World Pipelines - Extreme 2021

®

A SUPPLEMENT TO WORLD PIPELINES

LEADING THE WAY IN INACCESSIBLE TERRAIN CABLE CRANE SYSTEMS - PIPE LAYING SOLUTIONS IN CHALLENGING AREAS www.lcs-cablecranes.com

VERSATILE. Always a leading innovator, we supply customers with cutting-edge diagnostic and system integrity solutions. This, bound with our focus on flexibility, reliability, cost and quality, leads to offerings beyond your expectations.

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CONTENTS

®

PIPELINE MATERIALS

03. Comment Adapt and survive.

31. (Thermo)plastic fantastic

05. Guest comment

Igor Azevedo, Onshore Flexible Pipes, Baker Hughes.

Leigh Crestohl, Partner, Zaiwalla & Co., UK.

PIPELINE SPILLS

KEYNOTE ARTICLE

33. Revisiting the risk

06. Where are we vulnerable?

Tyler Paxman, MSc, PEng, Research Engineer, and Mark Stephens, MSc, PEng, Engineering Consultant and Chief Engineer, C-FER Technologies, Canada.

Claire Fleming, AKE International, UK.

COMMUNICATIONS 37. A new generation of tools Nigel Greatorex, ABB.

Claire Fleming, AKE International, UK, analyses the risks facing the global pipeline industry, providing detailed insight into the specific threats posed in each region.

41. Protecting against product loss Pedro Barbosa, Industry Sector Manager - Pipelines, at Fotech, a bp Launchpad company.

G

lobal pipeline infrastructure exists in extreme environments. Whether that extreme is climatic, geographic, strategic, political, societal or criminal, it poses operational and economic challenges, impacting stakeholders across and beyond the 120 countries transgressed by over 3.5 million km of pipelines (Marketwatch, January 2021) above ground, beneath our feet, running through our forests and under our oceans.

These are the very extremes we enable our clients to de-risk and to enter, operate and invest in safely and securely. As a global risk consultancy, we are asked to look at risk from many angles. In the case of a pipeline, this could be for an operator, responsible to multiple stakeholders and looking at strategic level risk, or that same company assessing risk from a tactical operational perspective. It could be a company further down the supply chain contracted for maintenance works, or equally, a legal firm engaged in merger and acquisition activity or an insurance underwriter assessing risk to its exposure. Whatever the angle, it all starts with intelligence and analysis.

To help you navigate some of the most relevant risks affecting these crucial assets and critical elements of infrastructure, our analytical team selected pipelines from their geographic regions of expertise and shared their thoughts on the risk environment for the year ahead. From the pipelines and regions highlighted below, you will see recurring themes. Unsurprisingly, these include the geopolitical impact of the economic forces of supply and demand; and the attraction of pipelines as often accessible, potentially lucrative, strategic and high-impact targets to a range of hostile actors both locally and globally. Of course, the rather large elephant in the room – COVID-19 – has exacerbated existing threats while incubating new ones. This is impacting the way in which security can be deployed.

Moreover, increasing reliance on technology – itself bringing pros and cons, not least the risk of cyberattack – is a risk to which the sector was among the most vulnerable even before COVID-19 entered our vocabulary.

Our collective travel plans have been hampered enough already, so let’s get started. Our journey begins in the Asia Pacific region and we will travel westwards towards the Americas.

PIPELINE MONITORING

Asia Pacific Central Asia, China: Regionwide pipelines While security risks facing the 1800 km dual Central Asia-China pipelines are assessed to be low, they could potentially escalate amid heightened tensions over Beijing’s repression of ethnic Uighurs, a Muslim Turkic community with strong links to Central Asia. China’s long-standing security build up in the region of Xinjiang has minimised the threat of sabotage within the country. Security around the 1300 km section which runs through Kazakhstan is heavily fortified with outposts operated by private security companies.

No security incidents against the pipeline have taken place in recent years and the risk of any incidents remains low. Meanwhile, the pipelines’ Line D section – which was due to be completed in 2020 – has been severely delayed due to the COVID-19 pandemic.

However, both the strategic importance of the pipelines and Central Asia’s economic dependence vis-à-vis China are likely to mitigate potential security risks posed by growing resentment towards China.

China, Myanmar: Sino-Myanmar pipelines As Beijing continues to maintain a guarded approach to the 1 February coup that ousted Aung San Suu Kyi’s civilian government, Sino-Myanmar pipelines are at a heightened

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PAGE

43. As seen from the sky

06

Peter Weaver, Orbital Sidekick, USA.

SHUTDOWNS AND SAFETY

REMOTE SENSING

47. Rent or buy?

12. Reaching into the remote

Richard Ryan, Dräger Marine and Offshore, and Dräger Hire.

Matthew Hawkridge, Chief Technology Officer, Ovarro, UK.

PIPELINE SECURITY

CLIMATE AND CONSTRUCTION

50. To patch or not to patch?

17. Sub-zero pipeline construction

Gabe Authier, Tripwire, USA.

Lindsey Mattson, Precision Pipeline, LLC, USA.

INSPECTION

DIGITALISATION

53. Pressure and diameter: the double whammy

20. Maximising value: digital edition

Stefan Vages, ROSEN Group, USA.

Kjell Eriksson, Vice President, Digital Partnering with DNV’s Energy Systems business unit.

25. Simple steps to digital transformation Vicki Knott, CEO of Crux OCM.

MAPPING AND SURVEY 28. A range of ways to minimise risk

®

Henry Berry, Director at UK oil company Tristone Holdings.

Reader enquiries [www.worldpipelines.com]

LCS Cable Cranes GmbH is a company with over 30 years of experience in offering outstanding transport solutions for the construction of pipelines in steep and inaccessible terrain. The Austrian company overcomes transport challenges with the help of cable crane systems and makes pipe constructions in extremely inclined mountain ranges (over 70˚) or rock faces possible. Cable crane systems are environmentally sound, safe and cost-efficient. They have been applied successfully on numerous projects all over the world.

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ISSN 1472-7390

ON THE COVER

Volume 21 Number 5 - May 2021

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Comment ADAPT AND SURVIVE

SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com

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I

n this, the 7th annual special Extreme edition of World Pipelines, we look at the most extreme issues facing the oil and gas pipeline industry globally. The issue is packed with insightful commentary on pipelines operating at the edge of current accepted practice: whether that’s performing frost or ice road construction (p. 17), monitoring pipelines with satellitebased hyperspectral scanning (p. 43), mapping pipelines at high elevation using LiDAR technology (p. 28) or maintaining communications with remote pipeline sites with local temperatures of -43˚C (p. 12).

Below are some of my takeaways from the issue (let me know yours, and any thoughts you have on the advancement of the pipeline sector, at elizabeth. corner@worldpipelines.com).

The Tripwire article – To patch or not to patch?, p. 50 – is particularly pertinent in light of the recent Colonial Pipeline hack. As digital, internet-connected systems become the norm in the oil and gas pipeline industry, there is a price to be paid for this extra level of connectivity. Cyberattacks seek vulnerabilities in software and control systems. It is therefore imperative that security teams protect assets. The article describes the use of patches to fix applications and mitigate risks. Patch management, however, is a delicate business and sometimes a patch isn’t possible (when it would cause disruption to the asset, or where the system is too complex for a patch).

“It’s easier to patch systems that are centralised into one corporate network. Having to secure and patch oil and gas assets that are spread out and in remote locations becomes a challenge.”

DNV’s article – Maximising value: digital edition, p. 20 – outlines the development of digital twin technology. For the uninitiated, this means creating a virtual representation of your asset that serves as the real-time digital counterpart of an object or process (i.e. a pipeline network). “With fluctuating oil price and the impact of COVID-19 on travel, a mirror image of an asset can be developed for varying purposes. For instance, by adding a layer of probabilistic risk modelling to existing digital twins, the concept aims to capture uncertainty, the effect of new knowledge and actual conditions on operational performance and

safety. This will allow operators to adjust operations or take preventive actions to maintain an acceptable risk level at all times.”

Read the article to find out more about the FPSO virtual replica – beautifully named ‘Nerves of Steel’ – built to quantify the structural safety of the vessel.

The frequent reality of our efforts to embrace digitalisation are laid bare in the CruxOCM article – Simple steps to digital transformation, p. 25. Vicki Knott, CEO, cuts through the jargon and advocates for “meaningful forward movement into the digital era for our critical energy infrastructure”. What does meaningful forward movement look like for you? For Vicki, substantial automation of human processes is the key driver towards a digitalised future.

The guest comment (p. 5) focuses on commercial disputes in the pipeline arena. Leigh Crestohl from Zaiwalla & Co. has 20 years of experience advising clients across a broad range of commercial disputes and he shares his fascinating take on litigation strategy in the oil and gas sector, using a RussiaUkraine legal claim as his example. Leigh describes a long-running dispute that includes an alleged oil payment siphoning scheme, a refinery raid, sham agreements, treaty breaches, and a lesson learned about limitation periods.

And finally, AKE International’s keynote article – Where are we vulnerable? (p. 6) – provides a broad overview of risk to pipeline assets around the world. Claire Fleming’s analysis recognises several recurring themes: “These include the geopolitical impact of the economic forces of supply and demand; and the attraction of pipelines as often accessible, potentially lucrative, strategic and high-impact targets to a range of hostile actors both locally and globally.

Of course, the rather large elephant in the room – COVID-19 – has exacerbated existing threats while incubating new ones. This is impacting the way in which security can be deployed.

Moreover, increasing reliance on technology – itself bringing pros and cons, not least the risk of cyberattack – is a risk to which the sector was among the most vulnerable even before COVID19 entered our vocabulary.” It’s clear that challenging times call for adaptation, growth and innovation and when your job is keeping the world’s energy supply safe and secure, the stakes are high.

IT IS IMPERATIVE THAT SECURITY TEAMS PROTECT ASSETS

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Leigh Crestohl Partner, Zaiwalla & Co., UK

P

ipelines are undertakings which, by their nature, carry the potential for complex cross-border litigation. Two recent decisions of the English Court in the long-running dispute between Tatneft and Ukraine illustrate how litigation strategy can have serious and costly consequences.

The dispute arose out of the ownership and control of Ukrtatneft JSC (UTN), which owns a refinery in Ukraine’s Poltava region. On 19 October 2007, UTN was “raided”, and Tatneft’s shares in UTN were effectively confiscated and later acquired by the Privat Group, controlled by Ukrainian oligarchs Igor Kolomoisky and Gennady Bogolyubov. Tatneft was unable to collect some US$420 million for oil supplied to the refinery through a pipeline from Tatarstan.

In May 2008, Tatneft commenced an arbitration against Ukraine under the Russia-Ukraine bilateral investment treaty (‘the BIT Arbitration’). Tatneft claimed for the loss of its investment in UTN, as well as the outstanding oil supply debt, alleging that it was the victim of an unlawful “siphoning” scheme, by which the perpetrators used sham agreements with companies controlled by the Privat Group to siphon funds from the intermediary companies along the contractual payment route. Tatneft obtained a ruling on 29 July 2014 in its favour for US$112 million for treaty breaches, but the oil debt claim was rejected because Ukraine’s liability had not been established.

In March 2016, Tatneft started a claim for US$334.1 million in the English Commercial Court against Kolomoisky, Bogolyubov and others for the alleged oil payment siphoning scheme.

On 24 February 2021, the Commercial Court dismissed Tatneft’s claim as time-barred under the Russian three year limitation period.1 Following an elaborate review of the evidence, including materials filed in the earlier BIT Arbitration, the judge concluded that Tatneft had sufficient

knowledge far earlier than it claimed (at paras 311 and 544546). For limitation purposes, Tatneft only needed to know that funds had been misappropriated through the diversion of money for the Defendants’ own financial benefit.

To many, it may appear a perverse result. However, it serves as a reminder that limitation periods are not mere technicalities, even in cases where serious dishonesty may be at issue. The limitation issue will likely have loomed large from the outset and the costs of litigating this case in the English Court over a five year period will undoubtedly have been huge.

In August 2017, Tatneft started proceedings in England to enforce the BIT Arbitration Award against Ukraine. After failing to resist enforcement on State immunity grounds in 2018 ([2018] EWHC 1797 (Comm)), Ukraine secured something of a pyrrhic victory in November 2020.2 The Court accepted Ukraine’s argument that a portion of Tatneft’s interest in UTN was acquired in contravention of Ukrainian company law, which would have knocked out US$81 million of the US$112 million total award. However, the Court held that it was an abuse of process for Ukraine not to have raised this illegality point in 2018 (at para 74), and that it was now estopped. The judge also inferred that Ukraine deliberately chose not to raise the point in the BIT Arbitration, and had thus waived its right to object to the Tribunal’s jurisdiction.

In litigation, questions often arise about what issues to raise, against whom, where, and when. Many different legal, commercial, political and tactical factors may be at play.

English judges are increasingly intolerant of strategies that prolong proceedings or appear abusive. Withholding even a meritorious argument in one’s ‘back pocket’ can prove risky, and a litigant is generally better off playing its best hand first, and before any potential limitation periods are engaged.

LIMITATION PERIODS ARE NOT MERE TECHNICALITIES, EVEN IN CASES WHERE SERIOUS DISHONESTY MAY BE AT ISSUE

1.

2.

http://www.bailii.org/ew/cases/EWHC/Comm/2021/411.html https://www.bailii.org/ew/cases/EWHC/Comm/2018/1797.html

2021 / World Pipelines

5

Claire Fleming, AKE International, UK, analyses the risks facing the global pipeline industry, providing detailed insight into the specific threats posed in each region.

G

lobal pipeline infrastructure exists in extreme environments. Whether that extreme is climatic, geographic, strategic, political, societal or criminal, it poses operational and economic challenges, impacting stakeholders across and beyond the 120 countries transgressed by over 3.5 million km of pipelines (Marketwatch, January 2021) above ground, beneath our feet, running through our forests and under our oceans.

These are the very extremes we enable our clients to de-risk and to enter, operate and invest in safely and securely. As a global risk consultancy, we are asked to look at risk from many angles. In the case of a pipeline, this could be for an operator, responsible to multiple stakeholders and looking at strategic level risk, or that same company assessing risk from a tactical operational perspective. It could be a company further down the supply chain contracted for maintenance works, or equally, a legal firm engaged in merger and acquisition activity or an insurance underwriter assessing risk to its exposure. Whatever the angle, it all starts with intelligence and analysis.

To help you navigate some of the most relevant risks affecting these crucial assets and critical elements of infrastructure, our analytical team selected pipelines from their geographic regions of expertise and shared their thoughts on the risk environment for the year ahead. From the pipelines and regions highlighted below, you will see recurring themes. Unsurprisingly, these include the geopolitical impact of the economic forces of supply and demand; and the attraction of pipelines as often accessible, potentially lucrative, strategic to a range of and high-impact targets hostile actors both locally and globally. Of course, the rather large elephant in the room – COVID-19 – has exacerbated existing threats while incubating new ones. This is impacting the way in which security can be deployed.

Moreover, increasing reliance on technology – itself bringing pros and cons, not least the risk of cyberattack – is a risk to which the sector was among the most vulnerable even before COVID-19 entered our vocabulary.

Our collective travel plans have been hampered enough already, so let’s get started. Our journey begins in the Asia Pacific region and we will travel westwards towards the Americas.

6

Asia Pacific Central Asia, China: Regionwide pipelines While security risks facing the 1800 km dual Central Asia-China pipelines are assessed to be low, they could potentially escalate amid heightened tensions over Beijing’s repression of ethnic Uighurs, a Muslim Turkic community with strong links to Central Asia. China’s long-standing security build up in the region of Xinjiang has minimised the threat of sabotage within the country. Security around the 1300 km section which runs through Kazakhstan is heavily fortified with outposts operated by private security companies.

No security incidents against the pipeline have taken place in recent years and the risk of any incidents remains low. Meanwhile, the pipelines’ Line D section – which was due to be completed in 2020 – has been severely delayed due to the COVID-19 pandemic.

However, both the strategic importance of the pipelines and Central Asia’s economic dependence vis-à-vis China are likely to mitigate potential security risks posed by growing resentment towards China.

China, Myanmar: Sino-Myanmar pipelines As Beijing continues to maintain a guarded approach to the 1 February coup that ousted Aung San Suu Kyi’s civilian government, Sino-Myanmar pipelines are at a heightened

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risk of sabotage amid growing anti-China sentiment. Anti-coup protesters targeted 32 Chinese-backed factories in Yangon’s industrial township of Hlaing Tharyar, raising concerns of long-term hostility and damages to Chinese assets. Some protesters also called for attacks against the dual Sino-Myanmar pipelines. This project spans nearly 800 km and consists of twin parallel pipelines running from Kyaukphyu port through Rakhine State and the central regions of Mandalay and Magwe to China’s Yunnan province. The security risks facing the pipelines, opposed by local communities’ environmental groups from the very start, increased after China asked Myanmar’s military regime to boost security around them.

The risk of potential sabotage, which is assessed to be moderate, could discourage foreign investment in Myanmar’s oil and gas sector.

MENA

Europe and Eurasia

Saudi Arabia: Yanbu pipeline

Azerbaijan: Baku–Tbilisi–Ceyhan (BTC) pipeline The BP-operated 1768 km BTC pipeline runs from Azerbaijan’s capital Baku on the Caspian Sea, through Georgia to Turkey’s southern Mediterranean coast. The security risks facing the pipeline have significantly decreased since November 2020 when Azerbaijan and Armenia agreed a ceasefire to end four months of fighting over the disputed territory of Nagorno Karabakh. Azerbaijan’s territorial gains provide a greater buffer zone for the pipeline, which lies just over 30 km from the epicentre of the fighting. However, there is precedent for the pipeline itself to be targeted. In October 2020 Baku claimed that Armenian forces fired rockets at it, although Azerbaijani forces prevented damage and repelled further attacks. The current ceasefire remains unstable, despite external peacekeepers. The risk of renewed conflict persists, increasing the chance of attacks and material damage to the pipeline. The risk of attacks through the Turkish portion of the pipeline is lower due to higher security infrastructure and fewer security incidents.

Nonetheless, the risk of the pipeline being targeted by Kurdish secessionist groups in the east of the country persists.

India, Pakistan, Afghanistan, Turkmenistan: TAPI pipeline The ambitious Turkmenistan–Afghanistan–Pakistan–India (TAPI) natural gas pipeline is intended to run from Turkmenistan’s Galkynysh gas field to the Indian city of Fazilka via Herat and Kandahar in Afghanistan and Quetta and Multan in Pakistan.

However, varying issues in each of these countries indicate that the pipeline will not be completed in the medium term. In February 2021 Afghanistan’s Taliban leader Mullah Baradar expressed support for the pipeline during an unusual February 2021 visit to Turkmenistan. However, an improvised explosive device (IED) attack on Abdullah Asafi – who leads the TAPI project in Afghanistan – the day after Baradar’s Turkmenistan visit scored the high levels of insecurity around the project. Speculation that an ascendant, territory-controlling Taliban might guarantee construction – supported by the group’s repeated public statements to this effect – are reminiscent of similar 90s-era hopes which overlooked the Afghan conflict’s durability. Insecurity remains as prevalent as ever, not least because of the Taliban’s own ‘fight and talk’ approach to peace negotiations. TAPI also runs through Balochistan, one of Pakistan’s less-stable provinces. A low-level separatist insurgency poses concerns, with the fair distribution of gas revenue a

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continued point of grievance. Separatist groups have long targeted pipelines. Over the last 15 years there have been over 230 attacks on pipelines in the province and further attacks are likely. Delhi too could be reluctant to invest significantly in the project. Around 42% of the gas transported by TAPI is meant to be sold to India, making Delhi’s involvement vital. However, while Delhi indicates that it remains committed to the project, concerns are high surrounding being reliant on a pipeline which traverses Pakistan.

There have been recent signs of improvements in bilateral relations, but tensions remain. In Turkmenistan direct security risks are lower.

However, official reports that construction is well underway are contradicted by the evidence.

Saudi Arabia’s Yanbu pipeline, or the East-West pipeline, connects the kingdom’s eastern oil epicentre Dhahran with Yanbu port on Saudi Arabia’s west coast. The 5 million bpd pipeline which stretches 1200 km remains in repair after being hit in May 2019 in a cross-border attack by Yemen’s Huthi rebels, with oil currently flowing west via an emergency network. The pipeline’s importance was highlighted in 2019 when aggression with Iran in the Gulf spiked. Tankers and Saudi oil infrastructure were then attacked, demonstrating the need for Aramco to be able to bypass the Straits of Hormuz should they be blocked or oil exports otherwise disrupted through the Gulf. However, risks persist. In recent weeks Huthis have restarted concerted cross-border attacks against Saudi oil infrastructure. Some attacks have been intercepted and some have hit their mark, causing fires but little other disruption.

Nonetheless, further direct hits against pipeline and strategic oil infrastructure remain of concern.

Yemen: Marib-Ras Isa pipeline Yemen’s Marib pipeline connects hydrocarbon-rich Marib province with the government-owned Safer offshore FSO moored off Ras Isa on the Red Sea coast. The risk to the pipeline is critically high, as Huthi rebels launched a campaign in early February 2021 to claim Marib, its eponymous capital and Yemen’s main hydrocarbon reserves – one of the only sources of revenue of the newly formed Saudi-backed Hadi government. Huthi rebels currently control access to the decaying FSO, which holds over 1 million barrels of oil and is leaking into the Red Sea due to disrepair, with everincreasing potential for an environmental catastrophe. Damage to the 200 000 bpd capacity pipeline and its pumping stations is currently being avoided. However, should the Huthi rebels capture and secure Marib town, they will have control of the hydrocarbon assets, pipeline and FSO, in which case AKE assesses that a scorched earth strategy is likely, with the Arab Coalition potentially seeking to destroy the pipeline in airstrikes.

Sub-Saharan Africa Kenya, South Sudan: LLCOP The Lokichar to Lamu Crude Oil Pipeline (LLCOP) is a proposed 890 km pipeline transporting up to 80 000 bpd from northwestern Kenya’s Turkana oil fields to the port of Lamu, with plans for an extension to Juba, South Sudan, as part of the Lamu

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and several armed groups operating in these areas. Both assets have been recurrently targeted in recent years, mostly with explosive devices often forcing state-owned oil firm Ecopetrol to halt pumping and address the environmental damage caused by oil spills. 210 000 bpd-CLC will remain the most targeted asset given its relevance, while intent to damage the Bicentenario pipeline (OBC) – often used to transport oil when CLC suffers disruptions – has also been reflected in growing incidents against it. Ecopetrol also reported a 46% year-on-year increase in crude oil theft from its pipelines in 2020, marking an average of 2638 bpd stolen. Security at this remote oil industry’s operations remains far from guaranteed.

Mexico: oil and gas pipelines nationwide

Figure 1. Extreme environments drive development of increasingly innovative solutions. Image courtesy of James Fisher Offshore from a recent cut and lift project offshore Saudi Arabia.

Port-Southern Sudan-Ethiopia transport corridor. The proposed route traverses some of Kenya’s highest-risk territory, particularly in Garissa and Lamu counties, where Somalia-based Islamist militant group al-Shabaab has carried out numerous attacks against government targets. Though the Kenyan portion is to be buried, providing some protection against sabotage, the threat of al-Shabaab attacks is substantial. Risks are particularly high during construction, which is expected to commence in 2021. The line’s eventual western extension through South Sudan’s Eastern Equatoria region, where various communal militia operate, would be exposed to a substantial risk of attack as well.

Despite a government-led crackdown on oil theft, locally known as ‘huachicoleo’, the practice continues to lead to infrastructure damage, particularly affecting pipelines across the country.

The theft of piping metal has also raised concerns surrounding the threat posed to the cylinders themselves. Moreover, criminal groups have shown readiness and capability to adapt to heightened security force presence aimed at curbing illegal tapings, which cause regular explosions. In March 2021 liquified petroleum gas (LPG) industry association Amexgas warned that illegal taps on LPG pipelines, locally known as ‘gaschicol’, had significantly increased in 2020 – over 23 000 reported such incidents compared to 13 136 in 2019 – causing losses of over US$1.4 billion. Associated risks include clashes between rival gangs and between the latter and security forces tasked with guarding the assets. Oil and gas industry personnel have also been and remain exposed to deadly targeted violence linked to huachicoleo and gaschicol.

Peru: Norperuano pipeline Nigeria: Niger Delta pipelines Pipelines in the Niger Delta face an increased risk of force majeure events due to surging sabotage and oil theft. In February the stateowned Nigeria National Petroleum Corporation (NNPC) reported that the country was losing 200 000 bpd on average – 9% of overall production capacity – due to security incidents targeting pipelines, a nearly three-fold increase from August 2020. Growing economic hardship driven by the COVID-19-induced crisis has fuelled financially motivated oil theft and the wilful destruction of infrastructure. Militant groups, largely dormant since 2016, could also resume attacks should the government scale back amnesty payments, with assets in Bayelsa and Delta states at the greatest risk. Losses have prompted oil majors Shell, Eni, ExxonMobil and Chevron to accelerate divestment. In response to the surge in oil theft and sabotage, on 25 February the government announced plans to deploy the military to protect oil and gas infrastructure, which could help reduce risks.

State-owned oil firm Petroperu’s Norperuano pipeline (ONP) and its pumping stations in the northern Loreto region will likely continue to be targeted by disruptive blockades and attacks by indigenous activists. On 12 March around 100 indigenous protesters seized ONP’s Morona station, took 10 workers hostage and presented a list of socio-economic demands, once again leading to government-mediated negotiations. The 1106 km long pipeline was partially suspended for much of 2020 due to social unrest and COVID-19-related measures, which caused Peru’s oil industry investment to fall by 50% to US$200 million during the first eight months of 2020 year-on-year. On 28 September Petroperu halted ONP’s operations after protesters occupied Station 5 and erected blockades to demand medical centres and COVID-19-related assistance despite earlier agreements.

Operations, which had restarted in August after a three month suspension due to COVID-19, were not fully resumed until 3 January. Further operational and business disruption is expected in 2021.

Latin America Notes Colombia: Cano Limon-Covenas and Transandino The country’s two main oil pipelines – Cano Limon-Covenas (CLC) on the north-eastern border with Venezuela and Transandino (OTA) on the south-western border with Ecuador – remain exposed to attacks by National Liberation Army (ELN) guerrillas

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AKE International is a leading global provider of security and risk consultancy solutions. To talk to Claire or request a free three month trial to AKE’s country risk platform, Global Intake, exclusively for World Pipeline readers, get in touch via claire.fleming@ akegroup.com

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Client: Watercare Customer: McConnell Dowell

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Matthew Hawkridge, Chief Technology Officer, Ovarro, UK, discusses using RTUs to monitor oil and gas pipelines in extreme conditions and describes a case study from the second line of the China-Russia crude oil pipeline, where a remote, high-latitude location brings extreme temperatures and other challenges.

P

ipelines are one of the safest and most effective ways to transport oil and gas.

But, with thousands of miles to cover across some of the world’s harshest environments, monitoring performance and condition can be challenging, to say the least. This article explains how remote telemetry units (RTUs) can be used to optimise the performance and maintenance of oil and gas pipelines.

Whether in upstream, midstream or downstream operations, pipelines play an essential role in the oil and gas industry. But they are not fail-safe. Structural failures including corrosion, cracks and leaks are common issues, which companies must resolve quickly and effectively in order to minimise downtime and interruptions and increase efficiency.

As well as costly product loss, pipeline leakages can significantly damage wildlife and the natural environment and pose a threat to workers and the population. There is therefore a need to constantly monitor the environmental impact of any operations and above all else, ensure the safety of staff and the general public. The most valuable tool in meeting this new range of key performance indicators (KPIs) is information; and the most appropriate device to collect and process this information is the RTU. For decades now, RTUs have been a key component in the data chain from the I/O to

the CEO. These devices have a longstanding track record of sitting on remote pipelines, wellheads and offshore platforms, collecting, storing and acting upon data, regardless of the surrounding environment.

To date, most RTUs have been used to collect and log operational data and perform local control. This very same device is also the ideal solution to collect and act upon the new wave of information that is needed for a modern, efficient and profitable organisation.

The RTU is a field mount computer. It collects data locally, acts upon it immediately, reports data to the central supervisory control and data acquisition (SCADA) control room and maintains a local historical store as an additional backup.

In remote locations, communications may be slow, intermittent or unreliable. The RTU is the device at the edge, sitting between the control room and the field instruments, that provides a low latency response to changing site conditions as well as performing data filtering.

The RTU ensures that only key, critical information is passed via the narrow communications links, minimising data throughput but maximising information throughput. Within the downstream sector, refineries operate 24/7, which means firms need RTU systems that are robust, secure, reliable and

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flexible enough to be able to manage and monitor extensive pipeline networks. RTUs are integrated with sensors across these sites and provide data to the SCADA system.

Working the other way, RTUs can receive commands from the supervisory system and transmit them to the end devices as well as retaining an ability to act autonomously. RTUs can do this over large and remote pipeline networks, handling the data acquisition portion of SCADA, providing early warning of impending issues – such as a rise in temperature of a holding tank or decreased pressure in a pipe – avoiding asset failure, and potential environmental incidents.

Tackling common issues

Figure 1. The TBox LT2 offers outstanding functionality from a single, compact rugged unit.

In practical terms, RTUs help operators overcome a wide range of issues in the oil and gas pipeline sector ranging from continuous monitoring of remote fixed assets, data logging – meaning

critical data from the field is not missed and is available for analysis – through to managing complex remote automation and control applications without the need for operators in the field.

Some of the specific issues that RTUs can help address include: monitoring of flow, pressure, temperature; natural gas flow measurement; optimisation and secondary recovery; storage facilities and pressure monitoring.

A number of practical considerations must be accounted for when choosing an RTU system to deliver these benefits.

The key features that are required in an RTU are resilience to the site environment, an ability to operate with minimal drain on local power resources, and the processing power to perform any local control algorithms autonomously.

It is also beneficial that an RTU has extensive diagnostics capability and a low mean time to repair (MTTR) to reduce the time required for technicians to spend on site, improving both efficiency and personnel safety.

An increased need for efficiency, environmental protection and safety are driving the market for data analysis and monitoring of assets in the oil and gas sector. RTUs facilitate these processes because they can be deployed on a vast range of assets. Once in place, the real value of an RTU is that it can perform autonomous control in real time and then report to SCADA that it has everything under control. Operators at the SCADA interface can ‘supervise’ the operations by setting new KPIs, set points or updating instructions – open/close this, start/stop that, for example – for RTUs to then act upon and manage locally.

This ability to provide accurate, real-time data enables management teams to make better, more informed decisions.

Figure 2. The market-leading TBox MS range, MS32S2 shown here, provides real-time remote access and control of your critical assets.

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In collaboration with our partner, ZKCiT, Ovarro provided 22 TBox-MS Modular RTUs for pipeline monitoring and control. The RTUs perform all data acquisition, control, and communication functions and also periodically report the status of all communication equipment to the SCADA control room.

There is no heat tracing in the valve chamber and the entire control system relies solely on ambient heating from the process and other equipment. TBox RTUs are designed to withstand temperatures across the range from -40˚C to +70˚C but are pushed further than these limits during type testing.

After the pipeline’s first month of operation, ZKCiT was congratulated on the system’s performance. During January 2018, shortly after oil transportation had begun, local temperatures of -43˚C had been recorded. Despite exceeding their stated operational limits, the TBox RTUs continued to operate successfully.

For the PetroChina Pipeline Company Limited, RTUs offered better control and management capabilities, reliability, situational awareness and reduced maintenance costs, even in such remote locations and extreme conditions.

Past to future

Figure 3. The TBox Nano combines the logic and control capability of an RTU with the ultra-low power operation of a wireless data logger.

In addition, because RTUs do everything locally, it means if communications break down, they continue to run, maintaining a historical log, and reporting back later. In remote locations, communications will fail regularly, although RTUs can manage this. For instance, the data that the RTU collects can be used to support maintenance decisions, and to verify that environmental obligations are being adhered to. As well as being used for operations, RTUs can support maintenance teams, health and safety initiatives and environmental management.

RTUs in the field: China-Russia pipeline case study The second line of the China-Russia crude oil pipeline began commercial operation in January 2018 and doubled China’s annual imports of Russian crude oil from 15 million t to 30 million t. The company behind the project, PetroChina Pipeline Company Limited, set a new record by constructing over 800 km of pipeline in 180 days, in a high latitude, extremely cold environment.

The pipeline begins in Mohe, China’s most northern city.

Located almost 53˚ above the equator and 850 km inland, this remote location exposes the pipeline to extreme environmental conditions. Part of the specification for the pipeline’s control system was the need to operate in temperatures between -52.3˚C and +39.8˚C – the record temperatures for winter and summer in the region.

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RTUs have come a long way in the last few years and as pipeline operators face continued pressure to maintain efficiency, safety and deliver shareholder value, their use looks set to increase.

Continued innovation will help drive this change; it is already possible to deploy RTUs on most equipment, whatever its size or age. Inbuilt redundancy and resilience are also helping to avoid system failures. At the same time, improvements in processing power and throughput are helping RTUs keep up with increasing demand for data.

Looking to the future RTUs, which are already ‘mini PCs in the field’, will help harness the power of IIoT by making older assets ‘smart’. Edge computing will come into the mix at some stage, although increased processing power of RTUs means they are already part of a distributed network, processed at the ‘edge’ of the network.

The benefit if this is low latency by computing the data where it is generated – essential for real-time monitoring. In addition, this edge capability provides linear scalability, which will be essential to support the increased deployment of communication devices that reduce pressure on the central network infrastructure.

With geographically spread assets and multiple process that all generate massive amounts of data, key to ensuring these improvements help business performance is being able to capture and interpret it in real-time. The latest, ruggedised RTU technology focuses specifically on that, helping pipeline operators meet their investor and customer commitments.

Notes Ovarro is the new name for Servelec Technologies and Primayer.

Ovarro’s technology is used throughout the world to monitor, control and manage critical and national infrastructure.

Collecting and communicating data from some of the most remote locations and harshest environments on the planet.

Enabling businesses to work smarter and more effectively.

Figure 1. Crews begin building the ice road with small, light equipment and increase size and weight a frost depth increases, creating a sturdy road of ice and frozen soil through wetland areas.

Lindsey Mattson, Precision Pipeline, LLC, USA, explains how infrastructure contractors can ‘drive frost’ as a method of accessing difficult project areas.

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orking in extreme cold weather has a variety of challenges for any project.

However, certain pipeline construction activities benefit from being performed during frozen conditions; for example, work geographically located in an area that has limited access due to saturated soils or environmentally sensitive areas. Construction through environmentally sensitive areas is inherent with unique challenges no matter the timing, e.g. access, workspace, soil segregation, native species, etc. By using the natural ground freezing process, infrastructure contractors can ‘drive frost’ to create an ice road in these heavily saturated areas, therefore limiting the construction

footprint and associated environmental impacts of these sensitive areas. These ice roads allow access to project areas that would be difficult to work in, and even inaccessible, in the warmer months. One of only a few United States pipeline construction contractors skilled in performing frost or ice road construction, Precision Pipeline, LLC, (PPL) used the ice roads to complete one of their cold climate projects.

“We chose to schedule work on one of our Northernmost projects during frozen conditions so we could drive the frost and build a solid road through some of the wettest areas of the project,” says Michael Hyke, Vice President of Midwest Operations with PPL. “By using

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the natural freezing process of the ground, we kept the project environmentally compliant while also saving

money by not purchasing, hauling and removing extra timber mats,” says Hyke.

How it’s done

Figure 2. After reaching the appropriate thickness to support construction equipment and materials, the ice road allows work to begin in otherwise inaccessible wetland areas.

Figure 3. Overall construction impact to the wetland is limited since the frozen ground allows for excavation to happen with minimal mixing of soils.

Driving frost is done in northern climates during the coldest part of the year and during the coldest part of the day, typically at night. Once the temperatures reach the appropriate point, preferably below 0˚F, PPL begins their frost driving activities on a 24-hour work schedule. The process of driving frost isn’t complex, but it does take a lot of planning and coordination, and it can be time consuming. “We begin by looking at typical temperatures in our project location and then plan the approximate time of year we would begin driving the frost based on historical data,” says Mitch Repka, P.E., Director of Major Projects at PPL. “Of course, it is never easy to predict the weather and schedules need to be adjusted daily as we wait for the exact conditions needed to drive the frost safely, efficiently and [be] environmentally compliant.”

As temperatures fall, the crews and equipment are readied for the steady, slow job of building the ice road. Starting with small, light equipment, the road begins by driving over the shallow depth of existing frost. As the weight of the small machinery drives the frost down, more is built at the surface. The process repeats itself until the light equipment is no longer effective, at which point equipment size, weight and width is slowly increased to drive the frost even deeper. The frost depth is continually measured for progress by drilling a small hole through the frost layer and then inserting a metal rod into the hole until the bottom of the frost layer is reached. This depth measurement is recorded and used to determine if there is enough frost to increase the size and weight of equipment for continued frost driving activity.

“This specialty construction technique increases the soils’ supporting strength as the thickness of ice increases in the ice road,” says Joshua Schultz, P.E., Director of Engineering with PPL. “We evaluate the

Figure 4. Construction can now be completed on a bed of solid ground, as if it was being done in a dry environment.

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thickness required specific to the equipment necessary to complete the work. Peatland ice is highly variable in strength and many factors are considered.”

Once the ice road reaches appropriate thickness, the construction equipment and materials can be moved in for the project work to begin, but there is still daily maintenance to keep the ice road operational. “It is a constant process,” says Hyke. “Swamps create heat from the fermenting organic material beneath the surface and sometimes there is a spring or underground aquafer flowing below it as well. These naturally occurring features are trying to melt the ice road while we build it.”

In order to keep an ice road operational for as long as possible, frost driving activities typically continue throughout the night even after the appropriate depth of frost is reached. This allows for project activity to use the ice road during the daytime so crews could complete that section of the job before the weather warms and the area becomes inaccessible. “When you are performing construction with an ice road, your time is limited and completely dependent on the weather,” says Repka. “Just like working in summer months, you have to complete certain tasks before the weather changes to mitigate significant impacts on the project schedule.”

If construction isn’t completed with the ice road in place, it could mean an increase in timber mats to traverse the swamp or wetland without rutting or mixing of water and soils, if it is even possible to continue construction throughout the summer months. Layered mats from two to three mats deep, and even five to six mats deep in some areas, may be needed to keep equipment at the surface. Conversely, construction in the same area during frozen conditions with the use of an ice road allows equipment to traverse the very saturated area with just a single layer of mats that will stay on top of the frozen ground.

Keeping it safe Since driving frost is done in the coldest months of the year and continues daily throughout the night during the coldest part of the day, new challenges are created. The lower temperatures at night are needed for continued movement of the frost but extra considerations must also be made for worker safety. Weather conditions must be addressed at daily and nightly job site analysis (JSA) meetings while crews are closely monitored for signs of cold stress and fatigue throughout their shift. “We drive frost with many safety protocols in place,” says Michael Lillie, Vice President of Health, Safety and Environment at PPL. “Every shift begins with a JSA meeting, and we always have a cold weather plan and a fatigue management plan for the crews. Also, reliable communication for all crew members will keep everyone safe.”

Cold stress is a serious concern as falling skin and internal body temperatures will lead to frostbite and even hypothermia. Properly training workers on cold stress is the first defense in ensuring their safety. Workers should

all know the symptoms of cold stress and look out for the signs in themselves as well in their co-workers. They should also be advised to wear appropriate clothing, dress in layers and cover all exposed skin. Additionally, it is easy to become dehydrated in cold weather conditions so frequent reminders and an easily accessible drinking water supply are safety measures that should not be forgotten.

Communication is also key in keeping workers safe during frost driving activities. The process leaves each operator slowly driving equipment up and down the rightof-way (ROW) for long periods of time and PPL ensures communication among the crew with personal radios. Even though operators are typically in cabbed equipment for the duration of their shift, there may be a need to stop their machine or be outside of it for even a short period of time. The rest of the crew must be informed of any change in activity so they can plan their own driving progress accordingly. “Driving frost is an incredibly tedious job,” says Lillie. “This paired with crews potentially working night shifts in possibly inclement weather, fatigue management and complete communication to all other crew members if fatigued in any manner is an absolute must. Being mentally tired can be much more detrimental than being physically tired and this task definitely has the potential for mental fatigue due to the monotonous nature of the process.”

Eye on environment Driving frost and creating an ice road for cold climate construction has many environmental benefits when compared to wetland construction in the summer months.

The primary reason to build an ice road is to support the equipment that is going to be excavating and digging the trench, minimising the overall impact of construction in the swamp or wetland. Because the ground is solid, the frost driven ground also aids in limiting the mixing of soils since equipment can perform as if it was operating in a drier environment. Together, this creates an overall smaller construction footprint within that wetland.

Additionally, creating a deep layer of frost to mimic dry ground means less ground water impacting the excavation of the ditch. This leads to less pumping of water and less runoff that needs to be contained and filtered with filter bags and straw bale structures.

Driving frost to create a solid structure like an ice road keeps the crews safe and the project environmentally compliant as equipment moves to continue work on a project. “Driving frost creates a floating mat of ice,” says Hyke. “Even though it is solid, it is only as wide as the ROW. As soon as you get to the edge of the right of way and it has insulation on it like vegetation and snow, it will have limited, if any, frost.” This specialty construction process is as unique to cold weather areas as it is to contractors who can perform this type of work. “It takes a lot of planning and communication to do it effectively,” adds Repka. “Every team involved has valuable input throughout the entire process so it can begin efficiently and end effectively.”

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Figure 1. The digital twin is a virtual representation of an asset maintained throughout the lifecycle and easily accessible at any time (©DNV).

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Kjell Eriksson, Vice President, Digital Partnering with DNV’s Energy Systems business unit, explains how the evolution of virtual assets can bring value to operations, and how digital twins can be turned into a real asset.

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n an annual survey of more than 1000 senior oil and gas professionals, DNV revealed that nearly seven in ten (68%) respondents will increase their investment in digitalisation in 2021 – the highest level since the Industry Outlook research series began in 2010 – with a quarter of those questioned maintaining current levels. Much of this is driven by a need to increase profitability (73%).

DNV’s 2021 report ‘Turmoil and Transformation’ ascertains that despite a crash in confidence for industry growth in tandem with reinvigorated cost cutting, the industry views smart and progressive investment as critical to recover from deep market turmoil and forge its path in the energy transition.1 69% stated that digitalisation was critical for their organisation’s survival.

While data collaboration platforms and cloud-based applications/databases top the list of priorities, a fifth (20%) considered digital twins of key importance in the ambition to integrate or produce accurate, high quality data (Figure 2) and potentially reduce up to 70% in engineering hours during field development.2

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Digital twin development

Reinforcing trust and value

While an awareness of digital twins has been around for several years and under many guises, from model-based optimisation to structural re-analysis systems, an accepted definition of exactly what it is and what it is not, is relatively wide. However, the general consensus is that it allows system information to be available to predict performance through integrated models with the purpose of providing decision support.

Still in the early stages of its evolution, today’s digital twin is focused on a series of standalone features to inform decision-making during asset design and operational phases.

As the market and technology matures, it is expected their sophistication and scope will increase significantly to cover the entire asset, eventually becoming dominated by either prescriptive or even autonomous functions.

Rather than think of the twin as a single structure, it should be viewed and treated as a collection of elements or components, of various levels of complexity, each with their own distinct role and function (Figure 1).

Monitoring and maintaining the condition of the data so that it is fit for use can be challenging. Therefore, as the technology evolves, it is vital to combine the criticality and the use cases of the digital twin to fully understand the quality and composition of all the components within it. Implemented correctly, a digital twin could potentially become a platform combining real-time simulations, advanced artificial intelligence and machine learning to analyse and generate data to support decision-making.

Digital twins are a rapidly developing technology widely expected to become a significant contributor to the future management of major industrial sites. In 2020, the market size was valued at US$3.1 billion and is projected to reach US$48.2 billion by 2026. Increasing demand in the energy and power sector is also likely to boost growth from 2021 to 2026.3 While physical oil and gas assets are built to perform to the highest standards and undergo rigorous assurance processes throughout their life, there has been no requirement for their digital counterparts to go through the same procedures. As oil and gas operators demand proof that digital twins can be trusted and deliver value over time, DNV in partnership with TechnipFMC, published the oil and gas industry’s first recommended practice (RP) on how to qualityassure digital twins.

DNVGL-RP-A204: Qualification and assurance of digital twins sets a benchmark for the sector’s varying approaches to building and operating the technology. It guides industry professionals through: ) Assessing whether a digital twin will deliver to stakeholders’ expectations from the inception of a project.

Figure 2. Top priorities for investment in digitalisation.

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) Establishing confidence in the data and computational

models that a digital twin runs on. ) Evaluating an organisation’s readiness to work with and

evolve alongside a digital twin.

For digital twin developers, the RP provides valuable guidance, introduces a contractual reference between suppliers and users, and acts as a framework for verification and validation of the technology.

The methodology was piloted with companies including Aker BP, Kongsberg Digital and NOV Offshore Cranes, and has been through an extensive external hearing process involving the industry at large.

The framework provides clarity on the definition of a digital twin; required data quality and algorithm performance; and requirements on the interaction between the digital twin and the operating system.

It addresses three distinct parts: the physical asset, the virtual representation, and the connection between the two. This connection amounts to the data streams that flow between the physical asset to the digital twin, and information that is available from the digital twin to the asset and the operator for decision-making.

The RP supports digital twin adoption from inception, through to operation and evolution alongside its physical sibling. It essentially brings a level playing field to the sector’s varying technical definitions and expectations of digital twins.

Together with several other major players, including Equinor and ConocoPhillips, TechnipFMC and DNV are also involved in another JIP to establish the required framework for using semantic data in business, including the upgrade of international standards. This work forms an important element of the foundation of a successful digital twin.

Dynamic digital twin Oil and gas companies are increasingly utilising digital twin technology to bring asset information from multiple sources together in a single and secure place, connecting 3D models with real-time field data during the operation phase.

In October 2019, Norske Shell joined forces with Kongsberg Digital to operationalise an ‘asset of the future’. A virtual representation of the Nyhamna facility, a gas processing and export hub for Ormen Lange and other fields connected through the Polarled pipeline, was developed in less than 100 days, and continues to focus on safe, effective and integrated work processes and optimisation of production and energy use.

The next step is to scale the technology across the entire Ormen Lange field, including all offshore infrastructure, to maximise recovery, optimise production and reduce environmental footprint. According to Norske Shell, integrating the entire value chain in a virtual environment will result in a ‘reservoir to market’ dynamic digital twin.4

Concord or conflict between twins Developing a twin is challenging, but success does not necessarily mean making value from it. How can you trust that it works when the technology hasn’t been used before?

Building trust in the quality and integrity of digital twins is key to extracting maximum value and, subsequently, to its adoption. This covers four key areas:

that operators ensure their digital infrastructure is secure, robust, and suitable for all purposes over its lifetime. This can be achieved by applying assurance activities to identify potential cyber security weaknesses and by instilling IT architecture specifications to protect against poor data driven from or to the twin.

Readiness Success depends on the organisational maturity and the capabilities of the workforce to change the way they work and develop alongside the implementation of digital twins.

Examples of relevant areas to assess include governance, management of digital infrastructures and architectures, defined standards and metrics for measuring and recording digital twin performance.

Developing solutions for the future With fluctuating oil price and the impact of COVID-19 on travel, a mirror image of an asset can be developed for varying purposes. For instance, by adding a layer of probabilistic risk modelling to existing digital twins, the concept aims to capture

Functionality If the purchase of a digital twin is driven by technology rather than business needs, it may be incorrectly specified.

This can lead to costly problems if the digital duplicate is inadequately maintained and updated as its physical sibling evolves. In addition, there are technical challenges relating to infrastructure environments for digital twins and data quality. Some companies will also struggle with digital transformations if they do not first tackle the change management challenges involved. Applying proven technology qualification and assurance processes can verify and validate that a digital twin will perform to specification based on the defined business needs.

Figure 3. Establishing requirements for functional elements depends on a well-defined process.

Control Through degradation and ageing, maintenance activities, and larger modifications, real-world assets undergo many changes during their lifecycles, including those made by supply chain partners. Structured processes, instigated either manually or automatically, should be regularly enforced to ensure the carbon copy remains qualified and fit-forpurpose long after being approved and deployed.

As a series of complex and integrating software programmes with varying roles and responsibilities, defining the need for each programme, the key decision it will support, the data required, and other technical information, will ease and hasten accurate decision-making (Figure 3).

Safety As digital twins interact with and have an impact on other information and operational technology systems, it is vital

Figure 4. Aoka Mizu while operating at the Lancaster field (image courtesy of Bluewater).

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Figure 5. The digital twin platform brings all the experts together, providing powerful analysis, insight and diagnostics (©DNV).

uncertainty, the effect of new knowledge and actual conditions on operational performance and safety. This will allow operators to adjust operations or take preventive actions to maintain an acceptable risk level at all times, thereby reducing expensive downtime. By including reliability and degradation models to forecast the remaining lifetime of mechanical components, it can also be used to display the overall impact on safety in real-time.

Hybrid twin technology uses a combination of numerical design models and data from actively recorded strain gauge sensors on board an FPSO, for example. A pilot project between DNV and FPSO specialist Bluewater is using this technology to predict and analyse fatigue in the hull of the Aoka Mizu FPSO (Figure 4), currently in operation in the Lancaster field, west of Shetland.

The project aims to validate and quantify the benefits of creating a virtual replica of the FPSO to optimise the structural safety of the vessel and enhance risk-based inspection (RBI), a decision-making methodology for optimising inspection regimes. To date, the pilot test has shown encouraging results.

Termed ‘Nerves of Steel’, the underlying concept permits the use of various data sets (external environmental data or local sensor data) combined with digital models of the asset, to develop a hybrid replica model of the vessel’s structure.

This can be used in real-time to monitor the asset’s condition, identify and monitor high risk locations, and plan targeted and cost-efficient maintenance and inspection activities.

The trial will expand on traditional FPSO integrity management strategies, which are based on software-based assumptions made at the design stage as well as current inspection records to enhance RBI decision-making. The trial is expected to provide new insight and smarter ways of managing risks and costs related to structural integrity management.

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This is DNV’s third pilot project evaluating the performance of hybrid digital twin technology. With global support from the advisor’s experts in Singapore, the UK and Norway, the first involved defining a repair procedure for a FPSO flare tower. Another trial, which is still ongoing, is being performed on a fixed offshore platform.

Making your digital twin a real asset DNV’s Technology Outlook 2030 predicts cloud computing, advanced simulation, virtual system testing, virtual/augmented reality and machine learning will progressively merge into full digital twins which combine data analytics, real-time and near-real-time data on installations, subsurface geology, and reservoirs5 (Figure 5).

Selecting the right twin can allow the digital technologies with which it may interact and/or enable through data exchange, to deliver benefits across upstream, midstream and downstream energy activities and play its role in carbon reduction.

Creating trust is imperative to its acceptance as a valuable and reliable technology. After all, potentially millions of decisions about the design, construction and operation of hundreds of thousands of real-world assets may be taken based on them.

Finding the right combination of functionality, operations, infrastructure and organisational set-up will turn your digital twin into a real asset, one that can be trusted and will deliver value to your organisation over time.

References 1.

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3.

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https://industryoutlook.dnvgl.com/2021 https://www.bcg.com/publications/2019/creating-value-digital-twins-oil-gas https://www.marketsandmarkets.com/Market-Reports/digital-twinmarket-225269522.html https://www.kongsberg.com/digital/resources/news-archive/2021/nyhamna-digitalinnovation/ https://www.dnvgl.com/to2030

Vicki Knott, CEO of Crux OCM, explains how automation is a key part of the digital transformation journey and outlines the steps towards reaping financial and operational benefits.

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ominations have been affected in the last year and we are finally starting to see recovery, especially for the transmission pipeline systems of our oil and gas industry. Recovery is great, but how do we come out of this better, faster, and stronger?

Digital transformation has been a trending buzzword for the last four

or more years; however, the actual progress made on a broad level has been limited to moving accounting, finance and administration computing functionality to [insert cloud provider of choice here]. The actual impact beyond spending money on [insert trial artificial intelligence (AI)/machine learning (ML) provider here] with minimal to zero proven ROI, has proven

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minimal to zero ROI in day-to-day operations of moving oil and gas safely and efficiently.

We have all seen the announcements by our pipeline majors, announcing a partnership with IBM Watson or AWS or Azure. These are very important to begin the process of digital transformation and are the first stepping stone to great things. Working beyond these initial partnerships requires the awareness of transmission pipeline leaders to know the limitations of their current workforce and the shifting landscape. Thankfully, leaders these days have the opportunity to be hyper connected to their communities, their opposition and their up and coming talent to ensure the success of digital transformation efforts. It can be difficult for leaders to extend their networks beyond their comfort zones and the proven methods of their past, in order to forge progressive, meaningful relations with people outside of their inner circle for the greater good of the pipeline industry. I encourage pipeline leaders to acknowledge that our industry has provided them with fulfilling, profitable careers along with the responsibility to empower the next generation – whether a vendor or an employee – with the relationships and opportunities to continue the success of the global pipeline industry.

Expectations vs reality When we think about where the rubber meets the road with digital transformation and taking oil and gas transmission pipelines into the digital era, we need to get comfortable with the terms: autonomous pipeline, advanced control room and future control room. To achieve this, we need more than just cloud computing and whether we like it or not, magical AI/ML solutions are not going to make us more efficient overnight. If it’s too good to be true, it probably is.

The thing about ML is that it’s useless unless you have people implementing the use cases that know exactly how it works, and – unpopular opinion – it’s likely not your best engineers that understand the underbelly of your operations best. It’s your control room operators, your heavy-duty mechanics, your electricians, your field inspections staff, the personnel pulling the pigs out of the line. The problem here is the tools may very well be too complex for the people contributing to your bottom line. It is crucial that implementors understand the tools in order to utilise and understand the value for your organisation overall.

A little more ranting on the so-called magic of AI/ML solutions; by some, ML is considered a subsection of AI, by others, AI is considered a subsection of ML. Depending on the audience, both are correct, or, both are wrong. I like to make the following analogy: imagine giving a person a shovel and telling them to dig a hole. They can’t ask questions but must dig the hole. If you don’t tell them where to dig, how deep to dig, and do not take in feedback to determine if their actions are correct, then how would you know that the person is accomplishing a valuable task of digging the hole that you wanted? The hole scenario is quite typical of digital transformation efforts where vendors are brought in for AI/ ML solutions but the vendor doesn’t have the experience to fully understand the complexities of oil and gas pipelines,

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combined with oil and gas pipeline companies not allocating enough dedicated resources to work with these vendors, or enough time to prove ROI. The examples above are typical with AI/ML digital transformation tasks. Expectations of these solutions from leaders in the pipeline industry are not always aligned with the skills and knowledge of those implementing these solutions, both vendors and internal employees.

Finally, no one knows what AI means, even the people who do it (don’t tell them that). Some might call it glorified statistics.

Environmental, social and corporate governance (ESG) ESG is another important part of this story. Pipeline transmission companies cannot achieve the targets set out by their boards on their own and need to work with their vendors and broader supply chain to meet these targets. Efficiency is green, so selecting technology companies and solutions that can create efficiencies to move ESG agendas forward is important. Oil and gas will be used in large amounts for a very long time, so we must use as much environmentally friendly oil and gas as possible.

So, how does one practically improve operations to increase safety, efficiency, volumetric throughput, decrease emissions, decrease costs and meet ESG targets all while you have to reduce headcount and in essence do more with less?

Well, there is this thing called automation that doesn’t just apply to your PLCs. Back to when we moved accounting, finance and administration computing functionality to [insert cloud provider of choice here] I hope we then employed one of the amazing robotic process automation (RPA) providers to automate form completion and other tasks such as copy and pasting important data to the reliable tool that is RPA. RPA has provided tremendous value to many industries, including transmission pipeline companies. Additionally, excellent progress in QR codes or RFI tags auto-logging to inspection and workflow management software such as SAP have added small efficiencies here and there. When applied on large pipeline operations, this results in massive efficiencies for workers’ time and effort – thus saving dollars.

Getting to grips with big data Misconceptions with ML/AI in our industry may be stemming from the multitude of easy wins in emerging sectors such as industrial internet of things (IIOT), and ML/AI applications in web apps and ad optimisations. I recall when I first heard the buzz terms ‘big data analytics’ and ‘data scientist’, many of these terms confused me because as a chemical engineer in the oil pipeline industry (which has excellent utilisation of transmitters, PLCs, SCADA and data historians) I had spent my career data mining for troubleshooting and commissioning assets, on top of optimisation efforts for the same assets. The term ‘big data’ referred to the millions of data points I would filter and trend to find opportunities for improvement. The term ‘IIOT’ referred to the multitude of transmitters, telemetry and actuation already existing on transmission pipeline assets

to ensure their safe operation. These points are to pay tribute to the extremely smart people contributing to our industry over the years.

Automation as a priority Some people think the oil and gas pipeline industry in general is slow moving and behind the times. This is far from the truth as an insider seeing the industry from the inside out.

We are very good at accelerating innovation in our areas of expertise. As the world changes, we need to open up to new innovations, which is very much within our repertoire of skills. The challenge lies therein looking past the shiny things and the big brands and excellent marketing promising “easy wins’’ to what is real and meaningful forward movement into the digital era for our critical energy infrastructure, which is actually powering the energy transition. Some might think my thoughts in this article are controversial, but the millennials are coming, and just wait for Gen Z! Pushing hard past promised easy wins involves automating the hell out of everything you do. From a technical perspective, large transmission pipelines have teams of smart people optimising equipment and business processes. What is being missed is the automation and efficiency gains that can be realised from automation of all human processes. That is digital transformation. Just think of the National Postal Service vs Amazon. Who do you think is going to deliver a package faster? Amazon, because they have automated all human processes to the max. I have been interviewing Gen Z applicants for junior marketing associate positions and without prompting, they tell me how they will automate our

marketing systems and integrate data. This is programmed into your DNA when you grow up with an iPad in hand.

This is probably not what you all were expecting because it isn’t a checklist to digital transformation success. Below is a summary: ) Cloud computing is great – pick the vendor you like the most. ) Use RPA for all business processes in your accounting,

financing and adminstration departments – it’s a good thing. ) Be wary of marketing promises of ‘easy wins’ and ‘low-

hanging fruit’ – even from trusted brands. ) AI/ML is cool – make sure you understand why you are

using it and the value it will provide before paying the big bucks. ) Automate all human processes – you will need external

software and talent to accomplish this whether you like it or not. Whether you like it or not, this is the real digital transformation.

Like any effort that is meaningful, it requires work and amazing human talent. There isn’t a magic bullet, but if we keep growing and learning as the amazing industry that we are, with substantial automation we will continue to be world leaders in supplying reliable energy to the world and going forward, a significant contributor to the energy transition.

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Henry Berry, Director at UK oil company Tristone Holdings, reflects on the industry wide uses of LiDAR technology, including pipeline mapping, leak detection, survey of dangerous environments and assessment of terrain and elevation.

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he oil and gas industry, however laced with centuries of history, is often one that finds itself at the forefront of innovative technology. One such innovation is Light Detection and Ranging, or LiDAR. It is easily one of the most impressive innovations in remote sensing of the modern day, and has applications in almost every aspect of the oil and gas sector. Its primary purpose – and the main reason for its invention – was to map topography and hidden features in the Earth’s surface.

It has been proven to be extremely useful in the creation of digital elevation models. Recent developments, however, have proven it to have uses in far more areas of exploration and scientific interest.

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Aerial surveying, for example, is not a new concept.

From hot air balloons to WW2 covert missions, remote sensing has a long history. Photogeology played a big part in the oil and gas industry until the 1980s, when digital data took over. Despite storage space being limited and resolution of digital data not being completely accurate, the oil and gas industry innovated regardless, and continues to embrace innovation to this day.

How does LiDAR work?

Despite the ground-breaking steps this LiDAR has taken, the technology it relies on is surprisingly simple. If you consider that radar uses radio waves, and that sonar uses sound waves, it stands to reason that LiDAR uses light waves. A light laser rapidly fires pulses into the area which has been selected for surveillance. The pulses emitted into the ground are then reflected back and picked up by the sensor. With a simple calculation, from the time taken from emission to reflection, distances can be accurately determined and described. Due to LiDAR using so many points of light, and since the photons are so small, the visual rendering of the area is highly accurate.

Drone technology Most, if not all, drones these days are fitted with a range of sensors. From the utilisation of optical and thermal cameras to other remote sensing and LiDAR, drones are commonplace in a range of mapping activities, as they decrease time, financial costs, and man power. They also increase the quality of mapped areas, whilst allowing mapping to be conducted at any time of the day, during almost all weathers. Thanks to this, drone technology has increased the use of LiDAR in the oil and gas industry exponentially. Drones can be programmed to fly along a predetermined path, or can be flown in-situ from the ground. This means that costs can be kept at a minimum and risk is minimised.

What can we see from the air?

One great bonus of surveying sites from above is that they map with great ease. Many oil and gas deposits are located in extreme, changeable and dangerous environments. By recruiting the help of a drone fitted with LiDAR, you get all the added benefits, including the element of safety.

When you’re scouting an area for production, infrastructure or refinement, then it makes sense to understand the location as accurately as possible. Optical imagery can make it difficult to pick out terrain elements and any specific difficulties one might encounter. With LiDAR, you’re able to trust you’re getting an accurate representation of the bare-earth topography and below soil elements that you need to be aware of. We can get a range of data outputs from LiDAR surveys, including, but not limited to: hazard proximity, environmental planning, ecological spatial analysis, site design and subterranean corridor mapping.

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Enhancing production to enhance output Research has recently been conducted into the slope angle of a region and the output of oil production. Again, when using aerial imagery, such as optics, the nuances of the landscape can be lost all too easily. By using LiDAR, you’re able to find the Goldilocks Zone of a slope angle where output could be maximised. By keeping costs down in surveying, you can spend more time researching and analysing the best places for production. As we want to become cleaner with our processes in general, minimising the amount of surveys that need to be done manually will definitely be a great help.

Eco-responsibility As important and game-changing as LiDAR is to increase output, scout areas and plan infrastructure, it also has some excellent uses in times of crisis. Under the circumstances of oil spills and slicks, for example, LiDAR makes for a helpful companion to manage the disaster.

By surveying the area of the spill or slick using a drone or plane, the pulses emitted by the sensor can accurately describe the density, width, and thickness of the spill. This allows clean-up operations to be faster, and with much less loss of environmental integrity, meaning damage to wildlife is diminished, and PR nightmares can be lessened.

Expansion into other areas Aside from all the primary outputs the oil and gas industry has received from embracing LiDAR, we still have other applications for this technology. Namely, the use of mobile LiDAR mapping for engaging investors and stakeholders. Now that it’s so easy to have access to VR technology, we are able to create immersive renderings of sites for easy viewing. This technology is only improving, with the addition of LiDAR into the latest iPhone. Another use case for mobile LiDAR mapping is for training and risk assessment purposes, where new employees and contractors can undertake training in a safe environment, ultimately cutting costs and minimising risk.

One of the most important aspects of the oil and gas industry is to accurately locate the depth of subterranean petroleum outlets. Since we already have capabilities to accurately assess and estimate where formations are likely to occur with existing depth data, LiDAR will only enhance our ability, and will become commonplace in all practices around the world. Existing photo-archives have helped us get this far, and now we have a solid understanding of how to find oil, LiDAR is the natural next step for furthering our understanding.

The overall versatility of LiDAR as a technology is what makes it so appealing. Providing a detailed picture of the environment whatever the weather, at low cost, in some of the most extreme conditions, is certainly an attractive investment. With the LiDAR market expected to reach US$4 billion in worth by 2026, it’s no wonder that big oil and gas companies are turning to this technology to lead them in the right direction.

The advantages of non-metallic pipe – and where it could go next, by Igor Azevedo, Onshore Flexible Pipes, Baker Hughes.

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here are 4 023 360 km laid in the United States. Nearly 25 000 kilometres are planned in the Middle East. The world’s longest stretches for around 10 000 km over China and Central Asia. We’re talking about pipelines, and in total there’s enough of it to wrap around the equator more than eight times. Beneath our feet, and over our heads, oil, natural gas, biofuels, water, hydrogen – and occasionally even beer – is transported from production to consumption through the world’s pipelines.

Ring of steel Much of that pipe is made of steel, with polyethylene accounting for some shorter distances and low-pressure environments. And there are good reasons for sticking with steel in many cases: it is after all excellent at resisting both high temperatures and high pressures.

But steel also comes with some major associated risks. It is costly to produce, transport and install. It’s unwieldy and inflexible. And it is exceptionally energy/carbon intensive at almost every stage, from the mining of iron ore and manufacture of billets and plates, through to pipeline construction and operational maintenance, and on to end-of-life recycling and replacement.

What’s more, it corrodes, and it erodes. Not immediately, but over time, and often in unexpected or unseen spots. Maintaining safety and pipe integrity is therefore an arduous and never-ending undertaking.

Despite these problems, steel has been the default option available for most applications, through habit as well as established supply chains and industry practice. Operators have tolerated lengthy install times and the risks of onsite hot-

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work, because the only available alternative pipeline material, plastics, have not had the pressure capacity to be a viable replacement. Until now.

We have relied on steel pipelines for so long that it can be hard to imagine a feasible alternative. But there are options – for energy and industrial operations which may offer real, tangible benefits.

flow and can be designed to work for a specified life, typically 20 years, at maximum pressure and temperature without intervention – whether that’s the injection of chemical corrosion inhibitors, operational corrosion monitoring or inspection and disruptive repair work.

Cleaning up A new era The current financial, operational and political environment has made new alternatives even more important. In short, the industry is being required to cut costs and to rapidly decarbonise.

Dependence on steel when it is not necessary hinders both goals.

So, what is the new alternative? Research into novel material sciences have moved out of the lab, and into the field on the back of Baker Hughes’ commitment to revolutionise composite engineered materials for their next generation of products. The result is Baker Hughes’ reinforced, thermoplastic pipe – which is already being widely (and economically) deployed in key areas and showing a great deal of promise for even wider usage.

The pipe is a composite of selected non-metallic materials which are designed to give it strength and durability to withstand much higher temperatures and pressures than traditional polyethylene pipe over a full lifecycle, typically 20 years but the product can be designed to operate up to 50 years of duty.

That means it can be used to optimise the backbone of many flowline and pipeline networks. For example, certain designs of non-metallic pipe can now deliver fluid pressures up to 2250 PSI and temperatures up to 180˚F. These are available in 8 in. diameter which means they are fit for higher-pressure, longer-distance transport and post-processing flowline duties.

When deployed instead of steel, this technology can cut installation time in half and reduce the installed cost of the pipeline by more than 20%, and can materially impact the total CAPEX and OPEX over the asset lifetime as well as slash the asset carbon/energy footprint.

Cutting costs Several factors contribute towards these reduced costs. The first is that reinforced thermoplastic is much lighter and more flexible than steel, with individual pipeline sections available in much longer lengths on a reel.

Critically, because it is spoolable, this instantly makes it easier and cheaper to transport and install: no more welding together 40 ft steel line pipe joints over miles of difficult terrain. The other impactful outcome for customers is that it massively shortens time from project initiation to production, which is beneficial for overall project economics.

Additionally, this technology can demonstrably reduce HSE risk exposure. Hundreds of metres of non-metallic pipe can be laid without connectors or welding, which reduces construction crew size needed on the right-of-way (ROW). As the pipeline spools are pressure tested individually, it also greatly reduces the number of joints in the pipeline which in turn reduces the risk of a hydrotest anomaly.

That leads us on to maintenance budgets. Reinforced thermoplastic does not corrode – it is stable over time when exposed to a wide range of fluids, gases and chemicals. It can withstand H2S, CO2, water, sand, and contaminants in the oil or gas

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These advantages are immediately clear. What is perhaps less obvious at first is that thermoplastic pipe can reduce required land use quite substantially. Because the installation operation is relatively simple, it requires less onsite support facilities, dedicated equipment such as pipe bending machines and side-booms and fewer truck movements – that in turn reduces the pipeline ROW width that is needed, as well as associated environmental disruption, so owners can buy or lease less land.

Finally, there are the wider environmental aspects – an increasingly important issue for today’s energy and industrial sectors. Non-metallic pipe simply reduces the lifetime environmental impact of any project. In addition, it can be used to transport CO2 to carbon-storage facilities, or to move the hydrogen that will become a key component of tomorrow’s energy and industrial sectors – allowing thermoplastics to play a vital role in the conversion of existing infrastructure to carry these gases.

The research continues Our technological advances in pipe design and material composition have already produced significant results. It wasn’t that long ago that an 8 in. non-metallic pipe was, quite literally, a pipe dream. Now it’s becoming available in versatile designs with different lining types – such as nylon, Polypropylene sulfide (PPS), Polyvinylidene fluoride (PVDF) and High Density Poly Ethylene (HDPE) – and a structure which is optimised for purpose in different applications.

Research, development and innovation is continuing.

Attention is turning to manufacturing and how machine learning algorithms can be deployed to enhance our understanding of reinforced thermoplastics and improve performance across a variety of operating conditions. There are plenty of promising developments that can add greater robustness to pipe design and qualification, optimise load-bearing capabilities to fit terrain and flow characteristics, and expand the applications in which nonmetal pipe can be safely and successfully installed.

There are occasions where carrying on as before is exactly the right strategy to pursue. But this is not one of them. The energy sector, our core customer base, is at a crucial inflection point. Operators needs to reduce total expenditure over the lifetime of each of its assets to secure future investment in major project developments. It needs a positive sustainability message to attract talent and investors. And it needs to secure the social license to continue operations and developments throughout the coming period of the energy transition.

These big goals cannot be achieved by just upgrading our pipelines. But in an industry that is so dependent on them, reinforced thermoplastic pipe which are recyclable, robust and reliable can play a key role in efficient and cost-effective oilfield facilities, and will provide the backbone for the next generation of lower carbon-footprint energy developments.

Tyler Paxman, MSc, PEng, Research Engineer, and Mark Stephens, MSc, PEng, Engineering Consultant and Chief Engineer, C-FER Technologies, Canada, describe using historical data to predict liquid pipeline spill volumes.

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ithin the pipeline industry, there is a concerted push towards reducing the risks associated with the transportation of hazardous products. In the event of hydrocarbon liquid pipeline failure, major concerns are the negative effects on the environment and the socioeconomic impacts on the neighbouring population. The impacts are highly variable and depend on the type of fluid released and the locations affected by the spill; however, there is agreement that the consequences of failure increase with the amount of product released. Therefore, the ability to predict the potential volume of a spill due to a hazardous liquid release is an important consideration in assessing the risks associated with pipeline failure, and in preparing for and mitigating any detrimental effects.

Analytical models have been developed to make spill volume predictions based on pipeline and terrain characteristics. However, we wanted to address the same issue by looking at what the historical data says about the outcomes of previous pipeline failures, and to use that information to make predictions about future spills. As such, our analysis focused on examining publicly available historical failure records to determine whether correlations could be drawn between key pipeline attributes and the reported spill volumes.

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Developing a model based on historical data The records made available by the Pipeline and Hazardous Materials Safety Administration (PHMSA) were the source for our analysis. The records contain information about accidents involving hazardous liquids that have occurred in the United States.1 PHMSA requires operators to report the details of these accidents, including information about: ) The equipment that failed.

relevant. The records were then filtered to include only spill events involving: ) Low vapour pressure (LVP) liquids that stay in liquid form after a spill. ) Onshore pipelines. ) Pipe body failures (including welds or repair sleeves).

) The volume of product spilled.

) Non-zero release volumes.

) A description of the context surrounding the event.

) Nominal pipeline size (NPS) greater than 1.

We were primarily interested in the reported spill volume, along with how it correlates with the other recorded parameters, such as pipeline attributes, fluid types and the manner of failure.

Categorising the data

Selecting a relevant dataset We selected records from 2002 to 2019 to obtain a consistent dataset containing data sufficiently recent to be representative of current practices, as well as large enough to be statistically

We categorised the selected records to reflect the mode of failure, such as ruptures or leaks of varying sizes. Based on an interpretation of each incident report, including effective opening sizes, failure causes and the operator’s description of the event, we ultimately divided the data into two groups: ) Small openings (or ‘leaks’): failures with an effective opening area less than a 10 mm dia. hole. ) Large openings: any failure with a larger

opening than the ‘small openings’ category, including full ruptures.

We made this distinction based on a preliminary investigation, which revealed that spill volumes from small openings tend not to vary systematically with pipeline attributes, while volumes from large openings did.

Ultimately, from the set of all 5865 hazardous liquid releases in PHMSA’s database, 886 were found to be applicable to our assessment: 248 large openings and 638 small openings.

Fitting the data Figure 1. Spill volume vs. pipeline diameter (historical data from PHMSA and corresponding non-exceedance percentiles for large opening releases).

Figure 2. Spill volume vs. pipeline diameter (historical data from PHMSA and corresponding non-exceedance percentiles for small opening releases).

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Large openings By analysing the reported parameters in the large openings dataset, we found that spill volume is significantly correlated with pipe diameter. Other parameters did not exhibit similar levels of correlation; most notably, the specific opening size was found not to be a significant factor. Using regression analysis, we determined that spill volume was approximately proportional to the square of the pipe diameter.

This makes sense, since the spill volume is largely dependent on the drainable volume of fluid within the pipeline. Given this, and the fact that the drainable length (as affected by, for example, the elevation profile of the pipeline in the vicinity of the break point and the block valve locations) is effectively random, the spill volume is thereby proportional to the circular cross-section area or pipe diameter squared.

We defined the correlation between spill volume and pipe diameter squared by calculating a proportionality constant that caused the averages of both predicted and actual spill volumes to be equal. While this correlation expresses the mean spill volume expected for each pipe diameter, it does not give a full picture of the variability in the data. This variability is an indicator that there are other parameters at play, with information on many of these other parameters not being available in the historical incident data.

To reflect this uncertainty, we introduced a model error term. We defined this term as a random quantity defined by a statistical distribution that explicitly reflects the variability in the actual-to-predicted data. Using a least-squares fitting method, we found the set of actual versus predicted spill volume ratios to be best represented by a log-normal distribution with a mean of 1.0 and standard deviation of 2.53. This was found to be a good fit across the entire dataset, implying that, though there is a high level of uncertainty, it can be confidently characterised by including this formulation of the model error term.

The percentiles of the model error distribution correspond to the “probabilities of non-exceedance” for a spill volume estimate. This means that the model allows you to calculate the spill volume at which the probability it will not be exceeded in the event of a failure is equivalent to a chosen distribution percentile. Figure 1 shows a selection of non-exceedance percentiles for large opening spill volumes, along with the raw data points used to calculate the distribution.

Small openings Unlike releases associated with large openings, spill volumes from small openings were found to be effectively independent of pipe diameter. Therefore, we treated the spill volume itself as a random variable and calculated a best-fit distribution, which was log-normal with a mean of 31.6 m3 and standard deviation of 390 m3.

This fit was found to be generally good; however, there was a slightly weaker agreement for the very small volume estimates, which is likely the result of operators conservatively over-estimating spill volumes for very small releases.

Fortunately, the ability to estimate

the mean and upper bound spill volumes is generally of greater importance and the fit in this region is quite good.

Figure 2 shows selected spill volume percentiles for small openings, along with the raw data points used to calculate the distribution.

Comments on variability The spread of the data shown in Figures 1 and 2 is large, which makes it clear that some parameters, such as valve spacing or shutdown times, play a significant role that isn’t captured by the simple relationships that have been developed. Despite that fact, the goodness-of-fit for each of the model error distributions gives confidence that this uncertainty is generally well-described by the models.

Table 1. Selection of predicted spill volumes for small and large opening releases at various pipe sizes and percentiles Release type

5th

10th

50th

Mean*

All

0.0635

0.143

2.54

31.5

Large openings

4 / 101.6

1.19

1.98

12.1

33

10 / 273.1

6.77

11.3

69.3

188

14 / 355.6

11.5

19.2

118

320

18 / 457.2

19

31.7

194

528

24 / 609.6

33.8

56.4

346

939

30 / 762.0

52.7

88.2

540

1467

36 / 914.4

76

127

777

2113

*The mean percentiles are 87 and 76 for small and large openings, respectively.

Using the models The models developed can be used to estimate spill volumes for specified probabilities of non-exceedance. This invites the question: what are the probabilities of interest and what are the applications?

To illustrate model use, a selection of spill volumes, calculated using the models previously described, is shown in Table 1, corresponding to various exceedance percentiles and pipe sizes. A description of how they can be applied in useful ways is provided below.

The ‘expected’ spill volume In some applications, such as in the case of a risk assessment, the expected spill volume may be of primary interest. In such circumstances, the mean of the fitted distributions in each model can provide credible estimates of the size of the release expected from a given pipeline for a given failure mode. The expected values for large openings vary with diameter.

For example, a large opening failure in a pipeline with a nominal pipe size (NPS) of 10 in. has an expected spill volume of 188 m3, while that of an NPS 24 pipeline is 939 m3. On the other hand, as previously noted, spills resulting from small opening failures have been found to be effectively diameterindependent and a spill volume of 31.6 m3 can be expected on average, regardless of the size of pipe involved.

Unlike with a standard normal distribution, the mean value is not the same as the 50th percentile, since the models are based on skewed log-normal distributions. For example, even though 50% of the large opening releases from an NPS 24 pipeline are expected to have a volume less than 346 m3, the mean release volume of 939 m3 is the preferred estimate where the expected value is of interest.

Worst-case spill volumes Where the worst-case scenario for pipeline spills are of most interest, the release volumes associated with high probabilities of non-exceedance provide credible bounding release volume estimates.

For example, it is predicted that 95% of all spills from an NPS 24 pipeline will not exceed 3537 m3, based on the prediction calculated for the 95th percentile.

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Another application use of this model is to gain an understanding 90th 95th of the range of potential spill 45.1 102 volumes. This is particularly relevant in emergency response 74.4 124 planning, where the ability to 425 710 prepare for both the most likely 720 1204 and the most extreme events is 1190 1990 important.

2116 3537 For example, if you were 3306 5527 interested in knowing the range 4761 7958 of potential spill volumes within which 90% of the spill volumes are likely to occur, you can calculate the lower and upper bounds of the range by using the 5% and 95% non-exceedance levels, respectively. For small opening releases, the range is 0.06 to 102 m3. For large openings, the range depends on diameter.

For a smaller pipe, such as NPS 4, that same range is 1.19 to 124 m3, while a larger NPS 36 pipe has a likely spill volume range of 76 to 7958 m3.

Predicted release volume at a given percentile (m3)

NPS / OD mm

Small openings

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A range of likely spill volumes

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Conclusion By analysing PHMSA’s public dataset of historical liquid pipeline failures, we developed correlations that provide credible spill volume predictions as a function of pipeline diameter and failure mode. We found that release volumes for large openings are a function of the pipeline diameter, with larger diameter pipelines typically spilling more, while releases resulting from small openings were found to be largely independent of pipe diameter. The model as developed provides the means to calculate expected release volumes and the likely range of volumes for a given spill.

Given that spill volumes are a primary consideration when assessing the environmental impact severity of a hydrocarbon liquid release, these simple release volume estimation models are useful for benchmarking exercises where the goal is to estimate expected or most-likely release volumes; for calibrating and/or validating more complex, pipeline-specific release volume estimation models; and for estimating credible worst-case release volumes for emergency response planning purposes.

Note This article is a description of findings reported in greater detail in PAXMAN T, and STEPHENS M., (2020), ‘Analysis of hazardous liquid pipeline spill volumes. Proceedings of the ASME 2020 13th International Pipeline Conference’; 28 September - 2 October, Calgary. New York (NY): American Society of Mechanical Engineers. IPC2020-9155.

References 1.

PHMSA – Distribution, Transmission & Gathering, LNG, and Liquid Accident and Incident Data [updated 6 April 2020]. https://www.phmsa.dot.gov/ sites/phmsa.dot.gov/files/data_statistics/pipeline/accident_hazardous_ liquid_jan2002_dec2009.zip. https://www.phmsa.dot.gov/sites/phmsa. dot.gov/files/data_statistics/pipeline/accident_hazardous_liquid_ jan2010_present.zip

Digital technologies, underpinned by dedicated, high-speed fibre optic communications, can offer pipeline operators multiple efficiencies, as Nigel Greatorex of ABB explains.

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he advent of the ‘digital pipeline’ is welldocumented, but a commonly accepted definition is less easy to come by. Does it mean, for instance, using more data to identify corrosion or leaks faster? Or using models to plan for future needs and carry out more effective asset performance management? Perhaps it is employing smarter, faster applications to inform better business decisions?

The answer is all of these and more. Digitalisation is a huge umbrella, covering everything from pipeline modelling, simulating compressors and pump stations to augmented operations. These innovations and others like them have a common thread, in that they are all enabled by secure, highspeed, high-availability communications.

Fibre optic communications Pipelines, like so many other aspects of modern process industry infrastructure, are increasingly underpinned by dedicated fibre optic backbones that offer operators

unprecedented visualisation along the whole network, as well as real-time control in the form of data available instantaneously from single, often remote, control centres.

Efficient, secure communications enable predictive (and increasingly prescriptive) as opposed to reactive maintenance and advanced status monitoring of corrosion and system anomalies. Using the fibre as a sensor in conjunction with an internal leak detection system (LDS), can also provide a ‘belt and braces’ approach to leak detection.

The deployment of a single integrated control and safety system (ICSS) spanning many thousands of kilometres is also a compelling alternative to a SCADA system with separate ICSS at main stations and remote terminal units (RTUs) at block valve sites.

Fibre communications also facilitate the transfer of data from operational technology, information technology and engineering technology domains to the ‘Edges’ (of which more later), allowing operators to take advantage of a range of opportunities around new applications and cloud storage.

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Digitising pipeline security Depending on the region they traverse, pipeline projects may now come with a high security requirement. Here again, fibre communications are employed to provide comprehensive end-toend security for every site and the pipeline itself, mitigating the threat posed by the theft of product or pipeline sabotage.

Distributed acoustic sensing (DAS) systems utilising fibre cores can be used to detect potential intrusions. CCTV cameras are able to monitor every pipeline site and can be backed up by drones that validate if there has been a security event, or even a leak, before deploying physical security on-site.

Pipelines have traditionally been implemented with separate SCADA, the ICSS’ and the RTUs; however, an integrated approach to control systems utilising a single fully integrated control system is currently finding favour in the market.

ABB manages the electrical, automation, telecoms and security risk, testing the various integrated systems before delivery to site. Pulling together these technology solutions in a solid, risk-free management proposition constitutes a major value offering on pipeline projects, allowing operators to work safely, securely and efficiently in the countries where they operate.

Leak detection Leak detection is a fundamental aspect of pipeline operations and digital and automated solutions can support operators in this vital task. The ABB AbilityTM Pipeline Control systems platform includes interfaces to the LDS that take pressure and flow data.

Where fibre is available, ABB also provides as part of their typical scope, distributed temperature sensing (DTS) or distributed acoustic/vibration sensing (DAS/DVS) technologies to augment LDS further.

With fibre facilitating the communications for internal LDS systems, and also acting as a sensor for DAS/DVS/DTS, facilitating and collating the output from these complementing systems is a task suited to the digital environment. Artificial intelligence (AI) can potentially be used to tune and calibrate LDS and intrusion detection systems (IDS), enabling them to better discriminate between the various types of events they need to alert against or filter out.

Case studies: QC LNG and TANAP ABB has proven expertise delivering on large-scale export and trunk pipelines worldwide as well as distribution networks and smaller pipelines, particularly in India and Middle East. These projects have varying levels of complexity, requiring robust safety and security systems.

QC LNG For the Queensland Curtis Liquefied Natural Gas project in Australia, ABB was able to engage early with the client and work on the FEED study in collaboration with the EPC contractor, providing a full telecoms and security system suite. Upstream assets include thousands of wellheads controlled via radio links and an ABB fibre optic communications backbone stretching along the entire gas gathering and trunk pipeline infrastructure.

The main backbone fibre optic communications were backed up via a microwave backbone, with a public network link to Brisbane, where the operator can monitor the whole field infrastructure from their corporate offices. The client controls

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the whole gas-gathering and transmission infrastructure from two main control centres powered by the ABB Ability System 800xA distributed control system.

TANAP TANAP, the Trans Anatolian Pipeline, which interconnects with the South Caucasus Pipeline (SCP) at Turkey’s border with Georgia and the Trans Adriatic pipeline (TAP) at its border with Greece, is much larger in scope and scale, but again the telecoms, security and ABB Ability System 800xA SCADA systems are all provided by ABB as part of their overall TSC, telecoms and SCADA contractor scope.

Three fibre optic cables installed by ABB run along the full length of the 1800 km pipeline, and not just for the purpose of communication; they also facilitate a distributed acoustic sensing (DAS) system for leak and intruder detection. All manned and unmanned sites along the TANAP pipeline feature a heavy camera presence for security. The IDS system is integrated with the camera system, allowing the operator to automatically position CCTV to detect fence line events, with varied fibre included.

One of the biggest challenges and risks of such projects is that supplementary interfacing systems don’t work when they are initially plugged into the communications backbone. ABB helped the customer manage this risk by conducting full integrated factory acceptance testing on all the critical communications and hosted systems before they arrived on site.

Operating at The Edge The increasing adoption of digital applications for safer and smarter operations is enabled by the development and deployment of new architectures and tool sets.

One of these tools, ‘The Edge’, refers to a device that gathers data not required immediately for pipeline operation in segregated secure nodes. Edge devices such as ABB’s Edgenius can also run applications to sort and analyse the data they gather, or for larger applications, interface to any cloud infrastructure with the option of an ABB-provided cloud.

The Edge device collects data from field devices, gateways and programmable logic controllers in OT systems, converts the various field protocols into one standard communication protocol, and then makes it available to all project stakeholders in a secure, centralised location. At its most basic level, using the Edge in this way enables asset monitoring for smart instrumentation to be taken away from the SCADA, and negates the need for multiple disparate nodes hosting numerous functions.

However, with evolving digital platforms such as ABB’s Genix Industrial Analytics Suite, the Edge can be further utilised to help operators cherry pick granular data on rotating equipment fatigue, for example, and use it to make better business decisions leading to prescriptive maintenance.

Larger applications with many Edges, gathering data from many sites and the OT, IT and ET domains require more data storage and processing. This capacity is provided in a cloud environment. ABB’s Genix solution gathers, sorts and utilises OT, ET and IT data in the cloud, providing operational analysis tools including artificial intelligence and machine learning, delivering useful information for the overall pipeline operation including KPIs and useful information from the site level through to the

boardroom. Oil and gas companies often like to have their own cloud infrastructure, and the ABB Genix platform can be hosted wherever suits the operator.

The rise of the smart worker Protecting workers by removing them from risky environments is a key early design factor. When an employee does have to be sent to a remote pipeline site to rectify a fault or perform standard maintenance, it is vital that they have access to every single piece of information they need in order to perform their tasks.

The new ‘smart worker’ has all that information on his or her smartphone or mobile device, without needing to tap into the SCADA system. ‘Prescriptive’ maintenance is a step beyond ‘preventative’ maintenance whereby operators not only know which equipment is not performing optimally and when it may fail, but also ‘why’ there is an issue; identifying an issue in advance and knowing what to do maximises ‘tool time’ effectiveness.

All of this may sound obvious, but often there is still no 4G network or other communications coverage around many oil and gas pipelines. Radio coverage may be suitable for stranded sites.

Microwave is powerful when there is a line-of-sight between sites; a very-small-aperture terminal (VSAT) can be useful as a back-up – but where fibre optics infrastructure is available it can be securely tapped, enabling beneficial radio coverage at all pipeline sites where there are no other options.

Augmented operations and autonomous operations are key trends playing out across the pipeline industry. Augmented operations enable field workers to perform a wider variety of tasks, with non-expert workers given instant decision support with AI.

The value of specialist knowledge The advent of digital tool sets and enablers such as ABB Edgenius and Genix combined with suitable communications such as fibre, mean gathering data is no longer a challenge for pipeline companies.

However, the skillset to develop these tools or apps is key to success and operators need to remember that the digital revolution still requires skilled people.

Much of the equipment deployed on large-scale pipeline infrastructure projects is supplied by third party vendors; where technology providers and integrators really add value is in project execution informed by specialist domain knowledge. ABB removes a significant amount of risk from large, complex pipeline projects, delivering fully tested integrated solutions and supporting the operator for the full lifecycle.

Future trends around digital pipelines will inevitably involve improving safety, reducing carbon emissions and overall energy optimisation. Pipeline operators are already talking about carbon neutrality or offsetting CO2 emissions from pump and compressor stations. ABB can help them optimise nominations, offtakes and flowrates to the performance of the pump or compressor using solutions such as ABB OPTIMAX. This is a great example of where digital technologies can be used to address specific industry challenges and improve operations, especially on brownfield sites.

No one understands pipelines better than the operators themselves. Through collaborative working with specialist technology companies, the new generation of digital and automated tools can be utilised for safer, more secure and, ultimately, more productive operations.

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F Pedro Barbosa, Industry Sector Manager - Pipelines, at Fotech, a bp Launchpad company, explores how advanced distributed acoustic sensing technology is helping pipeline operators to protect their assets in extreme terrains.

or pipelines in the most extreme and inaccessible locations – whether that is in jungles, deserts or mountains – providing continuous 24/7 monitoring of the entire pipeline using traditional measures is extremely challenging. However, this monitoring is vital for oil and gas pipeline operators who are under increased pressure to make cost savings while simultaneously reducing risk across their networks. By ensuring pipeline security and gaining full visibility in remote and difficult-to-access areas, operators can protect their assets as well as the integrity of the pipeline networks to minimise product loss.

Statistically, product loss has been mainly caused by pipeline failure – ruptures and leaks caused by corrosion, mechanical damage, etc – or by theft-related events. Failure to monitor against these threats adequately can easily cost an operator millions in lost fuel from leakages and stolen product. Leaks also pose the risk of, and the cost associated with, environmental damage to the surrounding area.

In the last decade there have been an average of 675 reported integrity incidents per year in North America alone, with an associated average annual cost of more than US$300 million. Indeed, two incidents, each originating from small orifices, resulted in leaks that went undetected for days; more than two million litres of product seeped into the environment. The costs associated with product loss at that volume are estimated to be approximately US$1 million, with the final clean-up costs estimated to have been significantly higher – in the region of US$100 million in each case.1 Theft of product from hot-tapping, whereby organised criminal gangs seek to tap into the pipe to syphon fuel to tanks, is also a key issue worldwide. Many regions in the Middle East, Africa and Latin America are home to some of the most remote pipelines globally – located in the heart of extremely inhospitable deserts and forests.

Major pipelines such as the East-West Cruel Oil Pipeline, which is a 1200 km pipeline that transports five million bpd of crude oil from the Abqaiq oil field on the Persian Gulf Coast to the Red Sea, have been specifically targeted in attacks.2 Problems with pipeline protection are not unique to the Middle East, though. There have been similar cases in South Africa, South America, the US, India and Mexico, among others.

A need for speed Historically, monitoring for leaks has been achieved using internal based systems, such as mass balance and real time transient modelling (RTTM). However, these systems infer the presence of a leak by computing different operational conditions using computational pipeline monitoring (CPM) based systems and, as such, tend to have long detectability times and very low sensitivity

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to small leaks. As a result, leaks are often overseen or alarms are raised when large quantities of product have already been lost.

In contrast, external based systems such as fibre optic sensing take direct measurements of different response dynamics associated with the leak, such as the noise produced by the orifice leak. This provides a quicker detection of smaller amounts of product.

Right-of-way surveillance for theft detection is also very difficult in remote locations under extreme conditions. Line walkers and aerial surveillance can be useful, but they don’t provide continuous detection of events. As a result, large sections of pipeline in remote locations might be entirely unmonitored and extremely vulnerable to accidental damage or even criminal threats for large periods of time.

There is a pressing need for a continuous monitoring solution – especially in extreme terrains – that enables operators to detect theft attempts and leaks accurately and quickly, supporting the pipeline operator in its efforts for product loss prevention.

In North America there is a common requirement to detect a leak equivalent to 1% of the flowrate of the pipeline. In a pipeline transporting 100 000 bpd of oil, that 1% equates to 1000 barrels.

If it takes just six hours to identify a leak, 250 barrels will have escaped.

If the leak is in an extremely isolated location, it could be many days before an operator is aware, and by the time anyone arrives on the scene, hundreds of barrels will have been lost. If criminal activity was at play, the offenders will be long gone. This is especially challenging deep in the jungle where supporting monitoring technology of helicopters and drones will not be able to operate easily or to see through a thick tree canopy.

So, speed is of the essence for operators seeking to protect their pipelines and their contents. Pipeline intrusion detection systems (PIDS) using advanced sensing technologies play a key role here.

Distributed acoustic sensing as the answer One technology that is able to monitor pipelines accurately for both leak detection and disturbances relating to attempted theft is distributed acoustic sensing (DAS). Fotech’s LivePIPE II solution uses photonic sensing DAS technology that essentially turns a fibre optic cable running alongside a pipeline network into thousands of vibration sensors, able to detect any disturbances along the length of the pipeline.

The technology sends thousands of pulses of light along the fibre optic cable every second and monitors the fine pattern of light reflected back. When acoustic or vibrational energy – such as that created by a leak or by digging – creates a strain on the optical fibre, this changes the reflected light pattern. By using advanced algorithms and processing techniques, DAS analyses these changes to identify and categorise any disturbance. Each type of disturbance has its own signature and the technology can tell an operator, in real time, what happened, exactly where it happened and when it happened.

around the pipeline in real time. DAS is able to detect vibrations caused by liquid being forced through a pipeline rupture, or by ground displacement associated with small leaks in pipelines that would otherwise remain undetected.

If the source of a leak is a tiny orifice, it could easily remain undetected or it could take days for the location of an incident to be identified with existing CPM systems. In the time it would take to locate such a leak, many millions of barrels worth of oil could have been lost. DAS has proven that it can detect leaks as small as 20 l/min, raising the alarm in just 90 seconds, by which time only 30 litres will have escaped. This speed is an improvement by a significant order of magnitude to existing technology. DAS can identify oil and gas leaks from many different sized orifices, even as small as 1 mm.

A smart way to enhance security Fotech’s LivePIPE technology has been proven in the depths of the South American jungle. During the site acceptance test of a LivePIPE solution on a pipeline prone to hot tapping and theft, an unexpected signal was detected at a location in the rainforest.

The pipeline operator initially considered it a false alarm, due to the remote position of the section of pipeline. However, Fotech’s engineers insisted that a visit should be made to the site as the detected vibrations had all the characteristics of human activity.

At the site, a seismic team were discovered drilling holes in the ground ready for explosives, as part of their exploration activities.

Their GPS navigation had malfunctioned and taken them a significant distance away from their intended location. Through the intervention, directed by the LivePIPE technology, the drilling was stopped and subsequent detonation of explosives close to the pipeline prevented – averting what would have been a very serious incident.

Effectively monitoring network integrity Pipeline integrity is one of the biggest priorities for pipeline operators due to the significant environmental damage and vast costs that can result from incidents – whether accidental leakage or malicious theft. However, monitoring in remote and extreme terrains has been a challenge for existing technologies.

DAS-based PIDS such as LivePIPE II are becoming an essential part of pipeline safety and security strategies worldwide as these systems help operators to protect their assets effectively against product loss.

By gaining real-time visibility of the integrity of their entire pipeline network and across all terrains, operators are able to protect their bottom-lines while also reducing risk.

Thanks to its continuous monitoring, DAS provides a vital layer of additional intelligence, able to detect and pinpoint the location of multiple threats simultaneously, such as small leaks and third-party interferences. This technology can also work together with existing monitoring measures to complement them, rather than to replace them. By combining information gathered from multiple monitoring and maintenance sensors into an overarching view, only then can operators have a detailed understanding of what is happening on the pipeline at any given moment, and they can respond with confidence to any events before they become major incidents.

Accurate leak detection LivePIPE II technology effectively provides an invisible smart barrier along the entire length of the pipeline, which can accurately detect and alarm leaks of different sizes and their position along and

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References 1.

2.

https://www.fotech.com/media/1520/fotech-technical-paper-pipeline-integritymonitoring.pdf https://en.wikipedia.org/wiki/East–West_Crude_Oil_Pipeline

Peter Weaver, Orbital Sidekick, USA, explains how the company’s first satellite-based hyperspectral scanner can be utilised for pipeline monitoring and leak detection, to ensure compliance.

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oday we are living in what has been described as the Fourth Industrial Revolution, or the Experience Era. A defining characteristic of the time is the extensive automation of most aspects of civilised life, including widespread interconnectedness, machine learning and a rapidly expanding Internet of Things. One development that is integral with the Experience Era is the evolution of customised access to space, now providing a means for communications not only between people but between machines.

One driver behind the rapid expansion of this space marketplace is a pursuit of improved asset stewardship. Orbital Sidekick (OSK) seeks to redefine the way pipeline operators conduct routine monitoring of their assets, initially as a substantially improved method for meeting DOT’s PHMSA pipeline monitoring requirements.

In June 2021, OSK is scheduled to deploy its first proprietary microsatellite outfitted with a hyperspectral sensor. Known as Aurora, this satellite imager will collect hyperspectral data cubes over targeted energy production and distribution assets. However, the real value of OSK’s monitoring service is the analysis of this data once collected, looking for anomalies, focusing initially on conditions of particular interest to pipeline operators. These include: ) Detection of hydrocarbon leaks, spills and emissions, above and below ground. ) Identification of physical threats to pipeline assets from ongoing or recent digging and construction

activity. ) Vegetative distresses that could be traced to pipeline activity.

The objective for OSK in building its initial satellite network is to provide pipeliners with unparalleled daily global pipeline leak prevention, detection and speciation, intrusion and change detection capabilities. In short order, it will begin to replace conventional DOT pipeline patrol for compliance, and will rapidly replace aerial operations as the preferred method for pipeline patrol with satellite monitoring and reporting.

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Hyperspectral Imagery (HSI) Satellite-based hyperspectral imaging is not a new technology.

It has been in practice since before the early 1980s, but has been

Figure 1. Collection of satellite-based HSI library profiles for standard vegetative features.2

limited to first world governments and military superpowers.

Historically, satellite-based hyperspectral imaging (HSI) has been exceptionally expensive to deploy, highly data intensive, and exceedingly cumbersome to work with. It is only now that Moore’s Law has seen computing capabilities begin to catch up with the technology’s promise.1 As a passive sensing technology, HSI data are generated line-by-line, a recording strategy often referred to in remote sensing as ‘push broom sensing’, rather than captured as a frame as traditionally done with common cameras. Hyperspectral scanners constantly collect as many as hundreds of reflected light signals, each centered around a different wavelength, ranging anywhere from the visible (RGB) to the near infrared (NIR), and in many cases also shortwave infrared (SWIR).

These numerous bands offer greater insights into the surface characteristics of the world under observation than what other modes of sensing, including common RGB imaging, can provide.

Every HSI pixel represents a position on the earth’s surface.

For all pixels along a flight path, a reflectance value for each spectral band is recorded in a data stack (Figure 1). For any given image pixel, the resulting spectral bands may be plotted to depict the characteristics of the surface according to the resulting reflectance values from each wavelength band across the spectrum. For any pixel captured, the spectral data could correspond to samples of soil, water, vegetation and others. As knowledge of surface characteristics is accumulated and consistently correlated to resulting characteristics of hyperspectral profiles, libraries are developed to catalogue surface features and allow digital characterisation of the world around us. To date, publicly available spectral libraries are focused on minerals and soils, agricultural and vegetative features, man-made objects and materials (such as roofing and steel), water and certain liquids, and select chemical compounds. Figure 2, for example, includes standard agricultural features for several common species.

Figure 2. Library profiles for standard vegetative features.4

OSK’s HSI imaging constellation

Figure 3. RBG image of natural gas pipeline manifold.

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Founded in 2016 as the brainchild of Dan Katz and Tushar Prabhakar, Orbital Sidekick began with an idea on a napkin, with the first imaging prototype being built in Dan’s garage soon thereafter. By 2018, OSK had placed its first sensor on a rocket bound for the International Space Station. This Hyperspectral Earth Imaging System Trial (HEIST) continued through 2019 and resulted in the collection of over 50 million km2 across the globe. This system could collect approximately 100 bands in the visible to near infrared region of the spectrum (0.4 – 1 micrometers). In doing so, it allowed the company to prove its ability to collect, process, and more importantly analyse and derive insights from their own spacebased hyperspectral data cubes.

Now at the start of 2021, OSK’s next satellite, named Aurora, is a second generation (Gen II) imager collecting over 400 bands of data in the visible to short-wave infrared regions of the spectrum (0.4 – 2.5 micrometer). Aurora is awaiting imminent launch into orbit from Cape Canaveral in June, and it will traverse the globe in a sun-synchronous pattern allowing data to be collected over any location on earth on a weekly or more frequent basis. With a pixel size of 30 m, Aurora will conduct low spatial resolution patrol over pipeline and energy assets while being utilised to further develop

and refine OSK’s suite of analytical capabilities, known collectively as Spectral IntelligenceTM. During 2022, OSK will next, in quick succession launch its full constellation of third generation (Gen III) satellites. This constellation, named GHOSt, will collect data with an 8 m pixel size. Once operable, GHOSt will be able to offer – as frequently as daily – hyperspectral data collection and analysis over any asset on the globe, to include actionable reporting on hydrocarbon leaks, encroachment, change detection and other anomalies, all for the approximate price of visual aerial patrol.

Pilot programme findings During recent months and years, OSK has been developing its analytical skills through analysis of data more easily obtained using a handheld sensor, small aircraft, and an aerial drone. From this work, four sample findings follow:

Underground natural gas leak and soil disturbance In a routine aerial patrol over a 100 mile underground natural gas pipeline, a very small gas leak was located due to the disturbance at the surface caused by the seeping methane. A colour (RGB) image of the manifold is shown in Figure 3, with the encircled area indicating the location of the previously unidentified anomaly.

A hyperspectral presentation of the soil anomaly is shown to the left in Figure 4. The area encircled in red indicates a soil anomaly, resulting from a hydrocarbon leak. Further investigation revealed a small, 0.5 in. corrosion leak at this location on a 10 in. pipeline buried four feet below grade.

Figure 4. HSI images of gas pipeline manifold leak.

Detecting an aboveground crude storage tank leak Another example of a spill, not apparent to the human eye, but detected by HSI, is shown in Figure 5. This small gathering tank battery is located among a crude gathering system in West Texas.

Using no assistive technology, the aerial patrol pilot failed to detect anything abnormal. In presenting imagery to the client, OSK was informed that a tank had failed the prior week, saturating the surrounding soil with light crude. No standing product remained, but the operator sought to test whether an HSI patrol would identify the contamination – which it did.

Satellite detection of oil tank rupture In the next example, Figure 6 indicates positive identification of the South Riding Point terminal leak on Grand Bahama caused

by Hurricane Dorian’s landfall during September 2019. The true colour image shows a fan of darkened soil at the surface that could indicate hydrocarbon, a shadow, or natural geologic feature.

Hyperspectral analysis gives a much clearer indication of spilled hydrocarbon than of shadow or geologic features. Given the tremendous forces acting upon the environment during a hurricane, the surrounding soil anomaly was likely the result of inundation by storm surge. This image was collected by OSK’s HEIST asset just two days after the storm passed over the facility.

Analytical methane detection In a final example, the data analysed by OSK was obtained using publicly available hyperspectral data collected by NASA over a major known natural gas leak just north of Los Angeles in 2015.

Using these data from the public domain, OSK analytical processes

Figure 5. Aerial HSI of aboveground crude leak.

were able to positively identify the large methane plume widely reported at this location.

As depicted in Figure 8, the centre image is an RGB presentation of the AVIRIS collection. In the frame on the right, OSK applied a standard methane index which calculates, pixel-by-pixel, a specific ratio of two prominent reflectance values characteristic to methane. This index reveals the plume for this emission source, white over orange as a false-colour representation. Other features, however, are also indicated in this frame in white, meaning this index alone is not sufficiently able to positively identify methane.

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The image on the left shows OSK’s application of additional algorithms1 - including a known hyperspectral methane profile – allowing the plume to be more reliably identified. Each of these images are from the same HSI data stack.

This exercise in finding a natural gas leak illustrates how it is possible to utilise HSI to tease out and identify specific features of particular interest, in this case seeking methane signatures.

way with findings of fully-analysed, satellite-derived anomalies, including identification of changes over time, as they are identified. SIGMATM v. 2.0 will soon be released to support OSK’s launch of its Aurora satellite.

Delivery mechanisms of processed information in such a manner will materially change the utility of imagery from merely a vast accumulation of bulk data requiring client processing, management and analysis, into a storehouse of actionable The client perspective intelligence whereby decisions can be made on prioritised Ultimately, the most sophisticated analysis in the world is of deployment of limited resources. This information delivery little use to the client if they cannot access and utilise it in an element will be how we move the needle, using satellite-based effective manner, and OSK is already working on an updated hyperspectral imagery, for improved pipeline integrity, asset second version of its client reporting interface, known as SIGMATM protection and public safety.

(Spectral Intelligence Global Monitoring ApplicationTM).

Orbital Sidekick is one of a growing number of companies As illustrated in Figure 7, a beta version of SIGMATM is now that seek to provide improved intelligent solutions for being used to integrate graphical depiction of client rights of compliance, leak prevention and detection including remote product speciation. The future holds great promise in this field of imaging for oil and gas. Safer and more environmentally conservative energy production will be the result once the full promise of tailored HSI collection, analysis and reporting is brought to bear on the market.

Back in 2018, OSK proposed that within five years, pipeline operators would look back on their routine aerial patrol activities for PHMSA compliance with a sense of nostalgia. If true, we’re Figure 6. Heist image South Riding Point, Bahamas fuel spill, September 2019. only two to three years from witnessing a seismic industry shift in how regular monitoring services are delivered.

References

Figure 7. Reporting of findings via SIGMATM.

Figure 8. OSK analysis of NASA AVIRIS data over Aliso Canyon, CA.

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1. Moore’s Law refers to Moore’s theory, formulated by Intel co-founder Gordon Moore in 1965, that the number of transistors on a microchip doubles every two years, though the cost of computers is halved. Moore’s Law states that we can expect the speed and capability of our computers to increase every couple of years, and we will pay less for them. Another tenet of Moore’s Law asserts that this growth is exponential. At present, the doubling of installed transistors on silicon chips occurs closer to every 18 months instead of every two years, though some experts assert that computers should reach the physical limits of Moore’s Law at some point later in the 2020s.

2. https://www.harris.com/perspectives/global-situationalawareness/hyperspectral-imaging-an-emerging-tool-for-mission 3. https://www.usgs.gov/labs/spec-lab/capabilities/spectral-library 4. GOVENDER, M., CHETTY, K., and BULCOCK, H., ‘A review of hyperspectral remote sensing and its application in vegetation and water resource studies’ (2007).

Richard Ryan, Dräger Marine and Offshore, and Dräger Hire, discusses the big decision facing businesses when it comes to safety equipment for pipeline shutdowns.

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he past 12 months have been undeniably challenging for the oil, gas and wider offshore industries. Clearly there has been a financial impact for the great majority but day-to-day operations have also been severely tested, which given the hazardous environments in question, has been challenging for those operating in this sector.

Social distancing, mandatory face coverings and reduced workforces due to furloughing have all had a significant impact on safety and on the effectiveness of people working together. Furthermore, putting employees on furlough has created a challenge for companies maintaining current training on new safety equipment.

Clearly investment in safety equipment is a fundamental expenditure for any business, but it is essential in the oil and gas sector to secure the wellbeing of the business and its employees. This is particularly true for unusual ‘peak’ activity periods such as pipeline shutdowns, where there is risk of fire and explosion associated with loss of containment of gas or volatile fluids carried within the pipelines during maintenance activity.

It may not be immediately apparent how reconsidering the way that a business procures its safety equipment can impact this, but with the growing popularity of hiring equipment rather than buying, we consider what difference this can make to those contracted to manage the maintenance of pipelines.

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Economics Historically, safety equipment has been purchased outright, allowing companies to own their own safety kits and to manage the calibration and maintenance. Many of these companies may have leased vehicles and will recognise the cash flow benefits of doing so, but will not necessarily have considered that this could be an option for other capital items, including safety equipment. However, the introduction of more flexible acquisition methods mean that this is now a more widely available option.

As with leasing vehicles, using hire vs buy has a range of economic benefits, namely that it gives more control over cashflow, particularly in times of business uncertainty, and preserves working capital. This is particularly important at a time when greater flexibility and access to cash is likely to have significance.

There will be instances where safety equipment is only needed for a fixed term, perhaps for a specific project, such as a pipeline maintenance contract. In these instances, hiring the equipment for the duration of the project can reduce the total cost of using the kit, as well as help in accurately costing the project.

When it comes to doing the maths, you only have to consider an item such as a benzene detector.

Ensuring that safety protocols are met is a fundamental part of any project but minimising employees’ exposure to harmful gases and substances, such as benzene vapours, which are associated with a range of acute and long-term adverse health effects and diseases including cancer and haematological effects, is essential within the oil and gas industry.

During the Forties shutdown this May, measuring benzene levels will be critical. However, with detectors costing upwards of £25 000, this is a high-investment item which may potentially only be needed for a relatively short period of time. Renting this item will cost approximately £450 per week, so if it is used for two weeks a year, it’s easy to recognise how much more cost effective this is, adding to the economic case for renting.

Another increasingly important safety issue is impairment in the workplace. The use of alcohol and drugs, and also

Figure 1. Benzene detector 9500 probe in operation.

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prescription medicines, is becoming more commonplace and has an impact on employers’ performance and general levels of concentration, potentially putting themselves and their work colleagues at risk. We are aware that many companies own drug tests but these are often only used for a limited period of time. The kits come out of the cupboard for a few weeks, and then require maintenance before being shelved for the following year. However, it is possible to hire these tests for the period of time they are needed.

This may be more significant as staff return to work after furlough or contractors are hired for shutdown periods.

We’ve heard much about mental health issues caused by the anxiety of living through a pandemic and staff being put on prescribed medication – prescriptions of this type of medication are believed to be up by nearly a third on pre-pandemic levels. As a result, impairment testing may be an aspect of safety management that companies are considering as we emerge from lockdown, particularly for those involved in the safety critical tasks required during pipeline maintenance.

Operational and training aspects As we’re all aware, technology doesn’t stand still and keeping up with the latest and most effective devices can be a challenge, even for cash rich companies. Another fundamental benefit of hiring vs buying is that while a company’s own equipment will date, using rental equipment provides access to the latest models and means that it is also often possible to access higher specification kit.

Each year a new model will be available, so coming back to our benzene detector example, by renting this relatively high-cost item when it is needed, a business also benefits from securing the use of the very latest technology to test gas levels, rather than using an item until it literally falls apart in order to justify the purchase cost.

Some may question how accessible rental equipment is.

After all, you are relying on a third party to supply essential equipment rather simply going to your storeroom. However, particularly when hiring from a manufacturer, access to the equipment is almost immediate. With many companies holding considerable fleets of equipment available for rent, delivery can often be much faster – in some cases 24 hours – than if a company purchased the same product outright.

So, by accessing safety equipment to meet business needs, renting allows companies in the sector to be more flexible, nimble and responsive to their safety needs.

In addition to having access to the latest models, this newer equipment is often less complex and easier to use.

This dramatically reduces the training requirements, a factor which is particularly significant as staff who may have been on furlough for several months are brought back for already delayed pipeline maintenance, or new staff appointments are made, particularly if this involves temporary contractors.

These staff need to get up to speed quickly, something which is made easier when using newer models of safety equipment which are likely to offer advances in user interface technology, and training on their operation can often be carried out easily and quickly online.

Maintenance When it comes to maintenance, calibration and testing of equipment, this can be very labour intensive and take up valuable resources. As alluded to earlier in this article, many businesses will already identify with leasing vehicles and outsourcing the maintenance of these vehicles. The maintenance of safety equipment can be viewed in the same way, particularly when some of this kit will only be used for a limited time but has to be serviced and recalibrated every time.

If you rent equipment, it usually arrives fully serviced and calibrated to ensure that detectors provide accurate readings: in other words, ready to be used immediately. As a result, your internal team can focus on the job in hand, undertaking critical tasks to complete pipeline maintenance rather than getting involved in the distraction of maintaining safety equipment.

Because rental equipment comes ready to use, this also minimises the chance of inconvenient equipment failure which can lead to expensive delays in the overall project, a critical and important element when there is a limited time to complete maintenance projects without a significant knock-on effect.

Forties shutdown We’ve made reference to the Forties shutdown throughout this article, but it is a good example of an event where renting safety equipment offers benefits.

One company which has rented a large volume of kit specifically for the shutdown commented: “The amount of

equipment we need for the pipeline shutdown is more than we’ve ever planned to use before. Economically it makes sense to utilise all of our own stock and then hire in additional equipment which we know is well maintained and ready to use.

“We’ve found hiring to be really easy and we know if we need any more equipment once the shutdown is underway we can get it by making one phone call.”

In addition, many SMEs are involved in a pipeline shutdown, but these businesses often don’t have access to large cash reserves and, as purchasing safety equipment involves an appreciable lump sum, this is a significant investment for these businesses.

There have already been contractors appointed for the Forties shutdown but there is a very real risk that there will be a shortage of people and equipment to manage the process.

The extent of the work required is much bigger than the scope for the delayed 2020 shutdown, because of the 12 month time lapse, but by encouraging businesses to plan ahead and to cost out projects using rental costs, more SMEs will be in a position to offer their services, and this will benefit not just these businesses, but the industry as a whole.

Safety is clearly paramount during periods when maintenance is undertaken, but if you can keep your staff safe, and also see OPEX benefits over CAPEX benefits, building in rental costs for the duration of the task to help cost out jobs, it is clear that there are some significant reasons to consider taking a closer look at rental when there is a safety critical project.

Gabe Authier, Tripwire, USA, describes how best to address security vulnerabilities in the oil and gas industry.

n our personal lives, installing software updates might be part of our daily mundane routines. Your phone, your laptop, IoT appliances and apps all require some sort of regular updates to bring you up to the latest software version and to install patches. While running these updates might constitute a brief disruption, they often include patches to vulnerabilities to help protect you against cyberattacks.

While perhaps not as hyper-connected as the technologies we use in our personal lives, the same applies to the expanding digital environments in the oil and gas industry. As more embrace connectivity to increase productivity to oil and gas operations, it’s critical to keep those digital, Internet-connected systems secure. Cyberattacks targeting industrial control systems (ICS) and the oil and gas industry specifically are today’s reality and this is increasing.

Known vulnerabilities are low hanging fruit for attackers, so security teams stay ahead of this threat by keeping systems up to date and vulnerabilities patched. ‘Patch management’ and ‘vulnerability management’

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may sound like IT speak, but the concepts are more and more important in industrial operations and critical infrastructure.

In today’s world, it’s important for operators of operational technology (OT) to understand these processes, the difference between the two, and how they are both critical for securing ICS environments.

Vulnerability management is a process that monitors the asset (application or device) on the network and provides analysis around vulnerabilities on the system. Patch management is actually a subset of vulnerability management and is the process used to ensure software is continuously updated while also highlighting, classifying and prioritising any missing patches on an asset. It’s an important element and can be crucial in mitigating the risk posed by an unpatched vulnerability.

While it’s becoming increasingly important in oil and gas, patching is particularly more difficult to do in these environments. It’s easier to patch systems that are centralised into one corporate network. Having to secure and patch oil and gas assets that are spread out and in remote locations becomes a challenge. For example, if you have remote connectivity for a given asset, and you decide to patch and something goes wrong, you might disrupt production, which is costly in itself, but also getting out to that asset to fix can take time and be costly.

Weighing risks and benefits in patch management When it comes to critical processes, such as those in oil and gas, it’s important to consider the pros and cons of installing a patch. There are instances in this industry where installing a patch may not be worth the effort, or too risky to operations.

Of course, the general intention behind releasing a patch is to provide some kind of benefit to the user. Patches are often released to address a vulnerability or security flaw in the operating system or in the applications. Or, if you find your software to not be working properly or acting buggy, you might implement a software patch that fixes the application’s stability. Stability is of course of high importance in the oil and gas industry, where ICS technology needs to maintain uptime and reliability.

There are certain cases, however, where patching might actually work against a facility’s uptime and reliability.

While the intentions behind the patches are to improve the application, implementing them can carry risk of disrupting operations. This is the case in patching any environment, but the stakes are higher when you’re looking at a disruption to oil and gas processes. This is where the IT side of the house might not think patching ICS environments is such a big deal, where the cost of a down IT system is comparatively a lot less compared to millions of dollars in a short period of lost production. If a patch goes wrong, which sometimes happens with a malformed or corrupt patch, there’s risk of taking down critical ICS components.

Cost of preparing to patch OT environments is another consideration. The patch may need to be tested before implementation in the actual environment. A test environment would involve additional equipment and hardware to simulate

the production systems in addition to the time and resources needed to actually test the different patches on different devices. In contrast, patching IT systems can be done in a virtual environment and with the help of an automated patch management system to handle most of the work. That’s a big difference in expense and logistical complexity.

These are certainly valid concerns that have slowed the progress of patch management in the oil and gas industry.

However, waiting until you’re actually hit with a cyberattack certainly isn’t an effective strategy either. Better practices need to be adopted to stay ahead of the attackers.

As DHS US-CERT described in their Recommended Practice for Patch Management of Control Systems, “The patch management of industrial control systems software used in CIKR is inconsistent at best and nonexistent at worst. Patches are important to resolve security vulnerabilities and functional issues. This report recommends patch management practices for consideration and deployment by industrial control systems asset owners.”

The oil and gas industry can start moving forward with controlled, manual, segmented patching to prevent a possible unexpected, uncontrolled system shutdown.

Confidentiality, integrity and availability (CIA) Confidentiality, integrity and availability, otherwise known as the CIA triad, is common speak in IT. And those elements are in order of IT priority.

Confidentiality comes first because of the potential for a breach to result in a loss of sensitive data, like personal data of customers or employees. That’s obviously bad for business, with financial impact, trouble with regulatory bodies, and a hit to reputation. Integrity comes next for similar reasons. If they can’t trust the integrity of their systems, organisations can also suffer fines and lost business. Availability, while still important, comes third because if a system does go down, it might not affect customers or create data issues, and the mean-time-torepair (MTTR) would likely be a lot shorter and simpler in IT environments than in OT. That thinking doesn’t line up with the priorities of operational environments where availability comes first, particularly in the oil and gas industry where a short period of downtime costs millions of dollars and where improper operations could have other effects such as environmental, health and safety of surrounding communities. This difference in context is one reason why IT and OT teams within the same organisation have differing priorities when it comes to patching ICS environments.

Still, there is common ground to be found in running safer, more secure and more reliable operations. No matter where you sit, it should all be agreed upon that you need to know what systems you have, where the potential problems lie, and if they meet your organisation’s policy and regulatory requirements. That’s why IT and OT should both find value in the tools for asset discovery, vulnerability assessment, policy management, change detection, configuration assessment, and log management. Security incident and event management (SIEM) can also be deployed in a converged IT-OT manner to monitor systems as an entire organisation,

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while alerting each team only to the issues and events that pertain to them.

The particular type and use of OT assets in oil and gas does still remain a tricky issue. Because these devices are so specialised and tuned according to their specific environments, they all might respond differently to patches. The concern here would be that a patch that has not been tested for that particular environment could disrupt production. Therefore, it is necessary for oil and gas organizations to invest in test environments to install the patch and ensure systems continue operating as expected. It’s of course difficult to get every single type of equipment out in the field replicated in a test lab, so that’s where weighing the risks and considering the criticality of that component comes into play

What to do if you can’t patch There will be quite a few scenarios in the oil and gas industry where a patch just isn’t possible. The patch cycle might be too long for required operations. Given the age of some of the systems in the oil and gas industry, a patch simply may not exist. Sometimes, the systems are just too complex.

In this case, additional protective controls need to be in place for assets that cannot be patched or would be patched only very rarely. In the case where patching isn’t possible or where the risk outweighs the benefits, these are practical approaches: Asset discovery will help you identify what you have in your environment. This is important so you know what to

protect but may also raise the question if there are some assets you don’t need and are wasting resources securing. ) Perimeter protection can be anything from firewalls to access controls, will protect your organisation from both physical and digital invasions. ) Segmentation can benefit your organisation in many ways

because it will prevent a breach from harming your entire organisation. ) Log management looks for movement within the

organisation to detect potential threats. ) Vulnerability assessment determines the vulnerable

risk level of each asset. A vulnerability scan will give you a score that indicates how easy it is to exploit the vulnerability and how much access is given if exploitation is successful. ) File integrity monitoring looks at the inside of the

organisation and alerts on suspicious changes there.

To keep up with rising cyber threats, oil and gas operators need to maintain visibility into and protection from events that can affect the safety, productivity and quality of their operations. Acknowledging the unique considerations within the oil and gas space, IT and OT teams should work together to ensure assets operate as expected and securely as possible.

Stefan Vages, ROSEN Group, USA, explains how to overcome the challenges of inspecting low-pressure and multi-diameter gas pipelines to collect useful data.

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n the world of extreme pipelines, there are many challenges to be taken on regularly. One of those is the inspection of multi-diameter low-pressure gas pipelines. Although many solutions for the inspection of multi-diameter pipelines have become available in the past two decades, these mostly focused on the mechanical passage of pipeline systems with multiple diameters. Today

the emphasis is not only on getting the inspection tool successfully through the pipeline, but also on collecting high-resolution and useful data, in order establish new information that enables better decision making for a comprehensive integrity management programme.

Gathering high quality data in low-pressure gas pipelines is particularly difficult due to the compressibility of the medium. At low operating pressures the likelihood of speed excursions, especially when using magnetic flux leakage (MFL) technology, increases significantly. These speed excursions usually result in compromised data quality, since the velocity negatively affects the magnetic field and therefore the properties of the measurement.

Another important aspect to consider when inspecting multi-diameter low-pressure gas pipelines is the preparation for inspection. In particular, the cleaning of these pipelines

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all boundary conditions. Special cleaning tools that have cleaning efficiency across all diameters are required. However, these also need to work within the constraints of the lower and upper pressure limits of the pipeline system. The inline inspection tools utilised for these complex pipeline systems have been outfitted with elements that have proven successful over the previous years in improving the run behaviour in single diameter pipelines, and their purpose is mostly to reduce friction and therefore reduce the differential pressure required to move them through the pipeline.

In the following sections, a project will be described where such a solution was successfully deployed.

Asset information Figure 1. Tailored solutions for unique challenges require extensive engineer and design, but also rely heavily on testing and validation to build confidence in the solution.

Figure 2. Once in the field the preparation work of understanding the pipelines operating conditions and mechanical conditions allows for successful collection of high-quality data.

is difficult, as multiple diameters need to be cleaned at the same time. Usually cleaning tools are set up in a way to create a lot of friction with the pipe wall in order to scrape sediments off it. High friction, however, is equivalent to high differential pressures across the cleaning tool. In many scenarios, these low-pressure gas systems can only accommodate a certain maximum operating pressure, mostly due to system limitations, and are limited at the lower end in order to be able to serve their customers. That means that only a certain amount of differential pressure is available in order to move cleaning and inline inspection tools through the pipeline.

In order to address the particular challenges of these systems, customised solutions are required that consider

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In order to ensure successful project execution, it is imperative to have sufficiently detailed information on the pipeline that needs to be inspected. In addition to the mechanical properties, like wall thicknesses, bend radii, installations, etc., it is important to also understand the operating conditions and their limitations. For example, there are circumstances in which it may be necessary that an inspection take place during the night, since gas flows are too high during the day, and/or that a certain period of the year has to be targeted in order to get the best possible operating conditions.

When reviewing the pipeline information, the mechanical properties must be established. The most important characteristics are the different diameters, the wall thicknesses in the different diameters, minimum bend radii for the different diameters, as well as critical installations. In addition to that, the operating conditions during the cleaning and inspection tool runs should be established. Meaning the range of flow rates, typically some variance cannot be avoided, and the upper and lower pressure limits of the system.

Solution engineering Once all the information is available and the boundary conditions of the inspection have been established, the engineering of the cleaning and inspection solution starts.

For the cleaning tools, usually a variety of different tools are designed in order to allow for a progressive cleaning approach. Typically two different designs are utilized: a disc tool with magnets, and a disc tool with magnets and brushes.

These designs are taken and different configurations of each are established with different disc diameters, thicknesses and material hardness. By changing the disc diameter, thickness and the material hardness, the amount of friction that is created against the pipe wall – and therefore the differential pressure needed to move these tools through the pipeline – can be adjusted. Once the rudimentary configurations have been established, basic testing of these is completed in order

to understand the required differential pressure. Depending on the results, adjustments are made to the disc diameter, thickness and material hardness. It is necessary to establish clear parameters upfront that need to be achieved in order to ensure that these tools deliver the required results.

For the inline inspection tools the process is more complicated. In the beginning of each customisation, a requirement specification is established based on the previously gathered information. The mechanical engineers first design the measurement modules for the different technologies. In the design process, the mechanical properties can be simulated in order to identify the minimum diameter these modules can pass through and what kind of bends can be negotiated. Another important aspect of this phase is the finite element analysis. In this process, the properties of the magnetiser are evaluated and it is determined whether the wall thicknesses present in the pipeline can be inspected with these measurement modules.

In order to fully cover the circumference of a multi-diameter pipeline, smaller diameter inline inspection tools require at least two measurement modules, while larger tools can typically accomplish full coverage with a single measurement module.

Design and testing For the inline inspection tools a lot of the design elements from the single diameter tools that were optimised for low-pressure gas pipelines have been adapted to the multidiameter tools as well. This includes a magnetiser that is

wheel supported instead of having a brush in contact with the pipe wall closing the magnetic field. This significantly reduces the friction of the measurement unit and is a key element to reducing the overall need for differential pressure. In addition to the wheeled magnetiser, other components are wheel supported as well. The pull unit with which the inline inspection tools move through the pipeline is also wheel supported, meaning the mechanism that is able to adapt to the various different diameters in a multi-diameter pipeline is wheel supported and the sealing elements are not carrying the majority of the load like a standard cup or disc would. This again significantly reduces the friction of the overall system and allows the inline inspection tool to move through the pipeline at very low differential pressure.

Upon completion of design, manufacturing, and assembly of these tools, a rigorous testing process is completed. For the inline inspection tools this includes two major forms of testing. First pull testing, which is done to validate the performance of the measurement system.

For magnetic flux leakage tools test pipes with various diameters and wall thicknesses are available. These have been outfitted with a variety of metal loss features that have to be detected and properly identified by the inline inspection tool in order to ensure it is ready for service. For geometry tools different features are included in these test pipes in order to verify the performance with regards to internal diameter measurements. It is important to mention that all of these systems are qualified in line with API 1163.

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The next step, in terms of testing, is to validate the actual mechanical passage capabilities and the properties concerning the inspection systems friction. For this pump testing is conducted. A pump test loop is usually established for this that simulates a variety of features present in the pipeline to be inspected. This usually includes the diameter transitions, the smallest bend radius in each diameter, as well as varying wall thicknesses in each diameter. Pressure readings are taken at the beginning and the end of the test loop in order to determine the differential pressure required to move the inline inspection system through certain features of the test loop. Upon completion of pump testing the differential pressure required to move the tool through the most difficult features has been determined and can be used to establish a better understanding of how the tool will perform in the actual pipeline. Since tests are usually performed at very low flowrates, in order to reduce the amount of momentum, the results are rather conservative in comparison to the actual values that are achieved in a real inspection.

Field operations Once all the equipment is deemed ready for the completion of the actual field work, it is mobilised and the process of cleaning the pipeline is started. First, the least aggressive cleaning tools are run through the pipeline in order to establish a baseline with regards to the cleanliness. After each run the aggressiveness can be increased, unless large quantities of debris are recovered from the pipeline. In such a scenario it is recommended to re-run the cleaning tool that recovered the large amount of debris until a reduction in debris removal has been achieved. Once the recovered debris from the pipeline has met a pre-agreed threshold the pipeline can be considered clean. It has to be understood that different inspection technologies have different requirements with regards to cleanliness, and therefore need to be established on a project-specific basis.

Upon completion of the cleaning activities, the inline inspection tools are prepared for their actual runs. First the geometry tool is run through the pipeline. It is recommended to keep the pressure in front of the tool as high as possible in order to stabilise the tool. Upon receipt, it is important to review the information gathered by the geometry tool in order to identify any potential restriction for the following MFL tool. If the data indicates that there are no restrictions, the MFL tool can be launched and the field work can be completed.

Conclusion Winn & Coales International, Ltd

World Pipelines

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Inspections of multi-diameter low-pressure gas pipelines are a complex and difficult undertaking. However, with good preparation, the right tools, and a consistent approach many of these pipelines can, and have been successfully inspected.

As requirements from regulatory authorities and the general public increase with regards to the operation of gas pipelines, technology will also improve to address the needs of operators for better information on their pipeline systems to ensure their continued and safe operation.

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