforts are gaining momentum, largely driven by the desire to diversify economies and develop new industries.

Mixed pathway (e.g. China)

China is one of the world’s largest importers of oil and gas. Despite this, it remains the global leader in green energy investments, rapidly expanding its renewable and nuclear capacity and highlighting its commitment to balancing energy security with environmental goals. China is enhancing its decommissioning capabilities for oil and gas. China National Offshore Oil Corp. (CNOOC) plans to decommission 171 oil and gas offshore platforms by 2035. These developments highlight the complex interplay between maintaining energy security, supporting economic growth, and pursuing decarbonisation.

Available strategies

Oil and gas companies essentially have three options when it comes to decommissioning: extend asset lifespans, potentially using technologies such as CCS to lower emissions; repurpose assets, potentially using them as the basis of clean energy operations; or fully decommission the asset.

Operators must base their decision on where the asset is located, the country’s regulatory plans, the speed of decarbonisation, potential incentives for clean energy, and the asset’s condition. For global operators, there must be decisions on a project-by-project, country-by-country basis, with the added complication of potential shareholder/stakeholder/public pressure (Figure 4).

Multiple aspects alongside location should be considered, focusing on the economic case for operation. For an upstream oil and gas asset, such as an oil rig, these questions fall into four groups: operational evaluation, risk assessment, regulatory compliance, and economic analysis.

Choice 1: extend asset lifespans

Asset life extension (ALE) is being considered by many oil and gas companies, especially national oil companies in developing countries, given technological advancements in prolonging asset integrity while achieving ROI, optimising costs, and taking a more sustainable approach. The main challenge to ALE is anomaly detection and asset inspection, which are traditionally labor-intensive manual tasks. However, by deploying sustainable solutions such as advanced detection sensors, robotics, and data-driven

Figure 2. Upstream oil and gas assets decommissioning spend forecast by region (2020 - 2039).

Figure 3. The rising expenditure on decommissioning in the UK Continental Shelf.

Figure 4. Framework for decommissioning strategies.

software analytics, companies can optimise these activities, reducing their environmental footprint and enhancing accuracy and reliability.

Choice 2: repurpose assets

This option is a middle ground between full decommissioning and continued operations. It optimises costs, achieves regulatory compliance, and can increase the asset’s value. Identifying how fossil fuel assets can be repurposed to reduce the cost of developing clean energy assets or create more economic value is essential to managing the energy transition, security, and economic growth trilemma.

Repurposing fossil fuel assets offers significant opportunities for clean energy infrastructure, such as energystorage systems, renewable energy projects, nuclear power plants, hydrogen production plants, and tourism hubs. The benefits of repurposing oil and gas assets include access to a skilled workforce with industrial expertise, transportation infrastructure, electrical grid connections, and existing site approvals and licenses. Fossil fuel assets can be repurposed for both energy- and non-energy-related infrastructure, such as turning oil and gas platforms into offshore wind farms or rig-to-reef programmes, which transform decommissioned rigs into artificial reefs, enhancing marine biodiversity, providing opportunities for fishing, and promoting local tourism.

Choice 3: fully decommission the asset

This involves completely shutting down a fossil fuel asset, and, if required, removing infrastructure such as platforms, pipelines, and buildings. This can be an expensive, timeconsuming process. However, it provides opportunities such as creating local recycling industries in the vicinity of ports and building circular economies that benefit local areas and asset owners.

Decommissioning challenges

The five key challenges to decommissioning oil and gas assets include:

Lack of regulatory frameworks

The party responsible for costs, the extent of decommissioning required, and future environmental liabilities are not always clear, particularly for assets operated under license from governments.

Lack of up-to-date technical specifications

Fossil fuel assets have been developed and customised over time, meaning there may not be accurate technical specifications available for all parts of the facility. This adds complexity and makes it difficult to standardise processes and apply them across multiple assets to improve efficiency.

Lack of ecosystem and infrastructure readiness

Some fossil fuel assets, such as oil rigs, have previously been decommissioned; however, they were nowhere near the scale of the current market. Given the large numbers of assets that face decommissioning within specific timescales

to meet decarbonisation goals, new infrastructure (e.g., port facilities for oil and gas rigs), expanded waste management, and service-provider capabilities and standards will be needed.

Lack of visibility into operator strategies

Many decommissioning strategies are at an early stage, with operators still considering repurposing assets or continuing to use them. This lack of visibility makes it difficult for ecosystem partners and suppliers to plan effectively and invest in new capabilities and appropriate resources. It also hampers the ability of operators to coordinate joint decommissioning efforts, which could save costs and improve efficiency.

Lack of available financing

Decommissioning tends to be an expensive process, and operators must ‘find’ money in existing budgets to carry out projects. There are also many orphaned assets that were developed prior to regulations that required mandatory decommissioning paid for by operators, leading to legal questions around responsibility and ownership.

Best

practices

Successfully decommissioning/repurposing fossil fuel assets is key to meeting decarbonisation goals while ensuring energy security and delivering economic growth. Best practices include developing a strategic roadmap for oil and gas asset transition, factoring in their impact on the energy transition, energy security, and economic growth; establishing regulatory foundations for effective decommissioning, including robust health, safety, and environmental legislation; setting up standardised financing guidelines to make it clear who is responsible for decommissioning activities and costs, particularly for older assets; ensuring transparency to enable ecosystemwide collaboration; leveraging technology to extend asset lifespans; standardising technical specifications; building local recycling hubs for sustainability; and establishing a collaborative ecosystem between government, communities, supply chain/service providers, and operators.

Conclusion

Decommissioning oil and gas assets is crucial for achieving net zero targets while maintaining energy security and economic stability. Premature retirement of these assets can cause economic disruption, job losses, and reduced government revenues, especially in fossil fuel-dependent regions. By collaborating strategically, governments and companies can foster a sustainable energy transition while minimising risks to economic stability and energy security.

Reference

1. https://www.nstauthority.co.uk/media/zvjbfauj/decommissioning-costand-performance-update-2025.pdf 2024 figure on page 15, £2.4 billion, or approximately US3.2 billion.

Alex

Flournoy, Vice President of Business Development, Baseline Energy Services, discusses the role mobile natural gas-powered generators play in meeting the power requirements of electric-drive compressors.

In the midstream sector, compressors operate nonstop, pushing natural gas across thousands of miles of pipeline.

By maintaining consistent pressure, these compressors efficiently move natural gas from the wellhead to the market, serving everything from residential heating to LNG exports. Today, many midstream operators are considering employing electric-drive compressors based on their reliability and low or zero-emissions operation. These same factors are also driving the consideration of electric compressors’ use in gas-lift-enabled production.

However, providing a reliable source of electric power to these compressors is no minor issue. Many natural gas compression facilities are located in remote locations which have unreliable grid connections. This set of circumstances is forcing midstream companies to evolve their approach to powering these modern electric compressors.

Enter mobile natural gas-powered generators, a new generation of flexible, scalable, and environmentally friendly

solutions which are transforming how electric compressors can be powered.

The challenge of powering modern electric compressors

Gas compression is mission-critical for the natural gas industry. A sudden loss of power can disrupt flows, damage equipment, and create costly downtime. The problem is that many compressor stations are located at the far edges of the electric grid, in rural or remote locations where reliable power is not guaranteed. In this case, outages are not just inconvenient; they can jeopardise contractual obligations and system integrity.

Similarly, the loss of power during gas lift operations can result in significant production loss.

Traditionally, oil and gas operators have been forced to rely on two options: the costly extension of transmission lines from the grid or the use of diesel generators. However, both approaches offer significant drawbacks. Grid power can

be unreliable in remote areas, while using diesel generation brings with it high fuel costs, emissions issues, and logistical headaches associated with transporting fuel. In addition, as environmental pressures mount, diesel is becoming less competitive compared to new onsite power solutions available in the market

Mobile natural gas generators: technology meets necessity

Mobile natural gas-powered generators are closing the gap between operational reliability and environmental responsibility by providing a clean and dependable power source for electric compressors. These generators, often trailer-mounted for easy deployment, directly convert natural gas into electricity. Since fuel for these generators can be taken from the pipeline or wellhead, these generators can provide a stable and scalable power source with limited interruption in fuel supply.

Today’s mobile natural gas generator systems are designed to meet the power requirements of modern electric compressors, most of which operate at 4160 V. In terms of capacity, these mobile units are highly flexible. Mobile natural gas generators are available in different configurations, with popular sizes being 400 kW up to 2.5 MW of power per unit. When higher capacity is needed, operators can engage parallel load-sharing of generators to create significantly larger microgrids, ensuring redundancy, scalability, and optimal efficiency.

This modular approach allows operators the flexibility to scale mobile natural gas power solutions to meet expanded requirements, reduce output during periods of lower demand, increase reliability through redundance, and redeploy units to other facilities as load needs change.

A new mobile natural gas generator

To meet evolving customer power needs, in 2024 Baseline developed the NexGen 400™ mobile natural gas generator, engineered to meet the reliability, low-emissions requirements associated with powering electric compression equipment. This unit produces 580+ horsepower and 385 kW of continuous power on 1000 btu pipeline quality gas and can be run in parallel to meet the power requirements of any size electric compressor.

A benefit of this system is its limited environmental impact. Baseline engineered the NexGen 400 to meet the most stringent emissions requirements, and today the unit boasts a NOX and CO output profile that are respectively 90% and 69% lower than current federal EPA standards for mobile spark-ignited engines. For operators balancing ESG commitments and regulatory compliance with performance, this level of environmental impact represents a compelling advantage.

Using the same natural gas that pipeline facilities are already handling or gas from the wellhead, mobile generators can create a closed-loop operation, eliminating the need for external fuel deliveries while minimising emissions.

Operational benefits of mobile natural gas generators

Modern mobile natural gas generators offer a number of significant advantages when used to provide power for electric compressors. These advantages include:

Reliability in remote areas

Where grid power is unreliable or nonexistent, natural gaspowered generators ensure 24/7 availability. These generators protect against costly disruptions and keep facilities online even in extreme weather or during regional blackouts.

Cost efficiency

Using natural gas from the pipeline or wellhead reduces reliance on costly diesel fuel and eliminates the need to transport fuel to remote sites. The logistical savings alone can be substantial.

Environmental performance

With ultra-low emissions system designs, mobile natural gas generators outperform diesel alternatives by a wide margin. Reducing carbon and NOX output is an operational and reputational win for operators facing scrutiny from regulators and investors alike.

Scalability and flexibility

The ability to parallel units into a microgrid allows operators to fine-tune their power supply to match demand. This approach increases efficiency while providing redundancy.

Figure 1. Baseline mobile natural gas powered generators running in parallel.

Figure 2. A natural gas pipeline.

The ESG and regulatory angle

Even with a new administration in Washington, D.C., the oil and gas industry continues to face pressure to demonstrate its commitment to responsible environmental stewardship. Air quality standards remain high, and investors are scrutinising ESG disclosures. In a related development, communities situated close to compression or gas lift facilities are demanding cleaner operations.

Baseline’s NexGen 400 provides a tangible solution to address these conditions as operators can demonstrate compliance with, and even surpass, the strictest federal and state requirements. Beyond compliance, integrating loweremissions technology strengthens ESG reporting and helps

both midstream and operating companies position themselves as forward-thinking energy providers.

Looking ahead: the future of mobile power for compression operations

The market for mobile natural gas generators in the oil and gas industry is poised for significant growth, based on the increasing popularity of electric compression for midstream and gas lift operations. In addition, the US natural gas industry is moving to meet the growing global demand for LNG, significantly adding to the expansion of midstream operations. At the same time, overall electric power demand, already at a high level, will continue to grow as power-hungry data centres are brought online. Demand for electricity in the US is sure to soar, creating scarcity in supply.

While the use of electric compressors in gas lift and midstream operations is expanding, operators are struggling to power this equipment. The often-remote locations of compression facilities and reliance on unreliable grid power have created vulnerabilities.

Mobile natural gas-powered generators offer a compelling solution for delivering the power necessary to operate the electric compressors. These proven units provide scalable outputs ranging from 500 kW to 10 MW and are compatible with modern 4160 V electric compressor systems. Further flexibility is derived from these systems’ ability to form load-sharing microgrids.

Products like the Baseline NexGen 400 demonstrate that reliability and sustainability are not mutually exclusive – they can be achieved together.

In the future, mobile natural gas generators may be paired with battery storage systems, enabling hybrid operations that maximise efficiency while reducing fuel consumption. Advanced microgrid management software will further optimise load balancing, making operations smarter and more responsive to change.

Mobile natural-gas-powered generators are no longer just a backup solution; they are a core operational strategy for compressor stations across North America. For an industry facing regulatory pressure and increasing demand, these generators represent more than a stopgap; they are an important element in the future of powering electric gas compression facilities.

Anne Knour, Tracto Technik, illustrates the use of sustainable trenchless grid connection in the North Sea, highlighting the use of rammers to support offshore pipeline construction projects.

Everything about this pipeline construction project is huge: the construction site ‘By the lighthouse’ on the island of Norderney in the North Sea covers 14 000 m 2 and has an additional 8000 m 2 of storage space. It is surrounded by a 257 m long, 10 m high noise barrier. In addition to forklifts and excavators, two heavy-duty cranes are at hand to transport materials and equipment. Two maxi horizontal directional drilling (HDD) rigs having

thrust and pulling forces of 250 t and 450 t, respectively, are used to install six pipelines that will each host a bundle of three submarine power cables. There are seven water tanks with a total capacity of 850 l on site for mixing and storing the drilling fluid. To install the pipes and transport materials from the southern mudflats, two huge platforms known as pontoons have been anchored there. Given these

dimensions, the 4 m long, 4800 kg TAURUS rammer from TRACTO seems almost small. Yet, it plays an important role for the success of this project. More precisely, it is what makes HDD drilling possible in the first place.

Balwin1 and Balwin2 are two of four grid connection systems operated by transmission system operator Amprion, which run from wind farms in the North Sea via two converter platforms under the East Frisian island of Norderney to the mainland in Hilgenriedersiel. Each system consists of three parallel DC cables and has a transmission capacity of 2000 mW, i.e. a total of 4000 mW – enough electricity for approximately 4 million people. The contractor, LMR Drilling, must carry out 18 horizontal bores in order to install pipelines into which the submarine cables will later be pulled. Construction work will be carried out in three phases: in the summer of 2025, six, 1010 m long bores will be made from the centre of the island to the southern mudflats towards the mainland. In 2026, drilling will continue northwards with six, 1140 m long sections in the direction of the offshore converter platforms and in 2027, the mainland dyke will be crossed. As the sandy soil in the starting area of the HDD bores is very unstable, the ramming machine is required to drive casing pipes at the entry points for guidance of the pilot bores into the drillable layers.

Pneumatically driven ramming machines are most commonly used in pipeline construction for the horizontal installation of steel pipes for media or protection. With dynamic pipe ramming, impact energy is transferred directly to the steel pipe, while soil is collected inside the openfronted pipe, meaning that obstacles do not need to be completely displaced or pushed ahead of the rammer. Despite their immense impact forces, dynamic pipe ramming machines emit minimal vibration, enabling their use in sensitive environments.

However, the rammers’ impact energy also helps to successfully complete complicated HDD operations. With these HDD Assist and Rescue methods, it is possible to support pipe pulling with dynamic impact force, to loosen stuck drill pipes, and to ram casing pipes for HDD drilling, a process known as ‘Conductor Barrel’. Dynamic pipe ramming is reliable and accurate because the rammer is connected firmly to the steel pipe to be driven and aligned axially behind it. Accuracy is also the decisive factor with the TAURUS on Norderney: ‘It is very important that the casings are built in precisely, to ensure that the bores can be drilled properly,’ explains LMR project manager Jorn Stoelinga.

As this is the first time that LMR is carrying out the ramming work for this project themselves using their own TAURUS, TRACTO has sent two specialists to the construction site to oversee the start of work in July 2025 and instruct LMR’s team on the details.

Working within fixed time frames with minimal disruption

The dune and mudflat landscape of Norderney is part of the World Heritage Site ‘Lower Saxony Wadden Sea National Park’. To protect this highly sensitive ecosystem, construction work in the summer of 2025 was only allowed

Figure 1. The construction site for the BalWin1 and BalWin2 grid connection systems is located in the middle of a protected natural area on this island of Norderney.

Figure 2. The construction site during the installation of the second casing in July 2025. In the background, the work pontoon in the mudflats.

Figure 3. TRACTO’s pipe ramming specialists support the LMR crew during the first use of the TAURUS.

to take place from July to September. “This area is home to specially protected bird species that breed in the spring. And from September onwards, there is a risk of storm surges,” explains Henning Gründemann, who is overseeing the construction site as project manager at Amprion Offshore GmbH. The construction work itself is subject

to strict regulations and ‘nature conservation supervision’: “Special measures apply in order to protect nature and the environment as much as possible. First and foremost is the zero discharge principle. This means that no substances from the construction site may enter the environment,” says Gründemann, adding: “The trenchless construction method complies with the minimisation principle. We opted for the HDD method here because it reduces the environmental impact to a minimum with its limited construction areas.”

Norderney also is a popular holiday destination that gets very busy during the high season. Campsites in the dunes, some of which are next to the construction site, are fully booked. To minimise disruption to holidaymakers, the aforementioned noise barrier was built, and it was agreed that ramming was only to take place between 8:30 am and 1:00 pm, and again between 2:00 pm and 7:00 pm. Driving steel pipes at full thrust is not a particularly quiet process. As with everything in this project, the ramming operations were precisely timed. Six days in July were allocated for it, i.e. one day per casing. The LMR team had the complex preparations well under control, and the installation of the steel pipes towards the southern mudflats began on 22 July as planned. The 24 m long steel pipe casings each have a diameter of 800 mm and consist of two 12 m segments, which were welded together during the course of the work. In order to correspond exactly to the course of the HDD drillings, they had to be driven in at an angle of exactly 14˚ and in the intended direction of the bores. LMR had built a mobile, 6 m high structure made of steel girders to serve as a launch pad. With the aid of a heavy-duty crane, a pipe segment was first placed in the guide rails, then the Taurus rammer was positioned behind it and aligned with centimetre precision according to the machine operator’s instructions. Next, impact segments were mounted in the opening of the steel pipe and firmly connected to the rammer. Once the first 12 m segment had been driven deep enough, impact by impact, in some cases at full thrust, the rammer wasdetatched, the second segment was welded on, reconnected to the TAURUS, which had been repositioned, and driven forward to the drillable soil layer.

Strong performance of one casing per day

This procedure took one working day and was repeated without any problems on the following days. The TAURUS was able to transfer its full thrust of 18 600 J to the steel pipe, with the team being in control the entire time. “Thanks to the training provided by TRACTO’s specialists, our employees were able to familiarise themselves with the ramming technology very quickly,” says LMR project manager, Jorn Stoelinga. Felix Buntkiel, who will be supervising the ramming work at LMR in future, confirms this.

Figure 4. The compressed air-powered TAURUS rammer while driving a steel casing pipe.

Figure 5. A maxi HDD drilling rig during pilot drilling through one of the casings. © LMR Drilling.

Versatile ramming technology: pipeline construction, HDD Assist and more

The dynamic ramming technique is suitable for installing longitudinally welded pipes, spirally welded pipes, seamless pipes, pipes with insulation protection. It is applicable in all soil conditions except for mud, marshes and non-displaceable solid soils, enabling a wide range of applications: for the horizontal installation of steel pipes underneath buildings, roads, waterways, railway tracks, parks, etc.; to construct underpasses or pipe roofs for tunnel structures; vertically applied (e.g. for foundations, sheet piling, or well drilling), and last but not least to support complex HDD pipeline construction jobs using Assist and Rescue techniques. These include Conductor Barrel, i.e. ramming steel pipe casings through difficult soil conditions to more favourable drill starting points. Pull Back Assist incorporates the use of both a rammer and an HDD rig working in tandem to get a problematic product pipe installed. With Drill Rod Recovery percussive power is applied to loosen jammed HDD drill rods. Salvage is the last resort to rescue/remove jammed product pipes when an HDD bore has failed. For all these applications TRACTO offers 12 dynamic and powerful GRUNDORAM models with an impact energy of up to 40 000 Nm.

“TRACTO provided us with excellent support during this initial deployment.” Unlike with conventional ramming, the casing pipes on Norderney do not need to be emptied separately. The soil remaining in the pipes is rinsed out by the drilling fluid during the standard HDD procedure. This meant that one casing could be installed per day, including all ancillary work. The actual ramming operations took only 3 h each. This meant that the noise disruption for holidaymakers was much less than the time slots permitted.

Due to the tight schedule, LMR began setting up the two maxi HDD drilling rigs while the third casing was still being installed. Once the pilot bores have been drilled along the specified cable routes, the steel casings will be removed and the cable protection pipes pulled into the bore channels from the southern mudflats. The steel pipes will be reused next year to build in the casings for installing the cable protection pipes in northerly direction. The two protection pipe strings will then be connected by sleeves at the drilling entry points, and power cables will be pulled in. The cables will be permanently accessible via the sleeve pits. The grid connection systems will be commissioned in 2030 (BalWin1) and 2031 (BalWin2), which is one and two years earlier than planned. Trenchless technology makes this possible.

Mike Marciante, Applications Engineer, NewTek Sensor Solutions, contemplates the importance of Linear Variable Differential Transformers (LVDTs) in ensuring the safety, integrity, and efficiency of pipeline operations.

Linear position sensors, particularly Linear Variable Differential Transformers (LVDTs), play an important role in ensuring the safety, integrity, and efficient operation of pipelines, especially in industries such as oil and gas, water, and chemicals. By monitoring parameters such as elongation, deformation and structural shifts, these displacement sensors help to prevent failures in pipelines, optimise their performance and help ensure compliance with safety and environmental standards. The precise and reliable position measurement provided by LVDTs supports proactive maintenance and performance optimisation in complex pipeline systems.

What is an LVDT?

LVDTs are highly accurate electromechanical transducers that measure linear displacement or position. They convert the linear motion of a measured object into a proportional electrical signal, which can be integrated by operators and control systems. This functionality makes LVDTs essential for precise, real-time monitoring and control of pipelines.

Design advantages of LVDTs

Frictionless measurement

Because the low-mass LVDT core floats freely within its housing, there is no physical contact or friction between the core and the housing (Figure 1). The contactless operation minimises friction, enabling LVDTs to deliver accurate measurements of even small linear displacements in critical pipeline components, such as supports, joints, or welds. The frictionless operation of an LVDT provides for near-infinite mechanical life.

High resolution and repeatability

LVDTs exhibit exceptional reliability and repeatability and are often specified at 0.01% of full range or better. They are reliable over numerous cycles, which is critical for inaccessible or unattended installations (Figure 2). Linear potentiometers and other contact-based technologies, on the other hand, are susceptible to signal noise and performance degradation caused by mechanical wear, vibration, or contamination from dust or liquids.

In pipeline monitoring, sensor resolution is important to detect small changes in pipeline conditions. Over time, pipelines can gradually shift or deform due to thermal expansion, soil movement, or mechanical stress. High-resolution LVDTs can detect small changes in position on the submicron level.

Rugged and sealed designs

LVDTs are extremely rugged and durable to withstand high-pressure, high-temperature, and corrosive environments. Their robustness enables their long-term performance in demanding applications such as subsea and underground pipelines that have temperature extremes, vibration and corrosive chemicals. Unlike mechanical sensors, which are prone to wear, contamination, and corrosion, LVDTs can be hermetically sealed while still operating with frictionless performance even under harsh conditions commonly encountered in pipeline systems.

Some LVDTs hold certifications, depending on what kind of fluid or gas is present in the pipeline.

For example, NewTek Sensor Solutions offers NT-HL LVDTs that are intrinsically safe for use in Class I, Zone 0, and Zone 2 areas. These AC-operated sensors meet the stringent standards required to operate in hazardous locations without risking ignition of combustile materials and gasses. Approved by Intertek Testing Laboratories and carrying the ETL mark, these HAZLOC-approved linear position sensors are certified for safe

2. This chart shows how the output of a position sensor can change over time at a fixed position. The inductive and frictionless operation of an LVDT gives it superior repeatability throughout its entire service life. With no mechanical contact or wear-prone components, the LVDT Position Sensor delivers stable, consistent output at a given position during decades of operation.

operation in hazardous environments where flammable or ignitable gases and liquids, such as in pipelines.

Long-life with minimal maintenance

With no contact or wear surfaces, LVDTs do not degrade over time, making them suitable for long-term installation in remote or hazardous locations. Their non-contact design delivers stable, drift-free performance, with minimal need for maintenance or recalibration.

Since pipelines often extend across remote, buried, or subsea locations (Figure 3) where accessing sensors can be difficult or costly, the durability and reliability of LVDTs help eliminate frequent replacements, ensuring continuous and uninterrupted pipeline operation.

Extended operating temperatures

AC-operated LVDTs are capable of withstanding temperatures up to 200°C (392°F), with some models supporting even higher limits. With no internal electronics, these sensors can operate in areas with high temperatures, vibration, and pressures. New higher-temperature materials and ceramics enable LVDTs to operate at temperatures exceeding 1000°F (537°F).

Piping systems are usually exposed to very high temperatures due to weather conditions, thermal expansion, or high-temperature locations (refineries, power plants). LVDTs with extended temperature ranges ensure accurate monitoring where other sensors might fail or degrade (Figure 4).

LVDTs can handle the high temperatures commonly found in pipeline systems while maintaining reliable performance over extended periods, reducing the need for replacements or servicing.

Different outputs

LVDTs offer a variety of output types, including analog voltage, current, and digital signals. This selection of outputs provides flexibility and precision for pipeline monitoring.

Analog outputs deliver continuous real-time data for basic systems, while digital outputs enable more advanced monitoring and control capabilities. Many modern pipeline monitoring systems are integrated with SCADA systems or automated decision-making software. The real-time data generated from LVDTs is ideal for intelligent systems, allowing for automated alerts and alarms when displacement or deformation exceeds a set threshold, as well as enabling remote monitoring and control. Digital data can be saved in the clouds or shared with different partners.

Operational benefits

Prevent unplanned shutdowns and downtime

LVDTs allow early detection of structural issues, such as thermal expansion, mechanical stress, soil movement, and corrosion. Continuously providing high-resolution measurements, LVDT sensors allow operators to address

Figure 1. This diagram shows the internal core of an LVDT where the core floats freely within the housing for contactless operation that minimises friction.

Figure

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problems before they can develop into more serious and widespread failure modes that can result in forced shutdowns.

Extend equipment lifespan

By ensuring the operating envelope of the pipeline is kept to optimum conditions, LVDTs can help maintain system stability and extend equipment lifespan.

Decrease manual inspections and labour costs

LVDTs allow continuous, real-time measurements of pipeline displacement, deformation, and strain. This can reduce the need for manual inspections, which can be especially difficult in remote, hazardous, or hard-to-reach areas (subsea, deep underground, or high-altitude regions). Operators can optimise resource allocation more effectively and focus their efforts on areas that require attention, as indicated by the data provided by the LVDTs.

Figure 3. NewTek Subsea and Marine Sensor designs are used in the monitoring of structural movement, as well as elongation of pipelines in harsh subsea environments. These sensors are engineered to withstand the extreme conditions of deepwater and corrosive subsea environments while delivering reliable, real-time data to ensure the safety, integrity, and performance of subsea pipeline systems.

Figure 4. In certain pipelines, such as those transporting hot fluids, chemicals, or gases, the surrounding temperature can be extremely high. Constructed of stainless steel and featuring a welded 0.75 in. hermetically-sealed housing, NewTek HATR series of sensors are resistant to fluids and caustic materials while operating at high temperatures of 400˚F. NewTek can customise LVDTs with high temperature materials and special packaging to operate in working temperatures from -65˚F to 1000˚F.

Enhance data collection for predictive analytics

With the high-resolution, accurate, and real-time data, provided by LVDTs, predictive modelling can be more precise. This improves failure forecasting and maintenance scheduling optimisation through data-driven decision-making.

Maintain environmental and safety compliance

LVDTs help ensure compliance and safety regulations pipeline monitoring by providing precise and real-time data on displacement and deformation.

Common applications

) Safe valve position monitoring: displacement sensors play a key role in the safe monitoring of valve positioning. The sensors help ensure valves are in the proper position so pressure does not build up, leakages do not occur, and explosions are avoided.

) Leak/rupture detection: abnormal movement detected by position sensors could mean strain or cracks are developing on structural components. This detection allows for immediate preventative action to take place, as leaks can be environmentally and financially disastrous.

) Pipeline thermal expansion: LVDTs can be used to monitor thermal expansion and contraction of pipelines. This can prevent damage from pressure or temperature changes.

) Vibration analysis: pipeline vibration due to pumps, flow, or environmental conditions can eventually lead to fatigue or failure. LVDTs provide accurate tracking of pipeline vibration without friction damping. This makes them an excellent choice for dynamic testing where other contact sensors may miss subtle or rapidly changing movements.

) Pump and compressor monitoring: LVDTs can be used to measure displacement or position of moving parts in pumps and compressors. This data can help to schedule maintenance and increase the reliability of the system.

) Pump and actuator feedback: pumps and actuators are used to maintain pressure and flow in pipelines. The position of these mechanical components can be monitored by displacement sensors to check proper operation and wear and tear before failure occurs.

) Structural health monitoring: pipelines can expand, contract, or shift due to thermal loads, ground movement, or pressure fluctuations. LVDT sensors can be used to detect shifting, bending, or misalignment of pipeline components (such as supports or mounts) to avoid pipeline failures or rupture.

) Pigging systems: position sensors can be used to track the location of pipeline pigs to facilitate effective cleaning and inspection of pipelines from the inside.

Conclusion

LVDTs play a crucial role in pipeline monitoring and maintenance systems, offering accurate measurements of displacement, strain, and deformation for improved safety, efficiency, and regulatory compliance. Their durability to withstand harsh environmental conditions, early failure detection of potential failures, and long-term reliability make them an essential component in modern pipeline monitoring systems.

EPISODE TEN

Featuring Alexandra Kostereva, Operations Manager at GERG (European Gas Research Group). In this episode, we learn about the role of GERG in European gas pipeline innovation, research, and decarbonisation strategy.

Tune in to hear more about:

• The most pressing technical challenges currently facing gas pipelines in Europe.

• What kind of innovations or adaptations are being explored for existing pipeline infrastructure.

• How GERG ensures that pipeline-related research translates into real-world safety, sustainability, or efficiency improvements across the continent.

• Energy resilience in Europe.

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World Pipelines interviews Aliaksei Sratsilatau, Founder and CEO, UAVOS about transforming UAVbased midstream, survey, and security operations.

In energy and infrastructure, unmanned aerial systems (UAS) are rapidly becoming indispensable for inspection, monitoring, and security. Yet the effectiveness of a UAV is only as strong as the sensor payload it carries. For missions that demand clear visibility, accurate geolocation, and reliable performance in all conditions, a stabilised gimbal camera is not a luxury – it is mission-critical. In this Q&A, Aliaksei will give insight into UAV-based midstream, survey, and security operations.

What is the GOS-155 gimbal camera, and what specific gap or mission profile is it designed to fill when it comes to midstream applications?

The GOS 155D/T gimbal camera from UAVOS is a gyrostabilised, two-axis electro-optical and infrared (EO/IR)

payload designed primarily for intelligence, surveillance, and reconnaissance (ISR) missions.

Key features include:

) Dual sensors: a 30x optical zoom HD (RGB) camera plus a high-resolution LWIR thermal imager (1280 x 1024) – ideal for capturing precise day/night imagery.

) Compact SWaP design: lightweight (1.8 kg) and compact (approximately 157 mm in diameter), making it perfect for mid-sized VTOL and fixed-wing UAS platforms without compromising endurance.

) Advanced capabilities: includes an embedded video processor with automatic stabilisation, video tracking, dry cartridge moisture protection, and integration with GPS/INS for real-time target localisation (accuracy approximately 5 m with UAVOS Ground Control Station).

In short, the GOS-155 is tailored for insightful midstream/ UAS missions, offering real-time day/night imaging, GPS-aided tracking, and compact high performance – all while preserving platform endurance.

Why is a gimballed camera system important for UAV-based survey, surveillance, and rescue missions?

A gimballed camera system is a critical component for UAVbased survey and surveillance because it ensures stability, precision, and situational awareness under dynamic flight conditions. Here’s why it matters:

Stabilised imaging

UAVs are constantly affected by vibration, wind, and sudden manoeuvres. A gimbal stabilises the payload, keeping the camera steady and ensuring clear, shake-free images and video. This is vital for reading small details (structural cracks, heat signatures) that would otherwise be blurred.

Flexible field of view

A gimballed system can pan, tilt, and rotate independently of the drone’s flight path. This allows continuous tracking of a target without changing UAV trajectory – critical in surveillance, or inspections of linear assets like pipelines and power lines.

Day/night and multispectral capability

Many gimbals combine electro-optical (EO) and IR (infrared/thermal) sensors. This enables operators to conduct 24/7 operations: identifying overheating equipment in the night.

Georeferenced data and target tracking

Integrated GPS/INS in advanced gimbals allows real-time target localisation and precise geotagging of imagery.

Mission efficiency and safety

By enabling drones to gather accurate imagery from a safe altitude and distance, gimbals reduce risk to human teams. In security, it ensures covert, wide-area monitoring without exposing personnel.

What are the core technical specifications of the GOS-155: weight, size, and imaging capabilities?

Core technical specifications of the GOS-155D/T Gimbal Camera: The weight and size of the camera is approximately 1.8 kg. the dimensions of the camera are 157 mm in diameter and 200 mm in height.

It’s imaging capabilities include a visible (EO) camera with HD resolution, 30x optical zoom (1280 x 720 at 30 fps), and 12x digital zoom (up to 360x combined with optical).

It has a thermal (IR) camera including a LWIR thermal imager, with 1280 x 1024 resolution.

Figure 1. UAVOS UVH 170: Enhancing wildfire response with unmanned aerial support.

Figure 2. UVH 170 delivers georeferenced insights with dual visible-light and thermal cameras.

Figure 3. UVH-170 conducts aerial imaging and multi-level magnetic surveys, delivering geodata for pipeline construction.

These specifications make the GOS-155D/T a highperformance EO/IR payload with a compact and lightweight design. This is ideal for integration on medium-class UAV platforms where maintaining endurance and agility is crucial.

How does the dual EO/IR system enhance visibility and performance across day and night operations?

The dual EO/IR (Electro-Optical/Infrared) setup is exactly what makes gimbaled payloads like the UAVOS GOS-155 so powerful for all-weather, round-the-clock missions. Here’s how it enhances visibility and performance:

Full spectrum coverage: day and night

EO (visible spectrum) provides high-resolution, color imagery with 30x optical zoom which is perfect for daytime surveillance, inspections, and mapping where detail is critical. IR (thermal imaging) can detect heat signatures rather than light, allowing operators to ‘see’ in total darkness, smoke, fog, or dust.

Together, they ensure the UAV delivers actionable intelligence 24/7, regardless of lighting.

Improved target detection and tracking

EO cameras excel at identifying and classifying objects (recognising shapes). IR cameras excel at detecting presence and movement, even when visual camouflaging is used. Combining both means operators can first detect with IR, then identify with EO, reducing false positives and improving mission reliability.

Mission flexibility across environments

Infrastructure monitoring: EO captures detailed surface images; IR detects overheating or energy leaks invisible to the eye.

Enhanced performance with integrated processing

Systems like UAVOS’ GOS-155 integrate video stabilisation, tracking, and geolocation across both sensors. This allows realtime fusion of EO and IR data, automatic tracking of moving targets, day or night, and accurate geotagging for situational awareness and reporting.

What smart features are embedded in the GOS-155?

The GOS 155D/T gimbal camera from UAVOS comes equipped with a range of intelligent embedded features that significantly enhance its performance and mission capabilities:

) Onboard processing and tracking which keeps targets in view without needing extensive operator input.

) GPS/INS fusion enables accurate, actionable geospatial intelligence.

) Large removable storage simplifies data transfer in remote operations.

) Robust design ensures reliability across challenging environmental conditions.

In essence, the GOS-155D/T isn’t just a gimbal – it’s a miniature ISR command centre, combining advanced

automation and robust endurance to support day/night, long-duration unmanned missions.

How does the system calculate and deliver real-time target locations across different environments?

The system combines global positioning system/inertial navigation system (GPS/INS) navigation, gimbal orientation, and advanced geo-pointing software to continuously calculate and stream target coordinates in real time –ensuring operators can act on precise, georeferenced intelligence in any environment.

Sensor data collection

The gimbal carries EO (visible) and IR (thermal) sensors plus an internal inertial measurement unit (IMU). It also integrates with the UAV’s GPS/INS. This combination lets the system know both the UAV’s exact position in 3D space and the gimbal’s precise orientation.

Line-of-sight targeting

When the operator or auto-tracker locks onto a target, the gimbal records its azimuth (horizontal angle), elevation (vertical angle), and zoom level. Using trigonometry and the UAV’s altitude from GPS/INS, the system calculates the target’s approximate coordinates on the ground.

Georeferencing algorithms

Advanced geo-pointing algorithms fuse the UAV’s GPS data with the gimbal’s angular measurements. These algorithms correct for aircraft motion, roll/pitch/yaw drift, and environmental factors to generate an accurate latitude/longitude fix of the target.

Real-time data delivery

The processed target coordinates are overlaid on the video feed and transmitted to the Ground Control Station (GCS). Depending on the configuration, accuracy can be:

) Approximately 20 m under standard conditions.

) Approximately 5 m when paired with UAVOS’ integrated GCS software and calibrated INS.

Environmental adaptability

) Day/night: assess EO in daylight and IR in darkness/fog/ smoke.

) High-altitude/long-range: automatic air pressure compensation maintains accuracy of sensors.

) Dynamic flight: the gimbal’s stabilisation and embedded video processor keep the target lock stable, even during UAV manoeuvres or turbulence.

What’s the accuracy range when paired with UAVOS’ Ground Control Station?

The GOS 155D/T gimbal sends stabilised EO/IR imagery and real-time telemetry – including live video feed, target coordinates, and sensor data – to the PGCS.4. The operator monitors everything seamlessly via the station’s advanced interface.

The video-tracker software, integrated into PGCS.4, facilitates automated object tracking and overlays target coordinates onto the live view – allowing quick detection, tagging, and response.

The station also supports the preparation, upload, and logging of mission parameters. Operators can plan or modify mission profiles directly within PGCS.4 and then relay those commands to the UAV with confidence and ease.

How is the GOS-155 engineered to perform in high-altitude or harsh weather conditions?

The GOS-155 is engineered with pressure compensation, anti-moisture protection, robust construction, and advanced stabilisation. Together, these features allow it to deliver reliable ISR capabilities at high altitudes and in demanding weather conditions, where conventional payloads might fail.

What materials and design choices support its ruggedness and operational reliability?

The ruggedness and reliability of the UAVOS GOS-155D/T gimbal camera come from a combination of careful material selection and engineering design choices.

Aircraft-grade aluminium housing

The gimbal is built from aircraft-grade aluminium, which provides a high strength-to-weight ratio which keeps it light (approximately 1.8 kg) yet durable, and resistance to vibration and structural fatigue common in UAV operations. This ensures the gimbal remains stable and reliable even during long missions or turbulent conditions.

Environmental protection and sealing

Automatic air pressure compensation prevents stress or sensor drift at high altitudes. Drying cartridge (moisture protection) stops condensation or fogging inside the housing, vital for reliability in humid or freezing climates. Sealed design helps keep out dust, salt spray, and environmental contaminants.

Internal stabilisation systems

Two-axis gyro-stabilisation isolates sensors from aircraft vibrations. This reduces wear on components while maintaining image clarity and sensor longevity.

Integrated smart electronics

Embedded video processors reduce reliance on external systems, lowering cabling complexity and failure points. Internal modular design simplifies maintenance and increases operational uptime.

How does this system fit into UAVOS’ broader portfolio of unmanned technologies?

The GOS-155 fits into UAVOS’ portfolio as a core enabling technology that turns UAV platforms into powerful, mission-ready solutions. It reflects the company’s philosophy of delivering complete, integrated

systems – aircraft, payloads, ground stations, and supporting infrastructure – engineered for precision, reliability, and realworld demands.

Integrated payload for UAV platforms

UAVOS designs and manufactures multi-role UAVs such as the UVH-25EL and UVH-170 helicopters. The GOS-155 serves as a primary ISR payload, providing stabilised EO/IR imaging and geolocation that allows these UAVs to conduct missions in security, defense, environmental monitoring, and emergency response.

Seamless ground control integration

The gimbal is fully integrated with UAVOS’ PGCS.4 Portable Ground Control Station, which means operators can control flight, payload, and data processing from one interface. This interoperability highlights UAVOS’ systems approach – designing not just UAVs, but the complete ecosystem of sensors, software, and ground systems.

How does the GOS-155 reflect broader trends in ISR tech, UAV miniaturisation, or autonomous missions?

The GOS-155 reflects the future of ISR technology: lightweight, multi-sensor, intelligent, and autonomous-ready. It enables UAVOS platforms and third-party UAVs to deliver high-value intelligence with smaller systems, lower power consumption, and reduced operator input – aligning seamlessly with global defence and commercial UAV trends.

What does this mean for the future of unmanned aerial survey and security operations for pipelines?

For pipeline operators, systems like the GOS-155 represent a shift toward persistent, autonomous, and cost-efficient aerial monitoring. They extend operational reach, improve accuracy, and reduce reliance on manpower – ultimately reshaping how critical energy infrastructure is surveyed and secured.

Enhanced situational awareness

With its dual EO/IR system and real-time geolocation, the GOS-155 allows UAVs to monitor pipelines day and night, in varied weather conditions. This means operators can identify leaks, intrusions, or potential hazards far more effectively than with traditional patrols.

Precision in detection and response

The ability to calculate target coordinates with up to 5 m accuracy when paired with UAVOS’ Ground Control Station ensures that anomalies along pipelines (tampering, vegetation encroachment, or damage) can be pinpointed quickly. That precision reduces false alarms and speeds up response time.

Lower costs and higher coverage

Traditional manned patrols (aircraft, vehicles, security teams) are expensive and limited in coverage. A UAV with a lightweight, rugged gimbal like the GOS-155 can fly longer missions.

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