World Pipelines - February 2021

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Volume 21 Number 2 - February 2021



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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 2 | FEBRUARY 2021 03. Editor's comment Fighting for NS2

PIPELINES AROUND THE WORLD 30. The midstream heavyweights

05. Guest comment

Victor Argonov, EXANTE, Russia.

Vicki Knott, Co-founder and CEO of Crux OCM, Canada.

07. Pipeline news US President revokes Keystone XL permit; ConocoPhillips acquires Concho Resources; appointments to the FERC; and contract news from Strohm and Noble Midstream Partners.

Yulia Borzhemska, Head of Government Relations, DTEK Oil & Gas, discusses Ukraine’s place on the gas sector world map, including its current strengths and economic prospects.

2020 saw COVID-19 impact energy industries around the world, and Australasia was no exception. Dr Hooman Peimani discusses the region’s major pipeline activity, and where it may be headed in a renewables-focused future.


t goes without saying that 2020 was an extremely difficult year for all countries and their energy sectors, including pipeline activities. Added to a global economic slowdown inherited from 2019, the COVID-19-imposed lockdowns and restrictions affecting all types of activities pushed just about all the countries into a recession with a varying degree of GDP contractions. A major contributing factor to this dismal situation was a US-led trade war declared on almost all the large economies, including Canada, China, India, Japan, Russia, the European Union and Turkey. Initiated by President Donald Trump upon his ascension to presidency in 2017, the initiative contracted the targeted countries’ economies, which responded in kind to jointly preside over shrinking the global economy, as its escalation to a two-sided trade war also affected their trading partners to a varying extent. The US government’s imposition of a wide-range of economic sanctions for political gains on several countries, especially the energy-exporting ones with strong purchasing power and large imports (particularly Iran, Libya, Russia and Venezuela), did cripple their economies to varying degrees, although this was not the only or even the main reason in cases (e.g. Iran). The continued sanctions have not secured the intended objectives, but certainly helped to further shrink the under-stress global economy and decreasing energy demand. Against this background, the COVID-19 pandemic turned into a dramatic, unprecedented world-wide development with a significant negative impact on the global energy industry. The main victim was the fossil sector as manifested, remarkably, in rapidly-lowering demand for oil, gas and coal and their falling prices, while the non-fossil sector started flourishing for two reasons. As a global phenomenon, the pandemic magnified the urgency of opting for a sustainable energy mix to deal with worsening global warming. A large number of countries severely devastated by the pandemic’s economic fallout linked their pandemic relief plan and post-pandemic economic recovery to reducing greenhouse gas (GHG) emissions. The majority of them set a target of net-zero emissions by 2050 prior to the pandemic era (e.g., Canada, Denmark, the UK, France and New Zealand) while the Asian economic heavy weights (Japan and South Korea) opted for it in the post-pandemic era, with China aiming at 2060. Joe Biden’s election to US presidency will lead to his officially setting the same target for his country, the world’s second biggest polluter. Briefly, by the end of 2020, all the major economic regions (notably the European Union) and most of the G20 countries declared plans for switching to non-fossil energy for the bulk of their energy demands. Expanding renewable energy became



lot has changed in Ukraine in the three decades since independence, both politically and socially. However, one thing has always remained constant: the country’s importance as a strategic energy provider in Europe. In particular, Ukraine’s oil and gas sector has been at the heart of European energy security, and continues to show tremendous potential for further growth as well as opportunities for investment. The use of new technologies and consolidation of international partnerships has driven the success of the Ukrainian oil and gas sector, allowing it to engage in world-class collaborative partnerships. The impact has been immensely positive for the country, its economy and, ultimately, for its people. An indicator for Ukraine’s international significance in the global energy market is the fact that in 2017, the European Federation of Energy Traders (EFET) included Ukraine in its ranking of European gas hubs for the first time. In 2019, Ukraine was also included in the renowned Baker Hughes Rig Count index. A subsequent Baker Hughes report in 2020 listed Ukraine as European leader in the volume of machines involved in oil and gas drilling operations.



34. The future awaits Yulia Borzhemska, Head of Government Relations, DTEK Oil & Gas.



PIPELINE CONSTRUCTION EQUIPMENT 39. Cybersecurity: top of the agenda


Guy Dulberger, Ritchie Bros., Canada.

REGIONAL REPORT 14. Recovery and redirection 2020 saw COVID-19 impact energy industries around the world, and Australasia was no exception. Dr Hooman Peimani discusses the region’s major pipeline activity, and where it may be headed in a renewables-focused future.

SOFTWARE ENGINEERING SOLUTIONS 41. Accelerating the path to connection Rockwell Automation’s Gert Thoonen, Business Development Specialist, EMEA.

43. A symphonic approach Deepa Poduval and Michael Nushart, Black & Veatch, USA.

KEYNOTE 19. Protecting pipeline data Whitney Vandiver, Ph.D., NuGen Automation, USA

EPC 45. Conquering the paper mountain

CORROSION CONTROL 25. Learning never ends

Joe Pikas, Technical Toolboxes, USA.

SUBSEA REPAIR 49. An all-in-one solution

Brandon Taylor, OneBridge, USA.

Peter Routledge, Forth Engineering, UK.

DEVELOPMENTS IN COATINGS 53. The power of remote control Bryan R. Kirchmer, Aegion Coating Services, USA.



INLINE INSPECTION SERVICES 57. Mapping broken currents Dennis Janda, ENTEGRA, USA.




DECOMMISSIONING 61. A green lifecycle Nicholas McNally, Decom Engineering, Northern Ireland.


Reader enquiries [] Volume 21 Number 2 - February 2021

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ISSN 1472-7390

Victor Argonov, EXANTE, Russia, provides an overview of some of the world’s largest pipelines and explains how they could support the industry in a post-pandemic world.

il prices have inevitably been affected this year by the world’s transition to greener, more economical energy sources, as well as the COVID-19 pandemic. However, the world’s largest pipelines are continuing to transport fuel all over the world. The second wave of the pandemic has hit the world with full force. In its September report, the International Energy Agency expected global oil demand to fall by 8.4 million bpd in 2020 compared to 2019. Given the worsening COVID statistics in some of the key oil-consuming economies, IEA and other key forecasters (the US Energy Information Administration, as well as OPEC) are likely to revise their expectations for global oil demand down. The near-term demand outlook for the largest oil importers is clouded by COVID-related uncertainty. In 2019, six of the EU member countries were among the world’s fifteen largest oil importers. Germany, France, Netherlands, Spain, Italy and Belgium together imported US$190 billion worth of crude oil. Together with the UK, these economies accounted for more than 20% of the total global oil imports. Historically, the oil market has been quite sensitive to relatively small percentage changes in global oil supply and demand. The relatively high share of the above economies in global oil imports explains why the oil prices dropped in response to the news of the recent restrictions in these countries. In 1Q20, global oil demand began suffering from the reduction in economic activity, which started with the COVID-related lockdown in China. In April, at the peak of the first wave of the pandemic, Brent oil price plummeted below US$20/bbl, while the US benchmark, WTI, briefly traded at a negative price. In late April, OPEC+ countries agreed to cut their combined output by 9.7 million bpd in response to the unprecedented demand shock. This restriction was in place in May and June; as of July, as global economic activity rebounded, the members of the augmented cartel switched to a smaller targeted reduction of 7.7 million bpd. According to the April deal, as of January 2021, the combined output reduction target should be cut further to 5.8 million bpd. However, given the recent acceleration in COVID cases in some of the key economies, the release of an extra 1.9 million bpd of oil on the market seems an increasingly bad idea. In late October, the Wall Street Journal quoted its sources that Saudi Arabia will propose an extension in the current level of oil output cuts (7.7 million bpd) into 1Q21. On 3 November 2020 Algeria, which currently holds the OPEC presidency, called for an extension of the current

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c o m p a ny


SENIOR EDITOR Elizabeth Corner





SALES MANAGER Chris Lethbridge







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he Nord Stream 2 gas pipeline project (NS2) faces mounting opposition, just as the final pipes are being laid. NS2 is the second phase of Nord Stream, which takes Russian gas directly to Germany via the Baltic Sea, bypassing Poland and Ukraine (turn to p. 34 for an in-depth look at Ukraine’s place in the global gas sector). As of 1 February, NS2 is over 90% complete, with only 148 km of pipeline still to be laid on the seabed. In January, members of the European Parliament called for EU states to sanction Russia, following the alleged nerve agent attack on – and recent detention of – outspoken Kremlin critic Alexei Navalny. This brings Germany under pressure to halt the construction of the pipeline amidst escalating EU-Russian tensions. In a nonbinding vote, MEPs called for the EU to “immediately prevent” the completion of the pipeline project, while demanding Navalny’s release from jail. Meanwhile, US President Joe Biden is expected to continue the work of his predecessor, former President Trump, in making policy that opposes NS2. On his last full day in office, Trump imposed sanctions on a pipelaying ship being utilised for the project (the Russian ship, Fortuna), and the US Department of State had previously updated its guidance regarding the applicability of secondary sanctions against parties who invest directly in and/or sell, lease or provide goods to the Russian Federation for the construction of energy export pipelines. Biden has called the pipeline a “bad deal” for Europe in the past. Despite the noise from the European Parliament and the US, the German government has reiterated that it does not plan on abandoning the project, despite the recent geopolitical developments. “There is no direct connection between the Navalny

case and Nord Stream 2,” government spokesman Steffen Seibert said in Berlin on 25 January. German Chancellor Angela Merkel is expected to discuss the project with President Biden in the coming weeks; the two world leaders will certainly disagree on what the project means in global terms. Merkel has always maintained that NS2 is a business deal and nothing more. She has pursued a ‘business first’ agenda when entering into investment or manufacturing deals with countries such as Russia and China; something that won’t sit well with Biden. Merkel is the outgoing Chancellor, having stated that she will not seek a fifth term of office in 2021. The (rumoured) favoured candidate to replace her as head of the CDU is Armin Laschet, a Russophile. He has repeatedly warned against a supposed ‘demonisation’ of Russia and an ‘anti-Putin populism in Germany.’ Of course there’s a precedent here: Merkel’s predecessor in the role of German Chancellor, Gerhard Schröder, is a Director at Nord Stream and also Chairman of Russian state controlled oil giant Rosneft. Can you hear Biden gnashing his teeth? I hope you enjoy this issue of World Pipelines, which includes a fascinating article from NuGen Automation (USA) on the risks posed by the public disclosure of sensitive pipeline data and information (p. 19). The article highlights the importance of protecting pipeline information from the US Freedom of Information Act and discusses many facets of pipeline operation, including control room security, incident response, confidential personnel information and integrity management. And for more on integrity management, join us for a virtual conference, Integrity 2021, on 28 and 29 April. Sign up for free at



Comment Vicki Knott Co-founder and CEO of Crux OCM, Canada


n 2020, the industry battled environmental, social, and corporate governance (ESG) initiatives, declining oil demand and decreasing investment into the oil and gas sector, combined with an increasingly difficult climate in which to recruit, engage and retain Millennial and Gen Z talent. All this has teed up the oil and gas sector for quite a ride for the next few decades. The energy transition to fully renewable will happen, eventually. The question is: will it be decades or centuries? Regardless, the oil and gas pipeline ecosystem will need to adjust to retain the talent required to meet energy demand, in order to combat global energy poverty. The majority of up-and-coming generations find it hard to care about oil and gas pipelines: this is an uncomfortable truth that the industry needs to face. We operate a tech company, Crux OCM, which has Silicon Valley backers, yet because many of our customers are oil and gas, we routinely hear: “I will not work for oil and gas” when trying to recruit top talent. If we – as a start-up tech company, funded by capital from the two global tech centres, Silicon Valley and Tel Aviv – struggle to recruit top talent because of the industry we service, what hope does the actual industry have to recruit the talent needed to innovate? The way I see it, the existing oil and gas industry needs to increase fragmentation and outsource more. Oil and gas companies are very good at extracting, transporting and processing petroleum products safely. Beyond this, they are stretching past their core competencies. During boom times, there is capital to experiment; however, this is no longer the case. With dwindling investment for new infrastructure, the only option is to work with what you have and make the existing infrastructure as efficient as possible. I know of pipelines operating at 85% capacity, yet those companies are lobbying to build more infrastructure. Investors are becoming wise to the ‘rate base’ contracts

and are demanding more responsible operation. Why would an investor with an ESG mandate pay for a new pipeline when a contract re-negotiation and increased responsibility of operation results in additional volumetric on the same asset, thus increased cash flow – all without building new infrastructure? Pipeline operators are no longer going to be able to say “this is the best we can do”. To get there, things need to be different. Oil and gas pipeline monoliths will need to learn to play with others to increase the efficiency of their existing assets, especially if investors, the general public and governmental regulation are no longer amenable to building more and more new infrastructure. A board of directors doesn’t want to hear “I have a seven year plan to get from 85% utilisation to 90%”; they want to hear about the one year plan to increase the responsibility of operation and utilisation of the assets that their capital is working. I have heard the term “innovative ecosystem” too many times to count in the oil and gas pipeline industry. The key point that is overlooked is that almost any large company, or industry, that has tried to innovate from the inside out has failed. We cannot expect an engineer who has worked at a large oil and gas pipeline company for the last 25 years to know how to re-imagine the industry. Given the lack of interest in talent migrating to oil and gas from other sectors (especially amongst younger generations), the only option is to learn how to work with smaller companies with different ideas and faster execution. The challenge for oil and gas pipeline companies then is to not kill or squash those small companies that attract Millennial and Gen Z talent, but to create the “innovative ecosystem” with them. This way oil and gas companies can benefit from the emerging talents of younger generations, rather than expecting their existing employees to re-invent a pipeline.


WORLD NEWS US President Joe Biden revokes permit for Keystone XL pipeline On 20 January 2021, The Wall Street Journal reported on US President Joe Biden’s first day in office, which included signing an executive order revoking the permit for the Keystone XL pipeline. According to sources, the action came despite efforts from TC Energy and unions to convince the administration of the project’s potential economic and social benefits. The new President’s focus on addressing the climate crisis, including rejoining the Paris agreement, was a key aspect of his campaign and has earned praise from environmental groups, including Greenpeace Canada, as well as many Indigenous communities. However, as reported by The Guardian, Alberta’s premier Jason Kenney – along with some First Nation investors – expressed disappointment at the loss of a project due to bring thousands of jobs to the region’s oil and gas industry, with many to be taken up by Indigenous people. Canadian supporters of the Keystone project were not the

only ones to express their discontent. The pro-natural gas nonprofit group The Empowerment Alliance released the following statement on 21 January from spokesman Ian Prior: “We had hoped to release a statement today congratulating President Joe Biden on his inauguration and imploring him to hold firm to his multiple promises not to end fracking. Unfortunately, just hours after taking office, Biden revoked the permit granted to the Keystone XL Pipeline and re-entered the Paris Climate Accord. “The last thing that the new President should be doing is taking actions that would kill jobs and raise energy prices for families in the middle of a pandemic; especially given America’s low consumer energy prices and the cleanest air in nearly 50 years, due to the shale revolution. “After an inauguration speech focused on healing and unifying, it is beyond disappointing that one of President Biden’s first acts is to bow to the Greens with Greenbacks while leaving American families to foot the bill.”

ConocoPhillips acquires Concho Resources ConocoPhillips has announced that it has completed its acquisition of Concho Resources following approval by shareholders of both companies. “We appreciate the strong support for this transaction from the shareholders of both companies, which we view as further affirmation of the significant benefits it will deliver,” said Ryan Lance, ConocoPhillips Chairman and Chief Executive Officer. “This acquisition results in the combination of two premier companies that can lead the structural change for our vital industry that’s critical to investors. We expect the company to deliver differential performance on three key mandates: providing affordable energy to the world, generating superior returns on and of capital and demonstrating ESG leadership.” Lance added, “I also welcome Tim Leach to ConocoPhillips’

board of directors and executive leadership team. Tim and his organisation built a best-in-class Permian company and we both look forward to creating significant value from this transaction. Thanks to the considerable efforts of our transition teams over these past few months, we’re off to a fast start toward seamlessly integrating our two companies and building momentum as a sector leader.” ConocoPhillips and Concho will each file the vote results for their respective special shareholder meetings on a Form 8-K with the US Securities and Exchange Commission. In accordance with the terms of the merger agreement, each share of Concho common stock was converted into the right to receive 1.46 shares of ConocoPhillips common stock at the effective time of the merger.

NDT Global completes integration of Halfwave into its inspection services business NDT Global has announced the integration of Halfwave inspection services into the NDT Global business. Halfwave is the owner of the proprietary Acoustic Resonance Technology (ART), an ultrasound-based technique which allows high-precision measurements in imperfect conditions and without the need for liquid couplant. The ART technique allows NDT Global to officially enter the in-service gas pipeline segment and present a competitive alternative to MFL and EMAT testing. Halfwave AS was acquired by NDT Global’s parent in February of 2020. Andy Bain, Senior Vice-President, NDT Global comments,

“We truly believe this integration marks the start of a new chapter of what has already been a great story for NDT Global and Halfwave. “We are excited about adding ART to our portfolio as it perfectly complements NDT Global’s Ultrasonic Technology (UT) solutions. NDT Global is now a single supplier of gas and liquid pipeline inspections and integrity management services. “This integration brings many opportunities for our combined organisations in terms of services and technological advancements that we will be able to provide pipeline operators helping them operate their pipelines safely and efficiently.”

FEBRUARY 2021 / World Pipelines


WORLD NEWS IN BRIEF CANADA On 14 December 2020, CodeCAD was acquired by HEXAGON. Consequently, as of 13 January 2021 FLUMEN has taken over CodeCAD’s role as the AFT representative for Canada. As a result, AFT is proud to welcome Patrick Tremblay and FLUMEN as an AFT Channel Partner.

UK A snapshot survey of the UK’s supply chain has revealed an improved outlook for the industry with less anticipated redundancies, greater optimism and new geographical markets. Industry body, Subsea UK, surveyed its 300 members in early July and then again in late November 2020 to provide evidence-based insight into how the supply chain was faring in the midst of the public health and economic turmoil of 2020.

INDIA Man Industries (India) Limited – a large diameter pipe manufacturing company – announced that the company has received new orders of approximately Rs. 250 crores for the oil and gas sector, from GAIL and several other companies.

GERMANY On 1 March 2021, Luc Perrad (53) will take over from Michael Schad (63) as Director of International Sales for DENSO Group Germany. Michael Schad, a renowned industry expert, will take his retirement after 36 years of service. Luc Perrad has more than 20 years of global technical sales experience and extensive consulting expertise when it comes to questions concerning corrosion protection for pipelines.


World Pipelines / FEBRUARY 2021

Intero Integrity Services announces completion of merger with Pipetel Technologies Intero Integrity Services, backed by First Reserve, has announced the completion of a merger with Pipetel Technologies, an innovative service provider to the gas utility industry specialising in robotic inline inspection of challenging pipelines. Pipetel Technologies, founded in 1999 in Toronto, specialises in difficult to inspect gas pipelines, combining advanced technology and engineering with innovative robotic solutions. These services are critical to enabling its utility customers to reduce methane emissions and enhance the safe operations of their pipeline infrastructure. As a result of their successful research and development programme, in partnership with the Northeast Gas Association/ NYSEARCH, Pipetel deploys the most technologically-advanced robotic inline inspection fleet in the world. Rienk de Vries, Intero’s CEO, highlights the strategic importance of this merger. “This merger creates a global company, with state of the art and unique solutions for the most difficult to inspect pipelines in the world, whether natural gas or liquid, or requiring ultrasonic or magnetic flux leakage technology. Pipetel’s experience, technology, and credentials, together with Intero’s, opens new possibilities to provide

multiple inline inspection solutions to both current and new clients operating critical pipeline infrastructure in the energy and transportation industries.” Paul Laursen, CEO of Pipetel Technologies, says: “Intero Integrity Services provides Pipetel Technologies with an extensive global network and access to many new customers outside North America. Our team is pleased to join strengths with Intero, and to continue to grow our services worldwide. “There is a strong synergy between Pipetel and Intero within the unpiggable pipeline inspection market, including the sales and agent network, training, R&D, and data analysis. Pipetel’s excellent track record and innovative technology can now reach significantly more customers around the world.” Mike Scardigli, Managing Director of First Reserve, commented, “This transaction highlights First Reserve’s continued support of companies playing a crucial role in maintaining the integrity of critical infrastructure. The aging pipeline asset base and heightened focus on ESG necessitate innovative solutions and the combined company is well positioned to continue developing these cutting-edge technologies for its customers.”

US President Biden names Glick Chairman of FERC President Joseph R. Biden has named Rich Glick to be the new Chairman of the Federal Energy Regulatory Commission (FERC). “I am honoured that President Biden has shown the confidence in me to lead the agency at this critical moment in time,” Chairman Glick said. “I look forward to continuing working with my fellow commissioners and the exemplary FERC staff to pursue the Commission’s important statutory missions.” Chairman Glick joined FERC in November 2017 after serving as general counsel for the Democrats on the Senate Energy and Natural Resources Committee, providing policy advice on numerous issues including electricity and renewable energy. Prior to that, Chairman Glick was Vice

President of government affairs for Iberdrola’s renewable energy, electric and gas utility, and natural gas storage businesses in the United States. He ran the company’s Washington, DC, office and was responsible for developing and implementing the US businesses’ federal legislative and regulatory policy advocacy strategies. He also served as a Senior Policy Advisor to US Energy Secretary Bill Richardson, and before that was Legislative Director and Chief Counsel to US Senator Dale Bumpers of Arkansas. Chairman Glick is a graduate of The George Washington University and Georgetown Law. He and his wife Erin have a son.







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28 - 29 April 2021 Integrity 2021 integrity2021/

RESCHEDULED: 25 - 27 May 2021 Subsea Expo Aberdeen, Scotland

8 - 10 June 2021 Global Energy Show 2021 Alberta, Canada

Outrigger Energy II announces completion of its Williston Basin midstream facilities Dave Keanini, Outrigger’s CEO, stated, “We are exceptionally proud of our team who worked diligently within a very ambitious schedule and were able to successfully execute the project, even through the COVID19 global pandemic. We delivered the project on time – in less than eight months from groundbreaking – for our anchor customer and under budget for our investors. The highcapacity state-of-the-art facilities will assist XTO with the execution of its development plans. “While Williston Basin activity levels clearly slowed due to the 2020 crude oil pricing and COVID-19 environments, we are seeing substantial interest from producers to accommodate future drilling plans as crude oil prices near sustainable levels for the Basin. Our assets are perfectly situated to provide producers with a competitive midstream option for both new development and volumes that are currently flaring due to infrastructure constraints.”

Outrigger Energy II LLC has announced that it has completed construction of its Williston Basin midstream facilities project in Williams County, ND. The assets consist of the Bill Sanderson Gas Processing Plant, a 250 million ft3/d cryogenic gas processing plant located west of Williston, ND, and an 80 mile, 20 and 24 in. dia., rich gas gathering system originating in eastern Williams County and terminating at the Bill Sanderson Plant. The high efficiency plant features ethane recovery and rejection capabilities with direct market access to the Northern Border Pipeline system for residue gas and the ONEOK NGL pipeline system for natural gas liquids. The assets are anchored by a long-term gas gathering and processing agreement with XTO Energy, Inc., a wholly owned subsidiary of ExxonMobil. The gathering system can transport over 450 million ft3/d of raw gas volumes and Outrigger plans to expand the plant’s capacity based on producer needs.

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RESCHEDULED: 5 - 9 December 2021 23rd World Petroleum Congress Houston, USA


World Pipelines / FEBRUARY 2021

Centurion Pipeline L.P.’s US Augustus Pipeline completes open season Centurion Pipeline L.P. has announced the successful completion of its binding open season for the Augustus Pipeline. The Augustus Pipeline will connect Centurion’s existing Midland Terminal to multiple long-haul pipelines originating at Crane, Texas, US. The project will include a combination of new and existing pipeline assets and have an initial throughput capacity of 150 000 bpd with future expansion capability available. The pipeline commenced service on schedule, on 1 December 2020. Centurion is a wholly owned subsidiary of Lotus Midstream, LLC. “We are pleased to be able to offer shippers a service that will provide connectivity between the Midland and Crane crude oil markets and provide shippers with access to multiple longhaul pipelines originating at Crane for delivery to the Corpus Christi and Houston markets,” said Lotus Midstream President and CEO Mike Prince. “Centurion Pipeline’s assets are strategically positioned throughout the Permian Basin, and the Augustus Pipeline will provide shippers access to the growing crude oil market at Crane.”


EagleClaw Midstream achieves ESG milestones

SAP and DNV GL partner to combat CUI

Spectrum Process Systems rebrands back to OPSCO

Shell Midstream Partners names Steve Ledbetter as next CEO Follow us on LinkedIn to read more about the articles

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CONTRACT NEWS Noble Midstream Partners adds Chevron dedication in DJ Basin

Total E&P and ExxonMobil commence TCP qualification project with Strohm

Noble Midstream Partners LP has announced that the Partnership has entered into an agreement with a Chevron Corporation subsidiary to provide oil transmission services from the Wells Ranch development area to Platteville, Colorado, for long-haul transportation out of the DJ Basin. With this agreement, Noble Midstream will now be responsible for substantially all crude oil gathering and intermediate oil transportation services from the Wells Ranch development area. Concurrent with this new transmission service, Noble Midstream has executed a capacity lease with a subsidiary of Energy Transfer LP for capacity on Energy Transfer’s Wattenberg Oil Trunkline (WOT). The partnership has contracted for the ability to utilise a substantial portion of the capacity on this in-service pipeline through 2031. The WOT pipeline terminates in Platteville, Colorado, where Noble Midstream has extensive existing infrastructure and storage with access to all four major long-haul pipelines in the DJ Basin. The WOT capacity lease highlights Noble Midstream’s strategy to seek highly accretive and capital-efficient opportunities to best serve customer needs. Additionally, this transaction furthers the Partnership’s objective to high-grade and diversify its cash flow profile.

Strohm has announced it has secured a contract with Total and ExxonMobil for a qualification testing programme for a high pressure, high temperature thermoplastic composite pipe. The qualification project will create a foundation for further development of this TCP technology for riser applications. Under the agreement, Strohm will execute a qualification testing programme for a TCP Jumper for permanent subsea application, for hydrocarbon service. The TCP Jumper is designed and fabricated using carbon fibre and PVDF polymer to provide a powerful combination for subsea high pressure and high temperature applications. “This project for Total and ExxonMobil demonstrates our success in the subsea market with our TCP technology on the basis of a compelling business case, fit-for-purpose materials and a clear endorsement of the technology from key clients,” said Henk de Boer, Chief Technology Officer at Strohm. He continued: “Total and ExxonMobil have previously qualified our materials and products for water injection and have an extensive and deep understanding of composite materials and TCP. We are delighted they have agreed to start this qualification project, which aims to extend our growing qualified product portfolio for Total and ExxonMobil to include hydrocarbon service.” Ivo Conradi, SURF & SPS R&D lead at Total E&P R&D, commented: “We have been involved in TCP developments with Strohm since the early days. We believe there could be great potential in using TCP Jumpers to optimise subsea architectures, with the aim to reduce cost and increase lay-out flexibility. “This programme is an important step for our company to be able to consider TCP as an alternative solution in a wider range of subsea applications.” Tristan Aspray, Vice President of research and technology development at ExxonMobil, added: “We recently qualified Strohm’s TCP for water injection applications and look forward to the potential for new offshore product offerings that bring value and maximise efficiencies for upcoming offshore developments.” Strohm has the largest track record for TCP in the world. The Netherlands’ headquartered company offers a wide range of products based on a variety of fibre and polymer materials, to provide the best solution depending on the needs, pressure, service and temperature. The robust PVDF polymer is already a fully proven material in subsea flowlines; the carbon fibre is insensitive to long term effects such as corrosion, fatigue and creep. Strohm expects that this combination makes it the material of choice for high-end subsea application in jumpers, flowlines and risers.

Magellan and Enterprise to develop joint Houston crude oil futures contract Magellan Midstream Partners, L.P. and Enterprise Products Partners L.P. have announced that affiliates of the two companies have entered into an agreement to jointly develop a futures contract for the physical delivery of crude oil in the Houston area in response to market interest for a Houstonbased index with greater scale, flow assurance and price transparency. The quality specifications will be consistent with a West Texas Intermediate (WTI) crude oil originating from the Permian Basin with delivery capabilities at either Magellan’s East Houston terminal or Enterprise’s ECHO terminal in Houston. “The industry-recognised quality and consistency of Midland WTI crude oil at Magellan’s East Houston terminal, combined with flexible and reliable market access offered by both Magellan and Enterprise, make this joint effort a logical advancement for crude oil futures to provide added value for our customers, both domestically and globally,” said Michael Mears, Magellan’s Chief Executive Officer. “We are pleased to join with Magellan on this initiative, which will provide customers with enhanced flexibility, connectivity, market access and price transparency for their physical barrels of crude oil,” said A.J. “Jim” Teague, Co-Chief Executive Officer of Enterprise’s general partner.


World Pipelines / FEBRUARY 2021


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2020 saw COVID-19 impact energy industries around the world, and Australasia was no exception. Dr Hooman Peimani discusses the region’s major pipeline activity, and where it may be headed in a renewables-focused future.


t goes without saying that 2020 was an extremely difficult year for all countries and their energy sectors, including pipeline activities. Added to a global economic slowdown inherited from 2019, the COVID-19-imposed lockdowns and restrictions affecting all types of activities pushed just about all the countries into a recession with a varying degree of GDP contractions. A major contributing factor to this dismal situation was a US-led trade war declared on almost all the large economies, including Canada, China, India, Japan, Russia, the European Union and Turkey. Initiated by President Donald Trump upon his ascension to presidency in 2017, the initiative contracted the targeted countries’ economies, which responded in kind to jointly preside over shrinking the global economy, as its escalation to a two-sided trade war also affected their trading partners to a varying extent. The US government’s imposition of a wide-range of economic sanctions for political gains on several countries, especially the energy-exporting ones with strong purchasing power and large imports (particularly Iran, Libya, Russia and Venezuela), did cripple their economies to varying degrees, although this was not the only or even the main reason in cases (e.g. Iran). The continued sanctions have not secured the intended objectives, but certainly helped to further shrink the under-stress global economy and decreasing energy demand. Against this background, the COVID-19 pandemic turned into a dramatic, unprecedented world-wide development with a significant negative impact on the global energy industry. The main victim was the fossil sector as manifested, remarkably, in rapidly-lowering demand for oil, gas and coal and their falling prices, while the non-fossil sector started flourishing for two reasons. As a global phenomenon, the pandemic magnified the urgency of opting for a sustainable energy mix to deal with worsening global warming. A large number of countries severely devastated by the pandemic’s economic fallout linked their pandemic relief plan and post-pandemic economic recovery to reducing greenhouse gas (GHG) emissions. The majority of them set a target of net-zero emissions by 2050 prior to the pandemic era (e.g., Canada, Denmark, the UK, France and New Zealand) while the Asian economic heavy weights (Japan and South Korea) opted for it in the post-pandemic era, with China aiming at 2060. Joe Biden’s election to US presidency will lead to his officially setting the same target for his country, the world’s second biggest polluter. Briefly, by the end of 2020, all the major economic regions (notably the European Union) and most of the G20 countries declared plans for switching to non-fossil energy for the bulk of their energy demands. Expanding renewable energy became


prominent in most cases, especially in European countries where nuclear energy aversion is strong, while many Asian countries, especially China and India, are also expanding their nuclear energy sector. Yet, this development should not be exaggerated, despite its importance, as it reflects an aspirational goal to be achieved over three decades – not a fait accompli. Hence, as noted by UN Secretary General Antonio Guterres in his address to the virtual Climate Ambition Summit of 12 December 2020, reported by The Guardian, the “G20 countries were spending 50% more in their stimulus packages on fossil fuels and CO2intensive sectors than they were on low-CO2 energy”. Nevertheless, the described global development did not spare any energy-producing region and, thus, Australasia was no exception. The region consists of a large number of islands and island states, the most major ones in terms of economies and energy production and consumption being Australia, New Zealand and Papua New Guinea (PNG). Compared to other regions, the impact of the pandemic on these countries has been less significant, although they have experienced short periods of surges and/or lockdowns with an accompanying impact on their economies. Going through the aforementioned pre-pandemic global economic situation, the pandemic induced a recession in the first two countries, and severely damaged PNG’s economy. New Zealand is the only regional country with a government-set zero emission target by 2050, adopted in November 2019, while the other two have broad commitments to expanding renewable energy. The three countries have oil and gas reserves to meet a varying extent of their energy demands, while all of them import different volumes of oil. Australia and PNG export LNG, the only way for exporting natural gas for these island countries with no realistic possibility for piped exports. Consequently, none of them has an active plan for constructing oil or gas pipelines to import or export these fuels except a proposed, but currently-shelved, project for importing PNG gas through the proposed Queensland-PNG Gas Pipeline (3800 km, including 650 km subsea; AUS$3 billion) to connect Australian gas consumers in Queensland and the Northern Territory to PNG’s gas reserves. The close proximity of PNG and Australia makes this project technically feasible. The impact of the global economic slowdown on the three countries, added to their own individual economic challenges, have surely reduced their energy demand with knock-on effects on their energy sectors, and, by default, pipeline activities. However, such activities have been limited in New Zealand and PNG, in any case, by factors such as small populations with lowpaced demand increase and domination of renewable energy (mainly hydro and wind) for power generation, in the case of New Zealand. PNG and New Zealand have comparatively small pipeline networks with limited activities and, therefore, an absence of any major oil and gas pipeline projects in 2020 or any firmlyplanned ones for the coming years. PNG’s few major oil and gas pipelines transfer its oil and gas productions to the country’s oil refinery and LNG production facility, respectively. The other gas pipelines distribute gas


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among its consumers, while an oil export pipeline feeds oil tankers. The major ones include a conditioned gas pipeline (700 km, of which 407 km is offshore) from the Hides Gas Conditioning Plant in the Highlands to the LNG Plant near Port Moresby. A gas pipeline (14 in.) and a pipeline for condensate (8 in.) are operational between the Hides gas conditioning plant and the Juha production facility. Likewise, New Zealand’s pipeline system is small. The country’s oil pipelines are very limited and mainly confined to transport refined products from its only refinery (Marsden Point Refinery) in Marsden Point, Northland, to the major regional storage facilities for domestic distribution through a 170 km pipeline to the Wiri depot near Auckland International Airport, and a Jet Fuel pipeline from the Wiri depot to the airport. First Gas Limited owns New Zealand’s gas transmission network, consisting of 2500 km of transmission pipelines from the New Plymouth area to Whangarei in the north, Taupo centrally, to Gisborne and Napier in the east, and to Wellington in the south. It also operates high pressure pipelines and more than 4800 km of gas distribution networks across the North Island. Short pipelines to replace or improve distribution networks aside, New Zealand has no planned project for constructing major oil or gas pipelines. Having a mainly renewable energybased power sector, its set emission-free goal, which will not immediately end its fossil-energy-dominated energy mix, will surely be leading to more renewable energy projects. However, as an expanding global trend, its growing interest in hydrogen could potentially stimulate large-scale pipeline construction to be explained. Having the region’s largest pipeline system, Australia is also its hub of pipeline activities. The country has more than 39 000 km of operating gas pipelines, which distribute gas among its consuming regions and connect its gas reserves to its LNG production facilities. Despite the mentioned discouraging global market for oil and gas, including LNG, Australia has a large number of approved and proposed pipelines to be discussed. Notwithstanding a global decline in oil and gas (both piped and LNG) demand affecting Australia as well, the world’s largest LNG exporter has preserved its largest customer, China, as well as others, including its second largest market: Japan. According to EnergyQuest estimates in November 2020, Australia’s LNG exports to China in the January - October 2020 period were exactly the same as the comparative period of 2019, i.e., 23.5 million t. In fact, as reported by Hellenic Shipping News in December 2020, the country’s total LNG exports for 2020 until November were “running 1.2 Mt ahead of the same period last year and EnergyQuest [expected] that total exports for the year could reach a new record of 78 Mt.” Within this framework, Australasia’s major pipeline activities are briefly discussed below.

Australia Northern Goldfields Interconnect (NGI) Australia’s APA Group announced in November 2020 its plan to construct a major gas pipeline connecting emerging fields in the North Perth basin to the Goldfields region in Western

Australia. Reportedly, the Group invest up to AUS$460 million in the NGI (580 km, 304 mm) set to go online by mid-2022. Being part of the Western Australian gas grid, the pipeline will connect to APA’s existing Goldfields Gas Pipeline (GGP), connected to the APA Group’s major Eastern Goldfields network. According to APA CEO and Managing Director, Rob Wheals, the NGI will add capacity to his company’s gas grid.

Extension to Eastern Gas Pipeline (EGP) In September 2020 Jemena proposed an extension to the Eastern Gas Pipeline (AUS$400 million). As stated by Australian Pipelines and Gas Association Ltd. CEO Steve Davies, the EGP will be extended by 185 km “from Sydney’s west to the Hunter Valley” to connect “the Hunter to domestic gas supplies and allow for connections to proposed LNG import terminals at Port Kembla and Newcastle.” Reportedly, Jemena is also planning to modify the EGP to enable it to transport bi-directionally between New South Wales and Victoria, to avail gas to more customers.

Port Kembla interconnect pipeline Following the above-mentioned report, in December 2020 the Australian Industrial Energy Pty Ltd. (AIE) signed a memorandum of understanding with Jemena for linking its proposed Port Kembla LNG reception terminal (AUS$250 million) south of Sydney with the EGP to run up the coast into New South Wales and the Australian Capital Territory from Victoria. AIE’s signing of a lease agreement in November with NSW Ports for up to 25 years enables it to begin constructing the reception terminal, as reported by OGJ Online. The cost of the 12 km underground pipeline between the two points is estimated at AUS$70 million, to create delivery capacity of 522 TJ of gas from the regasification terminal.

Scarborough Gas Pipeline (SGP) In July 2020, a discovery of ancient artifacts on the seabed off Australia’s west coast added a barrier to the construction of Woodside Petroleum Ltd.’s SGP (430 km) out of concerns about conserving Australia’s indigenous heritage. Their location are approximately 5 km east of where the company plans to build the pipeline once the final decision for developing the Scarborough gas field, now planned for 2021, is made. The company has reportedly approached the concerned archaeologists and the Murujuga Aboriginal Corp, who are the region’s indigenous landowners, about its pipeline route. Preserving those artifacts would likely lead to rectifying the pipeline’s route to some extent. The SGP is part of Woodside Petroleum Ltd.’s offshore project proposal for developing the Scarborough gas field off northern Western Australia, by new offshore facilities to be connected to the pipeline. Owned by Woodside (73.5%) and BHP (26.5%), reportedly, the field is estimated to have “contingent resource (2C) dry gas volume of 11.1 trillion ft3 (100%; 8.2 trillion ft3 Woodside share).” The developer aims at expanding the existing Pluto LNG onshore facility (Pluto Train 2). The Scarborough Joint Venture has already been granted petroleum production licences from the Commonwealth and Western Australian Joint Authority.


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New Zealand New Zealand is considering hydrogen as a renewable source of energy, to help it reduce its consumption of fossil energy and decrease its emissions to achieve its set zero-emission target by 2050. That is, of course, subject to a large-scale production of green hydrogen through electrolysis of water with green-based electricity. The bulk of the global hydrogen production is “blue”, i.e. produced by pollutive methods (mainly through methane steaming) and by electrolysis using electricity generated by fossil-fired generators. Against this background, green hydrogen producers are considering various options for encouraging the use of the existing gas pipelines to blend hydrogen with natural gas to decrease its emissions, or using these pipelines to feed hydrogen stations to supply vehicles with fuel cells. In November, New Zealand’s green hydrogen supplier Hiringa Energy announced its collaboration with First Gas to determine whether its existing gas pipelines could be used to feed 100 hydrogen stations to be built across the country by 2030. As the owner of the country’s gas transmission network, First Gas, as reported by View, received a government grant in 2019 to assess the feasibility of transporting hydrogen via its existing gas pipelines. Hiringa has been developing a network of hydrogen production and refuelling stations across New Zealand to feed primarily heavy vehicles. Hiringa’s project will be implemented in three phases during which 8, 16 and over 100 refuelling stations will be established across the country by 2021, 2025 and 2030, respectively. The ongoing Phase 1’s findings are planned to be released in early 2021. Its main objective is to assess the potential for using hydrogen or its blends in different end uses (e.g. heating, transport and power generation). Additionally, the two companies are also collaborating on the potential for First Gas to provide pipeline infrastructure for Hiringa’s hydrogen stations.

Papua New Guinea PNG’s political upheaval added uncertainty about the implementation of the country’s second LNG production facility, including feeding gas pipelines whose specifics are yet to be released. A deal for the US$13 billion undertaking of Total, in association with ExxonMobil and Oil Search, was signed in April 2020. It ran into difficulties when, in the following June, the PNG Parliament passed two bills affecting resource extractions, including oil and gas ones, namely the Mining (Amendment) Bill 2020 and the Oil and Gas (Amendment) Bill 2020. Consequently, many projects needed to be amended over disagreements regarding their terms and efforts to renegotiate them. In November 2020, the mass defection of pro-government MPs and ministers to the opposition created a major political crisis challenging the legitimacy of Prime Minister James Marape. However, he announced a meeting scheduled for December with a Total delegation to discuss the LNG project along with his Petroleum Minister Kerenga Kua, during which the delegation would tell them ‘the exact timeline of the Papua LNG’, according to PNG’s The National.

Whitney Vandiver, Ph.D., NuGen Automation, USA, discusses the risks posed by public disclosure of sensitive pipeline information, and the importance of protecting it against the Freedom of Information Act.


n mid-October 2020, Energy Transfer and Dakota Access filed a lawsuit for the return of confidential and proprietary documents that were handed over to a third-party in compliance with an open records

request. The lawsuit, which names the North Dakota Private Investigative and Security Board and TigerSwan, a risk mitigation and security firm, claims that the disclosure of the records via the Freedom of Information Act (FOIA)


creates a security risk for the pipeline.1 While the debacle surrounding the Dakota Access Pipeline has been longstanding and in the public eye for multiple reasons, the reality of confidential pipeline records being disclosed with little notice is not something to be taken lightly, and this lawsuit is making it clear to operators that they are not always in control of who has access to their records. Operators manage pipelines under the assumption that information they deem to be confidential will stay that way; however, that is not always the case. Federal agencies and legislation have put definitions and boundaries in place to limit what information is disclosed to the public in open records requests, but such limitations are in some cases very specific and in others rather vague. And the pipeline industry’s records do not always fit neatly into the protected categories. This has operators asking the million-dollar question – which records are safe from public disclosure?

Homeland security risks associated with critical infrastructure Because US pipelines are regulated by government agencies, including the Department of Transportation (DOT) and the Pipeline and Hazardous Materials Safety Administration (PHMSA), the FOIA, whereby the public has the right to request records pertaining to government agencies, poses a threat to pipeline security and the confidentiality of some operator documentation. However, recognising the sensitivity of some documentation, the US government has provided exemptions to FOIA requests, some of which have a direct impact on the pipeline industry.2 Beyond these exemptions, however, the status of pipelines within the economy speaks for itself when it comes to the need for confidentiality and security. In 2013, the US government released a policy directive that identified 16 critical infrastructure sectors, naming the energy sector as a primary area.3 Critical infrastructure is defined as sectors that provide systems, networks, and assets that are vital to the security of the US economy and health of citizens,4 and within the energy sector, oil and natural gas are named as two primary segments.5 Emphasising the significance of the oil and gas industry’s role in the economy, the Cybersecurity & Infrastructure Agency (CSIA) states that the country’s “heavy reliance on pipelines to distribute products across the nation highlights the interdependencies between the Energy and Transportation Systems Sector.” 6 In other words, pipelines play a key role in keeping the economy afloat, and it is impossible to separate the success of one from the other, as we’ve seen during the last year of economic downturn and initial recovery. With this in mind, the Department of Homeland Security (DHS) not only identified critical infrastructure sectors but established plans for how to protect these sectors and mitigate their risks in the interest of national security. In the most recent edition of the DHS’s plan for the energy sector, the agency acknowledges that “information on vulnerabilities, threats, and consequences is, by nature,


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sensitive” and that such “information will be strictly protected” given that “the costs of sharing sensitive information could be seen to outweigh the benefits” of a partnership between the sector and government agencies.7 The plan doesn’t state exactly what constitutes sensitive information, and one can easily deduce that it encompasses data surrounding risks and threats. Identifying what cleanly fits this bill, however, can get sticky when it comes to pipeline operations. Moreover, the majority of criteria published by the DHS relates to information shared directly with the DHS, and not everything that applies to the DHS applies to other agencies.

Sensitive Security Information (SSI) The concern for providing more protection of sensitive and confidential records within pipeline operations has been a recent topic for the industry and regulating agencies. In 2017, PHMSA released the final rule for updating 49 CFR Parts 190, 191, 192, 195, and 199. Of specific note was the outlined procedure for requesting the protection from disclosure of confidential commercial information. The subject had many operators and organisations buzzing about concerns regarding commercial information being disclosed to the public despite potentially qualifying as Sensitive Security Information (SSI), which would therefore put their operations at risk.8 However, PHMSA clarified in a comment in the final rule that non-commercial information follows a protocol in which records are reviewed to determine if security protection is required; if so, all federal laws and FOIA exemptions are applied. Following that determination, the DOT and DHS protections begin 9 and in particular FOIA Exemption 3, which “protects information exempted from release by statute.”10 In other words, if a law protects it, FOIA doesn’t apply, and PHMSA looks to other agencies for that guidance. But federal agencies haven’t always been able to clearly nail down what qualifies as SSI, taking more of a “we’ll-know-it-when-we-see-it” perspective. The start of the DHS SSI protections was initiated with the Critical Information Infrastructure Act of 2002 (CIIA). Initially exempting information relating to infrastructure’s vulnerabilities to terrorism, it quickly broadened its scope to “critical infrastructure information voluntarily submitted to the DHS with an express statement of expectation of protection from disclosure.” 11 Soon after, an FOIA exemption was added that protected from disclosure records that would not usually be made available to the public, and the application extended to agencies that shared protected records with the DHS.12 While pipeline operators are more likely concerned with the data they are offering to state and federal auditors, the CIIA’s language sets a precedent for determining what is and is not considered confidential when it comes to national security: “information not customarily in the public domain and related to the security of critical


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infrastructure or protected systems.” 13 The greatest concern with the CIIA’s application to pipelines is that it focuses on security related to terrorism, which in some cases must be proved as a potential consequence of releasing certain documentation. In an effort to provide industry-specific guidelines on this topic, the Transportation Safety Administration (TSA) released regulations regarding the protection of SSI in 49 CFR 1520; however, pipelines are only mentioned once in the regulation as qualifying for SSI if a vulnerability assessment is performed.14 Maintaining the security of pipelines is no small task. From access to field sites and qualified operators working on equipment to access in control rooms and SCADA systems, security is at the forefront of many federal regulations and a constant conversation topic for pipeline operators. Moreover, security is not easily separated from the concept of safety. It is only when security is maintained that the safety of a pipeline can be properly addressed. And when we start talking about safety, it opens an entirely new door to information that is often assumed within the oil and gas industry to be confidential. This information is often shared only with particular organisations such as regulating agencies and, even then, it is often only shared to the extent required by law. Given that not all governmental protections apply to all records that pipeline operators have deemed confidential by their own definitions, what then qualifies as SSI for pipeline operations and how can operators protect the security of their assets in light of FOIA requests?

Pipeline vulnerabilities as a matter of security The TSA’s definition of SSI in 49 CFR 1520.5 is “information obtained or developed in the conduct of security activities” that, if disclosed, would result in several issues, the most relevant to the pipeline industry being threatening “the security of transportation.”15 The regulation states that such information includes, among others, security programmes and measures, security inspections, threat information, security training materials, and critical transportation infrastructure asset information.16 Of particular note here is critical transportation infrastructure asset information, which is collected by PHMSA as part of the DOT during the federal regulation and auditing process for pipelines. As pipeline operators know, when it comes to federal audits, not only is there a great deal of information discussed but often just as much documentation provided to the auditing agency, most of which is considered confidential and restricted even within the operator’s own company. And at first glance, most operators will say everything they provide should qualify as SSI because it is, after all, kept confidential for a reason. While pipeline operational and security data might not fit squarely within the parameters provided by the statutes and federal regulations that address disclosure of sensitive information to the public, that doesn’t mean there aren’t ways to protect it.


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In the Pipeline Security Guidelines released in 2018, the TSA provides criteria for notifying the agency of incidents that are suspected to be an attempt to deliberately disrupt pipeline operations – in other words, terrorism. Among the key incidents is the loss or theft of SSI along with the examples of detailed pipeline maps and security plans.17 However, beyond this, there are few references to what pipeline data is considered SSI, leaving a good deal of the determination up to PHMSA’s discretion and, in some cases, operators’ arguments. In reviewing common operator records, however, there are several areas that one can easily identify as being potential SSI for operators.

SCADA operation and control room management A primary component of pipeline operation that can be argued to qualify as SSI is most data relating to SCADA operation and control room management.18 When it comes to control rooms, PHMSA took the guesswork out of securing the physical space with 49 CFR 195.446 and 192.631, which requires certain safety measures to be used throughout the industry to limit access to the control room and SCADA systems. Restricted access to the control room by key, badge, or pin and individual credentials for SCADA systems to track access are the agency’s expectation for any operational control room, but beyond the physical space, the realm of cybersecurity has come to the forefront of SCADA systems as hackers do more than simply threaten operational safety. Be it isolating the SCADA network, setting up firewalls, or integrating demilitarised zones within the network, operators are working to keep people outside of their control rooms from gaining access to and controlling their field equipment.19 Such security measures and how they protect the control room and SCADA systems are described in various documentation of pipeline operation, including control room management plans, which are required and reviewed by PHMSA. If this information were disclosed as public information, it could compromise the physical security of a control room and virtual security of a SCADA system, and thereby the security of the pipeline assets. This would arguably threaten the security of transportation, especially for larger operators whose loss of supply would be detrimental to the country’s economy.

Integrity management Ensuring the integrity of pipelines is crucial to the safety of personnel, the public, and the environment, which is why federal regulations require regular testing of pipeline integrity. When it comes to maintaining pipelines, the types of product that are moved and the environment in which they are built can affect which regulations apply and how the testing is performed, but the objective is the same: identify potential anomalies that could act as vulnerabilities for a pipeline’s physical integrity. This data must be documented by operators, and in some instances, such as audits or ruptures, agencies will request documentation to review integrity

management procedures and testing results. Because such documentation reveals vulnerabilities in specific assets, this information could be detrimental to the security of an operator’s pipelines if disclosed to the public. Individuals with malicious intent would easily be able to locate the vulnerable pipelines, which amplifies the risk of physical damage being inflicted on the asset in question, to impair operations or harm the local environment. Given the scale of impact that such an incident would have on the safety of the public in addition to operator personnel and the environment, such data should be considered significant to the protection of the transportation industry’s security.

Incident and emergency response Pipeline operators are required by US federal regulation to have procedures in place to respond to incidents as well as emergencies. The complexity of the procedures depends on the situation and the operator and the asset in question, but everything from an unreportable leak or spill to a storm surge flooding an asset must be covered. These procedures are kept confidential because they outline how an operator plans to respond to an emergency, including a physical attack on an asset or hacking of a SCADA system. Moreover, manuals for control rooms must outline where controllers will relocate if the primary control room is impacted by the situation to ensure that operations are affected as little as possible.

If this information were disclosed to the public, it is reasonable to assume that malicious individuals could use the information to anticipate an operator’s response to a terrorism attack, which would further hinder the operator in their response. With a malicious organisation aware of an operator’s planned response, it would put the operator’s personnel as well as the public and environment at further risk by prolonging the operator’s abilities to address the situation. In this way, maintaining the confidentiality of this information is paramount to promote the security of pipeline assets.

Facility response plans As part of US federal regulations, oil operators are required to work to “prevent oil from reaching navigable waters and adjoining shorelines and to contain discharges of oil.”20 In response to this requirement, facilities that run the risk of discharging oil into navigable waterways at such a rate as to cause substantial harm are required to have a Facility Response Plan (FRP).21 FRPs include sensitive data such as emergency notification information, evacuation procedures, potential discharge hazards, worst case scenarios for discharges, facility diagrams, drainage flow paths, and security measures that are currently in place.22 There is no denying that this information in the hands of the wrong individuals would put the asset in question at risk, allowing malicious individuals to maximise their impact if they sought to damage the asset and affecting

the effectiveness of the operator’s response. For obvious reasons, disclosing such data would prove a security risk of great proportions for affected assets and thereby the transportation sector.

Personnel information Many operations manuals and documents include confidential information about personnel. Control Room Management Plans, for example, require contact information for certain personnel so that controllers can easily find it in the event of an emergency. While some of this data is available publicly through the operator’s own disclosure, such as on a website, or via the employee, such as a phone number posted to a LinkedIn profile, disclosing it as part of regulated security documentation creates a different implication. Not only are employees now publicly listed with their role in certain procedures, but information they might have otherwise not made public has now been disclosed. This not only has the potential to cause more risk with regard to personnel safety but could constitute an invasion of privacy, which in some cases would assist such information as being exempt simply by this aspect.23

Understanding and challenging existing protections Pipeline operators know the rules when it comes to federal regulations and auditing agencies, but many are unaware of the impact that FOIA and similar disclosure requests can have on their data privacy. When it comes to legal battles, they often have no choice but to provide the requested documents, but public requests for information do not hold the same weight. Such requests are a protected right of the public, but that comes with caveats and exemptions that have been maintained for the security of the industry. However, even those protections do not always clearly apply to pipeline operational data without some thought and discussion. While some pipeline data would be disqualified by FOIA’s Exemption 3 – and even some commercial and financial information by Exemption 4 – not all pipeline data that operators know should be protected will automatically qualify for such protection. Operators should be prepared to oppose FOIA requests that threaten the security of their assets in a number of ways, including but not limited to appealing by exemption on a case-by-case basis, negotiating data exceptions such as with redactions, or initiating a judicial review challenge for a court review on the basis of confidential or personnel information.24 While not all challenges will be successful, operators should be prepared to make an evidentiary case for why public disclosure of the data runs the risk of compromising security of a critical infrastructure asset and understand that knowing their rights and how the system works for them is the first step in protecting their operational privacy.


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9. 10.


12. 13. 14.

15. 16. 17.








NICHOLSON, B., “Dakota Access Pipeline developer sues state over thousands of unreturned documents.” The Bismarck Tribune, 9 November 2020 Department of Homeland Security. “FOIA Exemptions.” Department of Homeland Security, 26 September 2019. Office of the Press Secretary. “Presidential Policy Directive—Critical Infrastructure Security and Resilience.” Office of the Press Secretary, U.S. Government, 12 February 2013. https://obamawhitehouse.archives. gov/the-press-office/2013/02/12/presidential-policy-directive-criticalinfrastructure-security-and-resil Cybersecurity & Infrastructure Security Agency (CSIA). “Critical Infrastructure Sectors.” Cybersecurity & Infrastructure Security Agency (CSIA), U.S. Government, 21 October 2020. Cybersecurity & Infrastructure Security Agency (CSIA). “Energy Sector.” Cybersecurity & Infrastructure Security Agency (CSIA), U.S. Government. Accessed 13 November 2020. Ibid. Department of Homeland Security (DHS). “Energy Sector-Specific Plan.” Department of Homeland Security (DHS). 2015. sites/default/files/publications/nipp-ssp-energy-2015-508.pdf Pipeline and Hazardous Materials Safety Administration (PHMSA). “Pipeline Safety: Operator Qualification, Cost Recovery, Accident and Incident Notification, and Other Pipeline Safety Changes.” Final Rule. Federal Register, Vol. 82, No. 13. 23 January 2017. PHMSA, Department of Transportation. pdf/2016-31461.pdf Ibid. Department of Homeland Security (DHS). “FOIA Exemptions.” Department of Homeland Security, Freedom of Information Act (FOIA), 26 September 2019. Gina Marie Stevens. “Homeland Security Act of 2002: Critical Infrastructure Information Act.” Report for Congress, 23 February 2003. sgp/crs/RL31762.pdf Ibid. Ibid. Transportation Safety Administration (TSA). “Subchapter B—Security Rules for All Modes of Transportation, Party 1520—Protection of Sensitive Security Information.” Code of Federal Regulations, 49 CFR 1520. Transportation Safety Administration, 1 October 2010. pkg/CFR-2010-title49-vol9/pdf/CFR-2010-title49-vol9-part1520.pdf Ibid. Ibid. Transportation Security Administration (TSA). “Pipeline Security Guidelines.” Transportation Security Administration. March 2018. sites/default/files/pipeline_security_guidelines.pdf HOGFOSS, B. and LITTLE, C., “Pipeline Information and FOIA: What Should Be Protected and How.” wp-content/uploads/sites/24/2013/10/AOPL_Pipeline_ Information _and_ FOIA.pdf WOOLDRIDGE, S., “SCADA/Business Network Separation: Securing an Integrated SCADA System.”, 27 February 2014. https:// United States Environmental Protection Agency (EPA). “Overview of the Spill Prevention, Control, and Countermeasure (SPCC) Regulation.” United States Environmental Protection Agency. ND. United States Environmental Protection Agency (EPA). “Facility Response Plan (FRP) Applicability.” United States Environmental Protection Agency. ND. facility-response-plan-frp-applicability United States Environmental Protection Agency (EPA). “Facility Response Planning: Compliance Assistance Guide.” United States Environmental Protection Agency (EPA). August 2002. production/files/2014-04/documents/frpguide.pdf HOGFOSS, B. and LITTLE, C., “Pipeline Information and FOIA: What Should Be Protected and How.” wp-content/uploads/sites/24/2013/10/AOPL_Pipeline_ Information _and_ FOIA.pdf Ibid.

Brandon Taylor, OneBridge, USA, explores new methods of harnessing Big Data and industry SME input to develop digital CIS surveys.


rom wearables that monitor field technicians’ hydration and fatigue levels to digital twins designed to enhance productivity by replicating real-world processes in a virtual environment, the oil and gas sector is applying digital technology to more and more assets. The goal is to use Big Data to reach business objectives, but the amount of information can be overwhelming — it’s been referred to as a deluge for good reason – and data-driven insights don’t


always come easily. That is especially true for pipeline operators faced with analysing mounds of inline inspection (ILI) data from multiple vendors. Spreadsheets might be handy but reading thousands of rows of data is hardly the most efficient way to parse value from critical information or make confident decisions. While the industry is hopeful that machine learning (ML) algorithms will improve the integrity decisions made using ILI. OneBridge is far ahead of the curve. In 2017, OneBridge introduced Cognitive Integrity Management (CIM), a true SaaS platform built to revolutionise the planning and implementation of Integrity Management Programmes. CIM is the only solution on the market that has harnessed the power of ML to make the most of ILI data, and it is now being extended to include cathodic protection surveys.

Going right to the experts Training the models to analyse input and then make accurate and reliable predictions requires data – and lots of it. Think of it as a never-ending cycle, where generating forward-looking information relies on an ever-increasing

amount of historical data, in this case, a continuously growing database of ILI anomaly examples. In other words, it takes the past to predict the future, existing data to put new data to work. But when you’re creating and expanding the capabilities of a platform like CIM, what’s the best way to acquire the data you need to start off strong and build the framework for the future? OneBridge went right to the source: integrity engineer subject matter experts (SMEs). Chief Operating Officer Brandon Taylor said that when the company launched the first version of CIM in the Autumn of 2017, there was no ‘truth’ ILI data; that is, the industry-specific information necessary for ML such as fields and feature types known to be correct. Integrating a user interface into the solution enabled OneBridge’s partner SMEs to categorise and build up truth data from vendorand tool-agnostic pipe tallies, providing the foundation OneBridge needed to create its first ILI ingestion algorithm. Ingesting and normalising data – that is, organising and standardising the data to make query and analysis easy – is a monumental manual task; just ask anyone who’s tried to slice and dice decades of ILI tally sheets by hand. The OneBridge interface allowed SMEs to enter data in just a matter of minutes. Since then, the CIM algorithm has been trained on more than 5000 data files regarding ILI, geospatial pipe properties, and in-ditch repair. OneBridge is now extracting important information on a variety of integrity topics, including locating interacting threats and understanding how they lead to pipeline failure.

Getting feedback for better performance According to Taylor, feedback, validation, and collaboration are essential as OneBridge continues to scale its CIM solution to address more areas. “We have received very positive feedback from clients and prospective customers with whom we conducted initial research and expect their Figure 1. Under the conditions tab within the Assessment Planning collaborative input to continue as we evolve this module, users can select from different close interval survey conditions. component of our CIM platform,” he said. For example, when the company began the development cycle around data related to cathodic protection (CP) surveys – specifically close interval surveys (CIS) that assess coating effectiveness in compliance with NACE SP0169 – they again sought the expertise of customers and other pipeline professionals. In particular, OneBridge wanted to know how many Figure 2. Cognitive Integrity Management’s Assessment Planning module now incorporates cathodic CIS datasets were already protection survey as a method category. available and in what format.


World Pipelines / FEBRUARY 2021

survey assessments (on/off, on, and depolarised), as well as other methods for verifying the condition of CP coatings: ) Alternating current voltage gradient (ACVG) surveys. ) Direct current voltage gradient (DCVG) surveys. ) Alternating current, current attenuation (ACCA)


Meeting integrity engineers’ expectations

Figure 3. Close interval survey reporting within Microsoft PowerBI embedded.

Taylor said they discovered there wasn’t much existing data depth (it was mostly limited to on, off, notes, latitude, longitude, and elevation), meaning there were few options for aligning it to existing ILI or geospatial data. To overcome these constraints and generate enough data volume to create a CIS ingestion algorithm, OneBridge created a defined import template that most customers and SMEs will use. Alternatively, because CIM automatically synchronises with the PODS pipeline data model, PODS users can push their data directly into CIM.

Incorporating data for CIS surveys The alignment algorithm in CIM is the baseline for ILI-togeographic information system (GIS) correlation within CIM. More than 22 releases of this algorithm have resulted in significant learnings that have facilitated anomaly alignment at the system level for all ILI assessments ever done on a system. OneBridge has now extended the algorithm to include mutually visible assets (for example, valves, casings, and above ground markers) that provide spatial-toengineering stationing (begin/end, m-value) alignment. “Our data science team has been running experiments using CIS data for the last couple of months, with encouraging results, and we are optimistic that adding CIS data to the library of CIM integrity compliance conditions will further our mission to advance technology for the industry with machine learning,” Taylor said. Today, CIM utilises the spatial latitude and longitude coordinates to snap CIS data to the nearest ILI location. CIS measurements are typically taken every couple of feet; the CP Survey process overlays multiple CIS readings onto a single joint of pipe then correlates every corrosion, dent, or crack anomaly that has been aligned pit-to-pit. This allows CIM to overlay corrosion growth rates and anomalous CIS patterns. Where there is sufficient data across an operator’s entire pipeline system, CIM supports and manages data from ILI, PODS, Repair, and CIS that has been aligned at the anomaly level. It provides the metadata pipeline operators need to plan, schedule, and execute the three basic types of CIS


World Pipelines / FEBRUARY 2021

Since its 2017 launch, CIM has been vetted by more than 250 integrity specialists who have integrated it into the IMPs of large, Fortune 500 companies and smaller independent operators alike. Altogether, CIM has analysed more than 50 000 miles of pipeline in approximately three years. The voice of the customer was instrumental in developing CIM and is equally important as OneBridge fine-tunes its CIS analyses. OneBridge learned that integrity engineers shared common expectations: ) They wanted a simple software solution that could help standardise, streamline, and create business process efficiencies. OneBridge has ensured CP Survey can be used in the same, familiar way they use CIM. ) They wanted to access as much data as possible, and

it had to be valid. CIM performs data validation checks on CIS data before it is ingested into the solution. This ensures that all downstream processes are accurate, consistent, and efficient. ) They required scalability. CIM enables loading of both

current and historical ILI data for the entire pipeline system after pre-ingestion data validation has been completed in the onboarding tool, and OneBridge has extended the same capabilities and disciplines to all CIS data. Users can now run many machine learning models and statistical methods against new data to determine if new patterns emerge. ) The solution had to support integrity compliance.

The CIM library currently measures more than 200 compliance conditions for liquid and gas pipelines, with new ones added each time a customer is onboarded. The library includes CFR 192 & 195 regulations, industry best practices, CIM data science and machine learning patterns, and company-specific conditions. All customers have access to the entire library and can conduct what-if scenarios using these conditions. With the addition of new CIS data, this library will continue to grow. Initially, the conditions will incorporate known industry best practices. As customers work through the CIS process, new requests have started flowing into the development queue. For example, one that has already been discussed is corrosion growth where on/off is near zero.

Leveraging the best of Big Data Now that the CIM platform has the capability to ingest and align CIS data, OneBridge’s data science team has developed statistically proven insights and patterns that operators can use in their daily decision-making: ) With 40 ft bins, there is a higher density of deeper corrosion within a region where it appears the on/off voltage difference is close to zero and/or there is a reversal. ) With 500 ft bins, the patterns based on the note

field within the CIS files show an on/off jump when encountering roads, powerline crossings, etc. OneBridge expects this work may further help refine the confidence interval of their alignment. ) There is early evidence that more repairs have been done

when on/off voltage difference is close to zero. ) Plots coming out of the data science experiments show

how GIS (PODS) data correlates to CIS data and provide additional details where specific foreign line crossings overlap with regions of diminished CP protection. Additional NACE SP0502 concepts and calculations will ultimately be incorporated into the overall framework

of the solution. This cadence will largely depend on the priority assigned by users of CIM and the development effort required. The ultimate value of organising and consolidating data into CIM is the enterprise-wide reporting that is made available to operators. CIM utilises Microsoft PowerBI Embedded as the tool to remove the noise and surface the learnings and intelligence needed to make informed decisions. Initially, CIM will ship with two dashboards. Chief Technology Officer, Jordan Dubuc said additional dashboards will become available as SMEs start digging into the results. “The release of this new functionality also serves as a foundational model to accommodate additional data sets in the future, which aligns with the company’s development roadmap,” Dubuc said. Big Data is immensely valuable, but only when it’s managed and used effectively – and leveraged to expand a body of knowledge. OneBridge continually uses the information SMEs and customers provide to guide their data science roadmap. This helps ensure that the new features and functions incorporated into CIM support operators’ daily work, allowing them to predict pipeline failures with greater confidence and to save lives, protect the environment, reduce operational costs, and address regulatory compliance requirements.

Victor Argonov, EXANTE, Russia, provides an overview of some of the world’s largest pipelines and explains how they could support the industry in a post-pandemic world.



il prices have inevitably been affected this year by the world’s transition to greener, more economical energy sources, as well as the COVID-19 pandemic. However, the world’s largest pipelines are continuing to transport fuel all over the world. The second wave of the pandemic has hit the world with full force. In its September report, the International Energy Agency expected global oil demand to fall by 8.4 million bpd in 2020 compared to 2019. Given the worsening COVID statistics in some of the key oil-consuming economies, IEA and other key forecasters (the US Energy Information Administration, as well as OPEC) are likely to revise their expectations for global oil demand down. The near-term demand outlook for the largest oil importers is clouded by COVID-related uncertainty. In 2019, six of the EU member countries were among the world’s 15 largest oil importers. Germany, France, Netherlands, Spain, Italy and Belgium together imported US$190 billion worth of crude oil. Together with the UK, these economies accounted for more than 20% of the total global oil imports. Historically, the oil market has been quite sensitive to relatively small percentage changes in global oil supply and demand. The relatively high share of the above economies in global oil imports explains why the oil prices dropped in response to the news of the recent restrictions in these countries. In 1Q20, global oil demand began suffering from the reduction in economic activity, which started with the COVID-related lockdown in China. In April, at the peak of the first wave of the pandemic, Brent oil price plummeted below US$20/bbl, while the US benchmark, WTI, briefly traded at a negative price. In late April, OPEC+ countries agreed to cut their combined output by 9.7 million bpd in response to the unprecedented demand shock. This restriction was in place in May and June; as of July, as global economic activity rebounded, the members of the augmented cartel switched to a smaller targeted reduction of 7.7 million bpd. According to the April deal, as of January 2021, the combined output reduction target should be cut further to 5.8 million bpd. However, given the recent acceleration in COVID cases in some of the key economies, the release of an extra 1.9 million bpd of oil on the market seems an increasingly bad idea. In late October, the Wall Street Journal quoted its sources that Saudi Arabia will propose an extension in the current level of oil output cuts (7.7 million bpd) into 1Q21. On 3 November 2020 Algeria, which currently holds the OPEC presidency, called for an extension of the current supply cuts. Some OPEC


members are already voicing support for a further increase in the combined oil output reduction target. In spite of this, oil pipelines continue to do well. Below are listed the world’s five largest pipelines, which in spite of the pandemic, continue to pump oil around the world.

Druzhba oil pipeline (8900 km/5530 miles, Transneft)

Figure 1. Druzhba oil pipeline.

This pipeline system starts in the city of Almetyevsk in Russia and splits off into two major branches. One of them goes to Leipzig in Germany, and the other goes south through Hungary into Croatia. It passes through Russia, Belarus, Poland, Germany, Ukraine, Slovakia, the Czech Republic, Hungary, and Croatia. The system was constructed between 1962 - 1981 to deliver oil from the Volga and the Urals into Eastern Europe. Most of the work was completed in the 1960s by the Lengazspetsstroy enterprise. Currently different parts of the pipeline are operated by different companies, depending on the country they are located in. The longest part (3900 km/2420 miles), located in Russia, is operated by the Transneft company. Transneft was founded in 1993, and is currently the world’s largest pipeline operator, with its pipelines totalling 68 000 km, or 42 250 miles, in length. It transports 83% of all crude oil extracted in Russia, and 30% of the country’s petroleum products. According to Reuters, the pipeline’s exports are predicted to fall in 1Q21, as sellers press for higher crude oil prices. However, the pipeline – which is translated to mean ‘friendship’ in Russian – links Russian fields to European refineries and has capacity to pump 1 million bpd.

West-East gas pipeline (8704 km/5410 miles, Petrochina)

Figure 2. West-East gas pipeline.

The West-East gas pipeline was constructed between 2002 - 2015 to transport gas from the Xinjiang Uyghur Autonomous Region in China and nearby Central Asian countries to the highly industrialised southeast regions of China. It consists of three sections, constructed one at a time. WestEast 1 starts in Lunnan, Xinjiang, and goes to Shanghai. West-East 2 starts in Korgas, Xinjiang, and goes to Guangzhou, Guangdong province. West-East 3 also starts in Korgas, but goes instead to Fuzhou, Fujian province. The pipeline is operated primarily by the PetroChina Pipelines company, a subsidiary of PetroChina. PetroChina extracts, processes, and transports oil and gas in China, and is the largest producer of these fuels in Asia. PetroChina was founded in 1999, and during the 2007 bubble it briefly became the world’s largest company by market cap, and was the first company in history to surpass the US$1 trillion mark.

Enbridge Pipeline System (5363 km/3330 miles, Enbridge)

Figure 3. Central Asia – Center gas pipeline system.


World Pipelines / FEBRUARY 2021

This oil pipeline passes through the US and Canada. The Canadian Mainline is 2306 km (1433 miles) long, and the US Mainline, also called the Lakehead System, is 3057 km (1900 miles) long. The pipeline primarily transports Canadian oil to the refineries in Midwestern US and the Ontario province in Canada. The mainline system was constructed between 1950 - 1976, and the parts outside that system were constructed

between 2002 - 2010. The system is operated by the Enbridge company, both in Canada and most of the US. In the US it operates through Enbridge Energy Partners. The Enbridge company was founded in 1949. Like Transneft in Russia, it specialises in constructing pipelines for crude oil, petroleum products, and natural gas, rather than extracting raw materials. The company’s name is a portmanteau of ‘energy’ and ‘bridge’. It operates in Canada, the US, and South America. The company has upgraded its 2021 core earnings and annual dividend forecasts as a result of volume recoveries in its Liquids Mainline System and downstream pipelines.

Central Asia – Center gas pipeline system (5000 km/3110 miles, Gazprom) This gas pipeline system was constructed between 1967 1985 to deliver gas from Turkmenistan, Kazakhstan, and Uzbekistan to Central Russia and neighbouring countries. It passes through Turkmenistan, Kazakhstan, Uzbekistan, and Russia, and is divided into the eastern and western branches. The eastern branch starts in eastern Turkmenistan and goes north through Uzbekistan and Kazakhstan, while the western branch also starts in Turkmenistan, but instead goes along the Caspian Sea, bypassing Uzbekistan. The pipeline includes underwater lines under the Amu Darya, the Volga, the Ural, and the Oka. It is operated by the Gazprom company in Russia. Gazprom is Russia’s largest energy company and Russia’s second company by market cap. It extracts 68% of Russia’s gas, and 12% of the world’s gas. Gazprom owns an even larger share of gas reserves in Russia and the world: 71% and 16% respectively. Gazprom is also represented on the oil market, though to a lesser extent.

Eastern Siberia – Pacific Ocean oil pipeline (4740 km/2950 miles, Transneft) This oil pipeline is located in Russia. It was constructed between 2006 - 2012 to deliver oil from Taishet, Irkutsk Oblast to the oil port of Kozmino near Nakhodka, Primorsky Krai, as well as to China through another section branching off at Skovorodino. The first stage, TaishetSkovorodino (2694 km/1674 miles), was commissioned in 2009, and the second one, Skovorodino-Kozmino (around 2000 km/1240 miles) was commissioned in 2012. The pipeline is operated by Transneft, the same company that operates most of the Druzhba pipeline.

Could China save the day? What’s clear is that several of the world’s largest pipelines supply China in some shape or from. Given that China’s share in the global oil demand is higher than that of the European economies worst affected by COVID-19, strong growth in China’s oil demand could offset the drop in oil demand in those economies. China’s economy is on a healthy recovery path owing to the authorities’ success in the fight with the COVID virus. In 3Q20, its economy expanded by 4.9% year-on-year; the number brought economic growth in the first three quarters of this year to 0.7%, a rare positive number in the pandemic year. As China is the world’s largest oil importer, the current dynamics should be positive for the oil market. In 2019, its total oil imports totalled US$239 billion and made up nearly 23% of the global oil imports.




Yulia Borzhemska, Head of Government Relations, DTEK Oil & Gas, discusses Ukraine’s place on the gas sector world map, including its current strengths and economic prospects. lot has changed in Ukraine in the three decades since independence, both politically and socially. However, one thing has always remained constant: the country’s importance as a strategic energy provider in Europe. In particular, Ukraine’s oil and gas sector has been at the heart of European energy security, and continues to show tremendous potential for further growth as well as opportunities for investment. The use of new technologies and consolidation of international partnerships has driven the success of the Ukrainian oil and gas sector, allowing it to engage in world-class collaborative partnerships. The impact has been immensely positive for the country, its economy and, ultimately, for its people. An indicator for Ukraine’s international significance in the global energy market is the fact that in 2017, the European Federation of Energy Traders (EFET) included Ukraine in its ranking of European gas hubs for the first time. In 2019, Ukraine was also included in the renowned Baker Hughes Rig Count index. A subsequent Baker Hughes report in 2020 listed Ukraine as European leader in the volume of machines involved in oil and gas drilling operations.



None of this is surprising given the country’s large resource potential, which producers have begun to uncover. According to BP Statistical Review of World Energy 2020, Ukraine ranks second in Europe after Norway in terms of proven gas reserves, amounting to 1.1 trillion m3. Also, the country is a leader in terms of R/P ratio, which, at 55.7, is three times higher than the European average.

New impetus from the private sector While public sector companies belonging to the Naftogaz group lead in the distribution and production of Ukrainian gas, private gas producers are providing the sector with new impetus, by utilising modern technologies and steadily increasing gas production in the country. In 2019, private companies both boosted production by 5% and recorded unprecedented production numbers, with the extraction of 4.6 billion m3 of natural gas. For some companies, gas production rose by 50% or more thanks to new wells, as well as the introduction of modern technology. DTEK is a real-life example of such dynamics at work. DTEK Oil & Gas, Ukraine’s largest private gas company, has a share of 36% in Ukraine’s private gas production market. In recent years, DTEK Oil & Gas has more than tripled its gas production. In 2019, the company reached a new all-time high for gas production in the private gas sector, with a total amount equalling 1.66 billion m3. Even better, the company increased the rate of its withdrawal of stocks from 4 - 5% to 15 - 17%, against a 10 - 12% average in Ukraine and Europe. The returns from this growth in production, and its transportation, are providing additional investment for the energy sector.

Investment climate revival as a key growth driver In 2018, Ukraine introduced tax incentives of 6% and 12% on gas production at new wells, depending on their depth. In

Figure 1. DTEK’s Olefirivska gas processing plant.


World Pipelines / FEBRUARY 2021

the two years since the implementation of the tax incentive, almost 200 new wells have been drilled. The following year, Ukraine, for the first time in many years, held oil and gas auctions and PSA competitions. In total, 42 blocks comprising an area of 29 000 km2 were available during the licensing rounds. Open and fair trading of subsoil use permits sparked interest in the domestic market and attracted the attention of international companies, including the Canadian Vermilion Energy, the American Aspect Energy and the Slovak Nafta RV. Of particular interest to the concerned parties is the competition for Production Sharing Agreements (PSA) which is a proven mechanism for attracting investments. The advantages of working under PSA conditions for investors are protection against legislative changes, international arbitration, reimbursement of costs, the large size of the territories provided for use, and the long-term nature of the agreements. The agreements are to be concluded in January 2021. Negotiations are ongoing, with many issues still needing to be agreed. Nevertheless, investors are determined to sign the agreements within the specified period. The international community is closely monitoring the signing of the PSA, as it is an indicator of the investment climate in Ukraine.

One of the world’s largest gas transportation and storage systems Reinvesting the revenue raised from the taxation into the midstream sector has been particularly important in maintaining the competitiveness and development of the broader sector. Ukraine’s gas transportation system is one of the largest in the world, consisting of main gas pipelines, distribution networks, gas storage facilities, compressors and measuring stations. The Ukrainian gas transportation system (UKRGTS) has remained integrated with the systems in Russia, Belarus, Poland, Slovakia, Hungary, Romania and Moldova, through interconnecting pipelines. Moreover, Ukraine has a lot to offer with regards to gas storage. The country’s underground storage facilities have over 14 billion m3 of available storage capacity which can be rented to European partners. Transit capacity from the main gas pipelines in Ukraine amounts to 145 billion m3/y from Russia to EU countries, and around 30 billion m3/y from Russia to Greece and Turkey. However, only 30% of the UKRGTS capacity to the EU is currently used, with the southern capacity faring worse at just 5%. This is because of the launch of Gazprom’s Nord Stream and TurkStream. On top of that, with the imminent introduction of Nord Stream 2, Russia plans to abandon the use of the UKRGTS by the end of

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2024. This will cause a significant shortfall: the current five year contract is worth US$7 billion.

The natural gas transport sector reform was completed in 2019 The UKRGTS operator has earmarked US$1.5 billion in its ten year development plan, to futureproof Ukraine’s pipeline transportation industry. This will largely be spent on the maintenance of critical infrastructure, such as compressors. Simultaneously, Ukraine is devising several new opportunities for UKRGTS. For example, the country insists that Russia opens up the potential of gas transit to Central Asian countries, providing alternative hydrocarbon sources for Europe. Moreover, as a member of the European Clean Hydrogen Alliance, UKRGTS is looking into opportunities in hydrogen transportation. This is particularly important in the context of the EU Green Deal and Europe’s carbon reduction endeavours. In fact, the EU’s regulatory and legislative frameworks have been particularly influential in shaping the development of Ukraine’s gas sector. A good example is that Ukraine completed the reform of its natural gas transport sector in 2019, in accordance with the EU’s Third Energy Package. Experts from EFET are working on an annex to a previous gas trading agreement which will simplify operations for participants. A key element of that reform was the separation of the management function of the gas transmission system from


the state energy holding, Naftogaz of Ukraine, into a new company, the GTS Operator. The gas transportation system of Ukraine is now legally, financially and operationally independent of Naftogaz. Unbundling also occurred along Ukraine’s distribution networks in line with the Third Energy Package, which has increased competition by allowing independent natural gas suppliers to emerge, including DTEK.

EU Green Deal The EU Green Deal will also have a significant impact on Ukraine’s gas sector. Growing political support in Europe for natural gas’ role as a transition fuel in the Green Deal is driving demand for gas. This is opening new possibilities for Ukraine to strengthen co-operation with European and international companies in the field of gas production, storage and transportation. In the face of changing realities, be it through the COVID-19 pandemic or the new energy landscape driven by the EU Green Deal, the Ukraine’s oil and gas sector’s ability to adapt will ensure it remains a leading player in Central and Eastern Europe. Through continued world-class partnerships, and both external and internal investments, the country’s growth is being further strengthened. It is clear that close geographic proximity to European markets, the abundant potential of its subsoil and a wellestablished gas pipeline system means Ukraine continues to be very attractive for potential international investors.

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Guy Dulberger, Ritchie Bros., Canada, outlines some of the steps oil and gas businesses can take to ensure their online operations stay effective.


igital transformation has paved the way for huge technological advancements in the oil and gas industry, but these advancements come with new threats. Last year the oil and gas industry saw a rise in the number of cyberattacks compared to previous years. Research carried out by cybersecurity firm Kaspersky states that the percentage of computers on which malicious objects were blocked grew from 36.3% in 2H19 to 37.8% in 1H20 in the oil and gas industry. At the same time, other sectors saw a fall in cyberattacks. So, what makes some sectors – such as oil and gas – more susceptible than others?


The problem Ritchie Bros. has customers across many industries, including oil and gas, construction, and mining. Although these industries differ, they have some things in common. Firstly, they are wide-reaching, with offices spread out sometimes over many regions, all dealing with individual projects and processes. Secondly, many companies within these sectors were traditionally made up of small contractors brought together. Lastly, many have been slow to join the digital transformation trend – meaning that their digital systems are less advanced than those of other industries. When it comes to cybersecurity, decentralisation and underdeveloped systems are the key issues facing many contractors to the oil and gas industry. Teams are often located in many different places, making companies more vulnerable to cyberattacks and more complex information recovery. The Wall Street Journal reported that, for this reason, construction companies are among the most likely to pay ransoms to restore access to their computer systems. Similarly, TechHQ reported that construction companies are particularly prone to phishing attacks, where criminals seek to obtain passwords or other confidential information fraudulently. Impersonation attempts to extract either money or information are also on the rise. Similar trends can be seen in the oil and gas sector. In fact, according to a recent study by Fortinet, 86% of responding oil and gas companies said they had experienced one or more types of cybersecurity incidents in the past 12 months. On top of this, these already vulnerable systems have been left even more exposed due to the changes in working practice brought on by COVID-19 – with many working from home. A recent study published by cybersecurity firm Malwarebytes claims 20% of businesses have suffered a breach due to a remote worker’s actions since lockdown was introduced.

How to protect your business As technology evolves, so do the threats and the measures we can take to mitigate them, so we make a point of staying up to date with all the latest trends. With hundreds of thousands

of transactions via our e-commerce platforms and tens of millions of visits to Ritchie Bros.’ website made each year, we take cybersecurity very seriously. We have a long-established cybersecurity department embedded in our company over many years to keep our operations and our customers’ data as safe as possible. There are several procedures our customers can implement to reduce risk to their organisations. The first step every company should take is to develop an anti-fraud and data protection strategy with policies and governance for handling detection, protection, and response, and appoint at least one team member to stay on top of emerging threats and the company strategy. There are various legal regulations when it comes to the protection of personal data. Since the EU introduced the General Data Protection Regulation (GDPR) in 2018, all companies operating in Europe must by law report any data breaches and those who do not face large fines. The designated team member could be someone in house, an external consultant, or a combination of resources, depending on company size and preference. Simultaneously, companies should invest in software from a trusted provider and update it regularly as threats evolve. This will ensure they stay protected against malware and ransomware and detect and prevent common email phishing and impersonation scams. Machine learning (ML) and artificial intelligence (AI) can also help with detection and response efforts. While it may seem painstaking at first, a zero-trust security approach, where no one is trusted from inside or outside the network without verification, will soon become an accepted part of your processes and go a considerable way to helping protect your business. Another important consideration, particularly with the impact of COVID-19, is team members working from home or multiple locations. It is usual for oil and gas companies to have people working from the office, job site, or home, meaning the IT network is fragmented. It is essential to educate colleagues on their role as individuals in protecting the company from cyberattacks. For example, for the increasing number working from home, they should ensure their WiFi is secure, trusted antivirus software is installed on their workstation, avoid sharing computers with children or others, remain cautious about the information they share, and with whom. Overall, employees can do a lot to mitigate risks and ensure a company’s online operations continue to function at their best efficiency level.

Stay positive

Figure 1. Caterpillar 594 Crawler Pipe Layers lined up for a Ritchie Bros. auction, North America.


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Transitioning to the digital world opens new opportunities to oil and gas companies. Those who take advantage stand to gain the most. Therefore, it is important not to be scared off by the need for cybersecurity or to focus too intensely on the potential risks. Good cybersecurity is like any other aspect of good business practice. It all starts with awareness and putting actions in place to safely use the powerful technology available today.

Rockwell Automation’s Gert Thoonen, Business Development Specialist, EMEA, details how a digital transformation strategy can help oil and gas pipeline operators and processors improve productivity and reduce risk.


il and gas processors and pipeline operators are well versed in navigating the vagaries that beset their industry. Challenges such as plummeting oil prices, fluctuating demand and the ongoing skill shortages all need to be traversed to ensure that they remain competitive. Their constant quest to maintain their profitability and optimise their operational efficiency to increase throughput are driving them through the digital transformation that is sweeping across all industrial sectors. The core requirements for a digital transformation are to increase visibility of the entire process by enabling access to often disparate and siloed data sources. For process operators, the heart of this is the venerable distributed control system (DCS). As the name implies, the DCS is a system of sensors, controllers, and associated computers that are distributed throughout a plant. Each of these elements serves a unique purpose such as data acquisition, process control, as well as data storage and graphical display. These individual elements communicate with a centralised computer through the plant’s local area network, often referred to as a control network. With the help of a DCS, operators can efficiently coordinate adjustments in a top-down fashion. Although crucial to any digital transformation, the DCS can be one of the biggest challenges that operators face. The trouble is that traditional DCS are based on a closed system, often proprietary design that makes it exceedingly difficult to migrate or modernise. Given that the working life of a gas processing plant could be 30, 40 or even 50 years it is no surprise that there are a huge number of legacy DCS applications that are still in operation. It is estimated that the global DCS installed base nearing end of life totals around US$65 billion, with many of these more than 25 years old and in dire need of updating. When you consider the pressures that operators face, it would appear surprising that there is such a backlog of outdated systems. But the fact is that many of these systems are keeping a plant running, even though it may not be performing at its peak. Given


the tight fiscal situation, many operators attempt to manage the heartache an obsolete system inflicts than be subjected to the perceived risks and costs of migrating to a modern one. Despite this reluctance to disrupt something that is working at an increased failure rate, higher incidence of off-spec product, accelerating maintenance costs, lack of legacy DCS expertise, capacity limitations, and inability to interface with contemporary systems, these all eventually begin to increase the desire to upgrade the system. Although an upgrade can be a complex operation, the modern DCS overcomes the three prime challenges that operators face: increasing productivity; the ability of doing more than less to boost profitability; and the reduction of operational risk. The sheer amount of data that operators face from sources such as supply chains, plant assets, and business systems can drown teams who are attempting to develop increased visibility to facilitate real-time control. To allow productivity increases, operators are searching for methods to increase the visibility and control that they require to decrease unplanned downtime, prevent quality issues, and eliminate waste from production. They are searching for systems that offer them plant-wide automation that can be readily updated to guarantee that the plant remains optimised and in continuous operation. Risk is an anathema to every process manufacturer, but it is ever present in many guises. Even when all eventualities are considered there are unanticipated incidents that can affect safe and reliable plant operations. When causes of risk are identified it is crucial that there are systems in place to enable operators to handle dynamic conditions and make real-time decisions based on dependable data. With these challenges in mind, a contemporary DCS can support an operator’s transition to become The Connected Enterprise as part of its digital transformation strategy. These platforms can reduce the architectural footprint with fewer servers and more powerful controllers, support consistency with native process objects in the controller, streamline workflows with an improved design experience of system attributes, provide robust analytics for real-time decision making, and align with international cybersecurity standards. The result is that a modern system should help producers achieve plant-wide control and optimisation, maximise operations, achieve high availability, reduce costs, and increase production. These sentiments were all part of Rockwell Automation’s thinking in the development of the latest version of its PlantPAx 5.0 DCS. This has been created to positively impact the lifecycle of plant operations with plant-wide and scalable systems to drive digital transformation and operational excellence. Amongst the new attributes are the introduction of process functionality native to the controller, improving the availability of system assets, driving compliance in regulated industries while enabling the adoption of analytics at all levels of the enterprise. Intuitive workflows and the use of industry-leading cybersecurity standards will help teams design, deploy, and support a DCS infrastructure which reduces time-to-market and helps plants realise profit at a faster rate. These new features are step changes in helping lower the overall cost to design and commission. The functionality improves the overall effort to integrate the process control layer to the enterprise. The thinking behind the enhancements is to meet the


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demand from process end users who want a structure that gives them the advantages of a modern experience without the burdens that come with a traditional DCS.

Example of modern DCS at work Working on oil and gas projects across Africa, Asia, and the Americas, Perenco has prided themselves on their ability to develop new business models. One such innovative approach came at the Sanaga gas production operation that fuels the Kribi power station in south-west Cameroon. They rebuffed the traditional option of constructing a fixed gas well and instead opted to develop the world’s first example of a floating liquidation vessel (FLNG) built from a converted ship, the Hilli Episeyo. Operating the vessel requires industrial processes and safety to be controlled from a distributed set of command centres. Its previous DCS was deemed not to be up to the task at hand for three crucial reasons. Firstly, the process and safety elements were misaligned, bringing operational inefficiencies. Secondly, the lack of diagnostic information meant that trained staff were required on site to identify and address issues. Thirdly, the platform lacked the scalability to expand capacity, which was coming under pressure as operations in the Sanaga gas field grew. This left Perenco with a choice: either upgrade the existing system or replace it entirely. Following deep analysis, the company decided to transition from the DCS to an integrated control and safety system (ICSS) connected to its centralised data operations in Douala and Paris. It was clear from the outset that replacing the existing system would not be cheap. Although the ICSS would need upfront investment, the total cost of ownership (TCO) argument was extremely compelling. Working closely with main contractors, ITEC Engineering, Rockwell Automation provided the PlantPAx 5.0 DCS along with the connectivity, via EthernetIP to enable remote access to the FLNG from Perenco’s control rooms. The components of PlantPAx 5.0 were pre-packaged, enabling all infrastructure to be integrated into a global application, thus saving huge volumes of time and engineering costs. By the time of the go-live date, one year after the project initiation, Perenco was able to activate all components in sequence. Within a year of the implementation, Perenco has already enjoyed some important benefits that justify the decision to transition from its original DCS including enhanced scalability, improved integration capabilities, greater simplicity, and better diagnostics. Such is the positive performance that just a year after implementing PlantPAx 5.0, it has decided to replace its DCS entirely and have one fully integrated system across all its operations.

The need for migration With the digital transformation in full swing, eventually every oil and gas processor and pipeline operator will have to embark on that journey. When implemented to its full potential this transformation can deliver a radical evolution for operators. To achieve this revolution producers must evaluate their legacy DCS and judge the benefits that can be achieved by migrating to the latest DCS platform. As producers continue their digital transformation journey, the advances from this system release will help them unlock value and reduce overall costs at all phases of the plant lifecycle.

Deepa Poduval and Michael Nushart, Black & Veatch, USA, discuss the need for operators to take a holisitic view when it comes to selecting the right SCADA system.


s data increasingly drives decisions about infrastructure – or poses missed opportunities for those slow (or unwilling) to maximise data’s inherent potential – pipeline operators are at an inflection point: stay the course with their ageing control assets and take their chances, or invest thoughtfully now in new or updated data-capturing that optimises safe operations. In an industry when reliance on supervisory control and data acquisition (SCADA) is the norm around the globe, many of those systems have aged beyond their effectiveness. Remedying this demands a shift to more holistic thinking when designing SCADA functionality to support the commercial functions of the pipeline, as well as the governing control room management (CRM) that optimises monitoring and handling of such things as pressure, flow and volume. The bottom line: break away from siloed decision-making when setting up a new or replacement SCADA system to identify the various operational stakeholders and have them articulate their requirements, accounting for all moving parts involved. Each business discipline – engineering, compliance, sales, control and measurement, and operations – brings unique requirements, and those fields have varying data requirements from SCADA. Setting aside tribalism for that more inclusive approach – and appreciating that SCADA is not just about CRM – helps ensure a more well-rounded vision of what the requirements should be while adhering to the safety code requirements that may vary by country. Integrating systems, applications and data can enhance processes involving both pipeline control operations and CRM business considerations. Without question, the pipeline industry’s issues are among the highest-profile ones globally. And addressing resiliency through SCADA is close to the top of the list, helping ensure the safe, efficient transfer of gas or hazardous liquids. Rife with complexities, SCADA systems and their outlying pieces enable the functions necessary in controlling a pipeline. SCADA is about telemetry between pipeline components in the field that send data back to an operator who views it on a screen as actionable information. Effective measurement data – about pressure, flow and volume – is critical to the system’s commercial operation, and understanding where and how much product is within the system to ensure that the controller effectively and safely moves that product to where it is needed. The measurement data also is essential for product custody transfer purposes, both into and out of the pipeline system.


Despite that importance, pipeline owners may too often get lulled into complacency, maintaining a SCADA system that may be adequate today without the crucial awareness that it is nearing the end of its lifespan. It’s a mindset that comes with its own peril, both in terms of diminished system efficiency and potentially, public safety. Band-aid approaches to end-of-life systems will buy time but delay the inevitable, making the case for the investment in a systematic overhaul. Advanced planning and research are the keys, starting with taking stock of what other pipeline operators are doing both from information technology (IT) and operational technology (OT) perspectives. Research can then flesh out what is available in the marketplace, and put into tighter focus that the IT/ OT capabilities are improving. The right connection between IT and OT cannot be overstated. OT hardware in the field must be able to integrate with the IT and SCADA software to provide the data needed to ensure safe, efficient product delivery. Diving into replacing a SCADA system is an expensive proposition, but the rewards abound. On the OT side, for instance, operators can get flow control that they may have never had. Plans for improved field measurement and supervisory control need to be considered when planning the SCADA configuration.

Cutting through the clutter For one southern US energy company that provides natural gas and electricity, decision-makers knew their SCADA systems had reached their end-stage and no longer could be supported by the software vendor. Although that vendor did offer an upgrade, that energy company instead sought out strategic support from global energy solutions leader Black & Veatch in defining its objectives from the SCADA upgrade and evaluating the available SCADA solution options to best meet its business needs. While Black & Veatch was not actually supplying the software, the company helped that client cut through the clutter of options, using its expertise in natural gas and electric operations as a consultant that helps clients strategically plan, assess and choose

tailored asset and risk management solutions that are best for their businesses. In many cases, as a recent Black & Veatch white paper on SCADA and CRM finds, pipeline operators and other stakeholders hold a parallax view of the system, each of them looking at the same object but from different perspectives. Such intersecting interests run the gamut, from commercial operations professionals involved in product purchase, sales and supply to issues related to alarm management, control room management compliance, and pipeline control and measurement (Figure 1). Complicating matters is the fact that SCADA software vendors typically focus on software, while companies need a more holistic view to avoid blurring the decision about which option is best. Simplistically speaking, supervisory control through SCADA allows pipeline managers to remotely operate devices, and frequently that is where the vendor’s offerings end, providing screen displays but not always addressing the task of trafficking data necessary for all facets of the commercial enterprise. Review and consideration of existing or required pipeline hardware to fully leverage the capabilities of modern SCADA systems are needed. For example, flow control allows operators to set volume threshold parameters that dictate how many million cubic feet should pass through the system each day or hour – or between specified intervals. Given the interconnection of diverse aspects of pipeline operations, a well-designed and intentional approach to SCADA design and implementation is critical to maximising the benefits from an organisation’s investment in SCADA. To meet today’s multi-faceted business objectives, the following steps are recommended during implementation of pipeline SCADA: ) The enterprise should review its business processes, identifying areas for improvements. ) Define the functional components to address the diverse

stakeholders’ needs. ) Ensure compliance through integration of applicable codes,

standards and recommended practices. ) Establish a design discipline around CRM early in the project. ) Integrate SCADA and CRM data flows to enhance business

processes. ) Develop test cases to validate stakeholders’ needs.

A playbook for operational readiness

Figure 1. There are often intersecting interests when it comes to finding the right SCADA solution. Source: Black & Veatch.


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The essential theme in the discussion of SCADA operational readiness and CRM design is the complexity of requirements to meet all stakeholder needs. While there is a commonly-held belief that compliance rules strictly govern CRM and SCADA design, the pipeline’s primary purpose needs to be considered to fully understand the relationship between the commercial value and purpose of the pipeline and the role that compliance rules play in safe operations. Putting these requirements in perspective and including all stakeholders’ needs will shorten and improve the SCADA-CRM design phase, and ensure that both compliance and operational requirements are met.

Joe Pikas, Technical Toolboxes, USA, explains how decades’ worth of redlined as-built drawings used to be the norm in pipeline construction projects, and how they have been made a thing of the past.

n as-built drawing is a revised drawing created and submitted by a project engineer after a pipeline construction project has been completed. They include any changes made from the initial drawings during the construction process, and provide an exact rendering of the pipeline, valves or other components as it appears upon completion. However, pipelines can be affected


by new construction and relocation, because of encroachment. Technical Toolboxes’ pipeline engineering subject matter expert Joe Pikas was involved in engineering construction back in the 1960s, and like any project, they never went according to the way they were designed for many reasons. These included land issues, right-of-way (ROW) issues and geological issues that affected the ability to put it in the way it was designed due to issues with swamps, etc. Today, pipeline engineers would use horizontal directional drilling to avoid the issues, but back then they could not. As a result, the way the pipeline was drawn on paper did not always work out in real life.

The long-lost era of paper documentation When an as-built was carried out, engineers re-surveyed the entire pipeline and all components and determined how they related to the preliminary drawings, as was originally planned. It was at this point that the red lines began. It soon became apparent that maybe the angle of the pipe was supposed to turn 10˚ to the right and it was actually 12˚ ahead and to the left, or it was supposed to be 10 ft deep and it was actually 5 ft deep. In addition to the main drawings, which were approximately 36 in. long by 18 in. wide, there were also supplemental charts called ROW drawings, which were the size of a regular letter sized piece of paper and had all the crossing locations. The problematic nature of this system of multiple paper drawings was that if a change needed to be marked on the main drawings, it needed to be marked on all of the supplemental drawings too. In the 1960s, pipeline engineers would carry huge books of reduced size alignment sheets around with them in their vehicles to locate specific components or crossings. Usually an entire seat in their vehicle would be dedicated to transporting these books. However, because the books were not updated as and when changes were made to the pipelines, by the mid-1960s their accuracy left a lot to be desired. It was not unusual for a pipeline engineer to know, anecdotally, that a newer parallel pipeline had been installed near an older, documented pipeline but not to have any record of it in the book. By the late 1960s, the physical distribution from Texas to the Northeast US was a long pipeline system with multiple parallel and lateral systems – most of which were not recorded in the engineers’ sheet book.

Speed over exactitude As a young pipeliner fresh out of college in 1967, Joe Pikas worked in New Jersey. It was then, as it is now, the most densely populated state in the US at around 1210 people per square mile, which made it more logistically challenging to carry out large diameter (42 in.) pipeline projects. Consequently, it was normal for the large companies overseeing these types of project to be more concerned with getting the pipe into the ground quickly, rather than taking the time to meticulously track the layout of the pipe. As a result of this attitude, the last


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thing people thought about was these drawings. Back in the 1960s, many pipelines were installed in the US and as the projects accumulated, so did the drawings. The sense of urgency to get pipelines into the ground as quickly as possible to begin making revenue from them resulted in a lack of attention being paid to the drawings. Partly this was because back then, there were no specific regulations requiring companies to keep accurate records of their pipeline layouts. The Gas Rule came out in 1971. As-built, redline drawings, therefore, have always been used in the pipeline industry. As time progressed, computer aided drafting systems were a very good way to manage the mapping system and bring information and changes in from the field. However, there were always new pipeline projects taking precedent over re-locations, re-coating, replacement valves and other changes to the pipeline mapping system. Then a dichotomy began to occur. The regulators required pipeline operators to keep up their respective mapping systems, which included not only these locations, but also the changes or upgrades in the pipe and other components. In the mid-1990s, geographic information systems (GIS) emerged as a conceptualised framework that provided the ability to capture and analyse spatial and geographic data. At this point, pipeline engineers were ‘saved by the bell,’ or so they thought.

The pile in the corner of the room The introduction of GIS caused problems that began to emerge, because they required a lot more information that was never written down on the preliminary drawings and/or as-builts. It turns out that these drawings were not to scale, because the surveyors used the pipe tally sheets compared to what was installed and measured in the field. Therefore, engineering station numbers did not match what was on the surface of the earth. In the company in which Joe Pikas was working at the time, the Codes Group did not keep actual wall thicknesses, but only the minimum requirements for class locations regarding gas lines and road crossing which were different than as-built and tally sheets. The pipe angles were based on the bending angles but were not in alignment of the pipe on earth, etc. For example, the arc radius of a 42 in. pipeline with a 30˚ bend would be very large compared to two drawn lines intersecting each other. However, the real problem occurred when the new GIS manager of the drafting/mapping group asked the question, “What is that stack of old drawings doing in the corner of the room?” One of the mapping guys answered, “That’s about 20 years of redline drawings that were never updated into the system.” This was not a small pipeline system. It had over 10 000 miles of pipeline. That large pile consisted of only the main redlined preliminary drawings and did not include all the small drawings associated with it. The problem was the pile of redline drawings was never redistributed to the people that were involved in it – only the person who worked on the project knew about it. The entire system needed a complete GPS of every line, correcting all the inconsistencies in wall thickness, updating

SansOne PATENTED OPTIONAL: articulated boom to maintain the balance point of the machine



the new components and the system based on the redline drawings. It took several years to move these corrections into GIS. Now, with the requirement for good profile data to determine pipe depth cover for crossings or other engineering assessments, or to assess internal corrosion for liquid/water holdup, etc., this brings another aspect that was not considered during the early days of setting up GIS systems. Today, Technical Toolboxes uses the Pipeline HUB, which gathers, stores, and leverages data in one structured database library, so you can find data and analyse history quickly, to deliver answers consistently and respond to regulators rapidly.

Management of Change In today’s world of regulations, particularly with regulated pipelines, keeping this type of documentation up to requirements goes hand in hand with making it available throughout the organisation. This promulgation of awareness is known as Management of Change (MOC). Today, whenever a change occurs on the pipeline, however small, it needs to be disseminated to everyone involved with it. With the Pipeline HUB and Pipeline Toolbox, for example, users upload data into their pipeline module or application and through the collaborative button, it becomes available to an approved group or specific users. This modern understanding of the importance of MOC is built upon the mistakes of the past – from occurrences when pipeline technicians or engineers couldn’t find the shut off valves in events of leaks or failures, or other vital components, because they couldn’t find the latest drawings or the information they thought was current was actually out of date. In most cases someone in the company redlined the up-to-date information at some point – but it was located somewhere in a corner of a room. At this time, regulators were starting to look at this failure to locate components in the pipeline in time to stop the emergencies that occurred, and initiated a driving force for pipeline companies to change their processes. With the Pipeline HUB and Pipeline Toolbox, users can recall the key asset data and analysis history. Next, users can create reports immediately without jumping through hoops to find the information. Furthermore, the ad-hoc tool allows users to find like components, similar data, or data busts/errors in the entire system within seconds, whereas to do it manually could take days, especially when responding to an audit.

When change is not managed Because population congregates near pipelines in open right of way areas, people tend to build around them, resulting in encroachment. As a result, it is occasionally required to move the pipeline due to the type of building being constructed – such as residential apartments – and many developers will pay for the associated pipeline relocation. During one job, Joe Pikas and his team were performing a typical pipeline survey and were following a pipeline according to its alignment sheets, and suddenly


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discovered a school in place of where the pipeline should be. After a call to the pipeline company’s head office, Joe and his team discovered no one in the upper management of the company knew the pipeline had been relocated except for a remote office. After a further call was placed to the senior engineer responsible for the local region in which the pipeline was situated, they were informed, “we relocated the pipeline and didn’t tell anyone.” Joe’s team subsequently intervened and located, surveyed their pipeline, and created a red line drawing for their files. Today, with The Pipeline HUB and Pipeline Toolbox, users have their asset database and the right engineering tools at their fingertips, so they can quickly make informed decisions based on changing field conditions.

Updating the process Over time, the drafting groups gradually upgraded to newer software – MicroStation, etc., which made their work easier and more automated. Before then, everything was hand drawn and filed in large flat horizontal cabinets. However, some of the original software was clunky and slow and the common complaint was, “I could draw faster than that.” Today, the software has all the information preloaded into it. Now it can tell the pipeline engineer the cost of the pipe, count the number of pipe joints needed; the cost of the valves, and estimates can be performed on the cost of all components. We have moved from a simple drawing of a pipeline to a powerful and complex geographic information system that can tell you the cost per mile of the pipeline and calculate the overall cost of a multi-faceted pipeline project.

A new era of instant, and more accurate information ArcGIS is a geographic information system for working with maps and geographic information maintained by the Environmental Systems Research Institute (ESRI). Today, Technical Toolboxes has graduated to a system where it can tie into the company’s system because every major uses ArcGIS in their systems. This system is designed not just for mapping where the redline is, but for mapping where the components such as valves are located, so they can be identified quickly in the event of a failure or issue on the pipeline. They have a latitude and longitude associated with them and everyone has access to the system – so when someone makes a change (due to pipeline relocation etc.) it is instantly input in a way that everyone knows where it is. In the old days it was done at a snail’s pace and today it is done instantly, and without the need for a team of hundreds of drafts people. The Pipeline HUB can reduce duplication of effort in data mining, data entry, and performing engineering analyses in over 254 oil and gas pipeline engineering applications. Any changes are made across the board and integrate into all the facilities at the same time, meaning important information is instantly at a pipeline engineers’ fingertips.

Peter Routledge, Forth, UK, discusses the development of robotic technology for the internal inspection, repair and rehabilitation of pipelines.


he development of the first ever FSWBot – Friction Stir Welding Robotic Crawler – for internal repair and refurbishment of pipelines, is designed to transform the way industries deal with pipeline issues. This technology has successfully completed its latest milestone on course for trials in 2021. Led by Forth in Cumbria (UK), the FSWBot project has been attracting attention from around the world since being first showcased for its capability in transforming how online crude oil


pipeline robotic internal inspection and repair is carried out. FSWBot is being designed to travel hundreds of miles along an oil pipeline to find and fix any defects while the oil is still flowing. The FSWBot received funding from Innovate UK in 2018 for a consortium led by Forth to develop a ‘proof of concept’ system. Forth is working with consortium members TWI, J4IC, Innvotek and LSBU on the project, which will have a major positive impact on safety within the industry.

The Innovate UK project, which concludes in March 2021, seeks to integrate several state-of-the-art technologies including friction stir welding, milling, patch deployment and ultrasonic NDT, onto a robotic system which can be deployed to conduct repairs on pipelines without the need for the pipeline to be closed down for the duration of the repair. If successful, it is envisaged that the system could be further developed to carry out a range of repair and fabrication tasks. Forth has already successfully trialled the hydraulic system (walking and crawling) using automated controls, and all of its work on the FSWBot fuselage was conducted at its headquarters at Flimby, Cumbria, in north-west England. Collaboration with Forth and LSBU on the controls elements is also on track and was due to be completed in January 2021. The milestones reached on time means FSWBot remained on course for its planned trials in late January/early February 2021.

Friction stir welding Friction stir welding is a solid-state welding process which generates enough frictional heat to soften or plasticise the metal without melting it, allowing metal components to be forged together at the joint line. This system will demonstrate that a patch weld can be made in steel pipe under oil, and that a representative FSW system can be made small enough to operate in a 36 in. diameter export pipe. The FSWBot is envisaged to be a five-segment or six-segment PIG type vehicle which will be Figure 1. FSWBot technology. inserted at the production end of the pipeline and will travel with the oil flow to a pre-designated spot to perform a repair. One segment will carry the FSW machine and a steel patch dispenser, with the other segments carrying the navigation, control system, communications, NDT (non-destructive testing) and power storage/generation payloads. On entering the pipe segment containing the pre-identified defects, the FSWBot will stop, then slowly advance until the FSW system is in place over the defect. It will then lock itself in place and confirm that it is correctly located to perform the repair. An onboard turbine in a duct within the FSWBot will harvest energy from the oil flow within the Figure 2. Forth’s Deep Water Recovery facility at its headquarters in Cumbria, England. pipe to augment any power cells


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carried on the system, with the duct providing through flow in the pipe. Once energised, the FSW unit will deploy a milling tool to cut away the corroded area and prepare a pocket in the pipe wall into which a steel patch will be dispensed. The FSW unit will then weld this patch in place and deploy the milling system again to ensure that the patch is flush with the pipe wall and will not initiate turbulent flow, or impede the passage of subsequent cleaning or inspection pigs. FSWBot will then deploy NDT packages to inspect the weld for quality assurance, before unclamping and moving downstream to repeat the process on any further defects.

Further developments An FSWBot2 is also under consideration for multipurpose repairs and inspections. This innovation would be a very different robot but would build on the learning from the initial development. It would be able to inspect and repair fatigue and corrosion in offshore assets, as well as other subsea infrastructure and applications in other industries. It will be able to climb and walk, and will be deployed from a system which has the ability to lock onto a structure. FSWBot and its future developments is one of the latest in a long line of innovations from Forth, which have been designed and manufactured by the business ever since it was first founded in 2000. The company has grown over the last 20 years via its specialism in the commercial provision of bespoke harsh environment solutions to a range of industries, including R&D, testing, installation, commissioning and maintenance of bespoke robotic solutions, in – among others – the oil and gas and subsea industries. It offers a range of solutions to meet clients’ needs including robotics, remote handling, machine vision, 3D digital asset capture, use of VR, AR, AI, ROVs and the provision of specialist services, including bespoke systems in the offshore oil and gas sector for companies such as EM&I, Total, and Petrobras. The company also supplies, installs and services hydraulic systems, mechanical engineering systems, robotic and remote handling systems and bespoke engineering. Mark Telford, Managing Director of Forth, said: “FSWBot will be another world-first for Forth and another example of where an industry has a specific challenge and has asked us to come up with a solution. “At Forth, we take that process all the way from concept to manufacture, designing, manufacturing, demonstrating that solution, substantiating the product, implementing, and if necessary, maintaining it. “We work collaboratively and are very open to working with other businesses and organisations, who are experts in their own field, to deliver a safer, faster and cheaper solution for industry. “We also offer rapid prototyping whereby industry has an immediate problem and we can quickly design a solution from a concept and prove that approach can fix the problem. We can then continue that process through


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full design and manufacture, and offer substantiation to the point that the product passes all the necessary certification tests, qualifications and legal requirements to do that task. “We can then implement the technology and offer ongoing maintenance support.”

Underwater testing Forth is able to test underwater technology and innovations in its bespoke Deep Recovery Facility at its Cumbria headquarters. At 22.5 m long, 10 m wide and 6 m deep, and holding 1.2 million l of water, it is one of the largest wet test facilities in the UK. The covered, freshwater pond, built as part of a £1.25 million investment, allows businesses from a range of industries, including oil and gas, marine, nuclear and renewables, to carry out their research and development. It is used by Malta-based EM&I group, an industryleading global organisation providing support services to the oil, gas and energy industries. Peter Gresty, Equipment and Training Manager for the EM&I Group, said: “The pond at Forth is ideal for us. We use it to carry out many aspects of our technological development. The facilities at Forth are unique and we really value being able to use the pond as it helps us to be innovative and stay ahead of the game when it comes to our technical development.” Mark Telford says there’s scope for other businesses and organisations to be making use of the facility. “As well as wet work, there’s an area for dry work as well, so it’s ideal for companies and organisations to use for testing equipment, or for divers, or any business or organisation involved in underwater operations. It is the perfect place to test new technology. “We also have conference rooms for companies to use while they are here testing their equipment so it means they can be time-efficient while they are on site.” Forth recently hosted a demonstration at the Deep Recovery Facility of an Autonomous Aquatic Inspection and Intervention (A2I2) underwater robot set to transform the way a range of industries carry out inspections and maintenance. The consortium, led by Rovco, and including Forth, D-RisQ, the National Oceanography Centre (NOC), Thales UK and The University of Manchester, is developing world-leading technology for use across multiple sectors, including offshore wind, nuclear, and oil and gas, which aims to improve safety by reducing risks when working in challenging and hazardous environments. A second demonstration is now being planned to be hosted by Forth at its Cumbria headquarters in March 2021. Forth’s HQ also recently hosted several demonstrations by EM&I which were live streamed to different time zones across the world to show the latest innovations in technology being developed for the offshore oil and gas industry. To fast-track other collaborative solutions, Forth is developing its base in Cleator Moor in Cumbria as an innovation hub, where products such as FSWbot will be further developed.

Bryan R. Kirchmer, Aegion Coating Services, USA, explains how advances in remote-controlled robotic technology are improving the quality of internal field joint coatings.

ipeline owners can implement several effective strategies to manage pipeline corrosion and prolong a pipeline’s service life. The traditional strategy features the products’ ongoing chemical treatment moving inside a ‘bare steel’ pipeline with corrosion inhibitors, biocides and anti-scaling chemicals. Internal coatings are now receiving recognition and proving to be a more effective and cost-efficient strategy compared to chemical treatment alone. Owners who elected to apply a layer to the inside of their pipeline have experienced reduced operational costs versus a chemical treatment strategy. Now, leading oil and gas EPC companies complete life-cycle cost analyses comparing chemical treatment alone versus internal coatings with a supplemental chemical treatment to minimise corrosion cost over the asset’s life. The internal coatings can yield several promising benefits: a return on investment within three years, reduced operating expense, lower life-cycle cost than chemical treatment alone, and better flow characteristics, thereby reducing


the power demands by as much as 15%. In summary, owners can save millions of dollars over an asset’s life by turning to internal coatings as a corrosion strategy. The owner selects the internal coating system’s selection during the design phase due to the fluid composition and other design parameters. While considering the fluid composition’s corrosivity, the spectrum ranges from very low to extremely corrosive. Somewhere along the spectrum, there is a scenario in which internal coatings are preferable to the chemical treatment and corrosion allowance, just as a strategy exists. The use of a corrosion-resistant alloy, CRA, becomes preferable. The determining point at which internal coatings become attractive should consider reducing operating expense, due to reduced chemical treatment combined with increased capital expenditures. Internal coatings proved difficult to adopt in the past due to the scarcity of adequate coating materials and the inability to coat the internal field joints with the same level of quality as the line pipes at the coating plant. However, these barriers no longer exist, and current technologies have cleared how to use coatings as the primary corrosion strategy for a pipeline interior. The line pipes (generally 40 ft in length) are coated at coating plants in a controlled environment with good quality control. Then, the line pipes are welded at the site, and the field weld joints (girth welds) are coated at the site.

The internal coating system’s effectiveness depends largely on selecting a proper coating material, high-quality coated mainline pipe, and proper on-site application of the field joint coatings. During the onshore construction of an internally coated pipeline after the trench is completed, externally and internally pre-coated segments of the pipe, usually 40 ft in length, are transported from stockpiles in the staging area to the right-of-way. Pipes are laid aboveground next to the trench or within the trench on top of supportive sandbags in steep terrain. Individual pipe sections are bent using pipe bending equipment, enabling the pipeline to follow a planned route and the terrain. The pipe sections will then be welded together, sandblasted, and the external weld joints coated with epoxy to prevent corrosion. The pipeline is assembled in strings up to 1 km in length, and at this stage, the ACS Robotic equipment is placed into the pipe string to travel to each internal field joint and carry out the five subsequent steps.

Pre-coat inspection This step incorporates a visual inspection of the uncoated field joint through a high-resolution video image combined with a three-dimensional scan of the weld performed by an onboard laser. An experienced technician reviews the twodimensional video and any suspect areas identified by the laser scan algorithm.

Cut-back and weld repair There is typically 2 - 3 in. from the end of the uncoated pipe, referred to as the ‘cut-back’, that keeps coating far enough away from the weld/heat-affected zone during the welding process. Suppose a weld anomaly or contamination site is identified in the previous step. In that case, this step uses equipment capable of repairing many of the anomalies that historically required the joint to be cut-out and the welding process to be repeated.

Cleaning/substrate preparation Figure 1. ACS 12 in. RC Robotic equipment train for internal field joint FBE coating application.

Once the cut-back and the girth weld have passed the review for coatability, this step uses a centrifugal grit cleaning unit to lightly clean the cut-back and apply an anchor profile to the girth weld. The equipment features an onboard vacuum system to ensure the joint is clean and dustfree. Upon completing this step, the field joint has now been verified for coatability and is ready for the coating application.

Material application This step is a critical point where either a fusion-bonded epoxy, FBE, or a liquid epoxy is applied to the field joint. The liquid epoxies have a two-part composition that, once mixed, have a finite pot-life and require time to be managed in connection with the application of the material. Figure 2. Aegion Coating Services internal field joint coating crew upon completing over 20 000 robotically coated field joints on an offshore project.


World Pipelines / FEBRUARY 2021

Post-coat inspection Once the applied field joint coating has cured, field joint needs to be inspected for any holes in the layer, referred

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to as ‘holidays’, and to check the ‘dry film thickness’ in several areas to validate the coating thickness is within a prescribed range. The process requires the harmonious synchronisation of: ) Wireless communication.

currently developing new equipment infrastructure that combines enhanced communication capabilities with greater energy density, enabling advanced payload options to expand available robotic services for pipelines. A technician operates the robotic equipment with a proprietary wireless communication system that features an ) Onboard power supplies. impressive data exchange rate over a long distance inside a pipe. Precise control of the equipment requires data transfer ) Control systems to precisely move the internal robotic that is as close to real-time as possible. Too much latency equipment to each field joint at a depth up to 1 km in the causes errors in controlling the precision equipment. It can pipeline and successfully execute each payload function. be a challenge when the equipment is required to transmit a large amount of data acquired from the payload over a Many advances through the years in each of these long distance inside a carbon steel pipe without losing data areas have contributed to the high-performance level and integrity. consistent quality results expected from the equipment Improvements in the wireless communication system, fleet. These advancements have helped deliver unparalleled new payload offerings, and the desire to travel a long consistency and validation of quality field joint coatings distance inside the pipeline have increased the power to pipelines worldwide. Aegion Coating Services (ACS) is requirements necessary to operate the equipment. Due to recent advances in battery technologies, ACS has incorporated battery packs that feature an increased energy density. The energy density (Wh/kg), the amount of energy stored per unit mass (kg), and corresponding power density (W/kg) means the amount of energy flow per unit mass (kg) per unit time (s), like a water tank with the fixed tap at the bottom. Energy density can be thought of as the water tank’s volume, and power density as the water flowrate from the tap. The ACS robotic unit’s onboard control system has been overhauled to allow for easier integration of new payload devices. This system has also simplified the traffic required to trigger, acquire, and communicate data to and from the onboard components. Figure 3. Left: two-dimensional image from a video feed. Right: The advances in wireless communication, battery power, the dimensional data captured by a laser scan. The scan data and the control systems have enabled ACS to begin adding shows that the area highlighted by the arrows from the image on the left has more than 6 mm of excessive penetration, well payload offerings that were not available in the past due beyond a coatable limit. to power constraints and the inability to transmit large volumes of data with low latency. The new payload options will further expand the repertoire of available features providing the benefit of faster cycle times for contractors, automated inspections, and better internal field joint coating reliability for owner companies. ACS developed the first robotic field joint coating equipment over 30 years ago, and the technology has continued to evolve rapidly over the last three decades. The ACS fleet of remote-controlled robotic equipment can remotely control and robotically coat over 50 000 internal field joints every year for pipeline diameters ranging from 8 - 60 in. ACS plans to deploy its internal coating equipment to work on projects in six countries and multiple offshore locations in 2021. The strategy to deploy internal coatings for an effective corrosion strategy is expanding as a cost-effective solution for owners creating a more competitive market and pushing leaders to innovate. ACS remains the pioneer in this Figure 4. Left: ACS technicians monitoring the operation of robotic critical area and, through innovation, will continue as the equipment onboard an offshore barge. Right: ACS technicians preparing to insert the pre-coat inspection equipment with laser scanning industry leader for providing RC robotic internal field capabilities into an 8 in. pipeline being constructed on an offshore barge. joint coating services.


World Pipelines / FEBRUARY 2021

Dennis Janda, ENTEGRA, USA, discusses how cathodic protection current mapping can help to reveal costly blindspots.


o you know your pipeline? Do you know where all the current sources and current drains are located? Do you know how far upstream and downstream each source protects? Do you have any confidence about the coating condition of your pipeline from end to end? If you had a run beneath the Mississippi River and 10 000 ft of cathodic protection had been lost, would you know it? This article will outline how new cathodic protection current mapping (CPCM) technologies can give pipeline operators reliable information, where and when they need it.

A new way to collect and manage data Adoption of new technologies within the pipeline cathodic protection industry has historically been slow moving. There might be new technology available when it comes to collecting data, but the data we are collecting is still the same old data our fathers and grandfathers


collected. We, as an industry, are still heavily reliant upon pipe to soil potentials to assess the effectiveness of our CP systems. The truth is that pipe to soil potentials alone do not always reliably and accurately answer the above questions about the effectiveness of our CP efforts.

Figure 1. CPCM current graph.

Current is the key Do pipe to soil potentials protect our pipelines from corrosion? No. It is current that protects the pipeline. Pipe to soil potentials are created by the current. So, if it is the current that is actually protecting our pipelines, why have we not been monitoring the current instead of the potentials for all these years? The answer is that we never had a practical way to do so other than occasional spot checks like current spans or bonds across insulating flanges. CPCM is designed to change this. The basic premise behind inline CP current mapping is one that all corrosion professionals are very familiar with. The CPCM tool measures voltage drop in the pipe wall and converts this value to current. It is just like measuring current with a shunt; in this case the resistance is the pipe itself. The resulting line current value is plotted against pipeline footage for a detailed map of current distribution for the entire pipeline. This not only provides information about the current direction and magnitude on the pipeline, it also reveals each current source and/or current drain on the pipeline. This confirms the locations that are regularly monitored, but also shows those locations that operators may be unaware of. To protect pipelines from external corrosion, and thereby protect people and the environment, operators must know their pipelines.

Operation of the CPCM tool

Figure 2. CP current distribution.

Figure 3. 16 in. CPCM inline inspection tool.


World Pipelines / FEBRUARY 2021

The CPCM tool operates mechanically like most other ILI tools in that it is propelled through the pipeline by the flow in the pipeline. While most other ILI tools are looking for metal loss or cracking, the CPCM tool is measuring the voltage drop in the pipeline wall. These voltage drops are caused by the CP current collected by the pipeline at coating anomalies and the subsequent flow of this current up or down the pipeline to its current source. These voltage drops are converted to current values using a simple Ohm’s Law calculation in ENTEGRA’s proprietary software and plotted against pipeline distance. This is a truly high-resolution tool, in that hundreds of these voltage drop measurements are recorded per foot of tool movement down the pipeline. It provides a detailed map of how the protective CP current is distributed along the pipeline length, the magnitude and direction of this protective current, as well as the location and amperage of each current source or drain (Figure 1).

CPCM win

you confidence about your system’s protection, do you A CPCM inspection can often reveal information about have all the required knowledge to ensure accurate your pipeline that conventional above ground inspections interpretation and understanding of the survey results? might miss. Figure 2 depicts such a scenario. Are you 100% confident that every current source and The CPCM tool indicated an undocumented bond just drain that has an impact on your pipeline is accounted for a few hundred feet downstream of the launch at what a and interrupted for a true IR free potential? If you do not previous MFL inspection called out as a near metal object know where they all are, you cannot cycle them. at 12:00. Field verification found this to be a bare water Do you know what the coating condition is for the line touching the target pipeline. This short was draining entire pipeline? Do you know how much footage of your 3.8 amps back to the target pipeline. A 73 amp rectifier pipeline each rectifier protects? can be seen in Figure 2, at approximately 12 000 ft. CPCM can answer all these questions, and give This high output rectifier only protects upstream operators an easy to understand map of the magnitude approximately 2000 ft to a valve set. As evidenced by and direction of every amp of protective current that a the graph, the pipeline has almost no current pickup pipeline has received from its CP system. or current flow from the undocumented water line short to the valve set at 10 000 ft. The pipeline operator had been recording adequate pipe to soil potentials at this valve set, and at the launcher. Data analysis determined that there was an insulated flange on the upstream side of the valve preventing the 73 amp rectifier from protecting upstream of this valve. Field verification determined that this was in fact the case. The insulated flange had been bonded across in the past but this underground bond was found to be broken. The result was that approximately 10 000 ft of pipe upstream of the valve was not receiving protective CP current. This 10 000 ft section of pipeline happened to be underneath a major river. Pipe to soil potentials on each side of the river gave the operator a false sense of security that the river crossing had adequate Maintaining a pipeline is no easy task. With so many things to worry current to provide protection, about, you need products you can depend on. Always. Our solid-state when in fact it did not. decouplers help improve your cathodic protection system’s performance and stand up to AC faults and lightning strikes, in all sorts of conditions. Why CPCM? We make them rugged so that you can trust them to perform. Always. Why would a pipeline operator choose to spend money on a Applications Include: technology that is not a direct • AC Voltage Mitigation replacement for a tried and • Insulated Joint Protection true method of inspecting their • Decoupling Equipment pipeline system? The answer Grounding Systems • Gradient Control Mat Isolation is knowledge, which is key to making better integrity decisions. Learn more about our If you are solely relying Always Rugged Promise: on annual pipe to soil surveys and an occasional CIS to give

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Nicholas McNally, Decom Engineering, Northern Ireland, looks at how the company’s decomissioning solutions can maximise the potential of pipeline repurposing and recycling.


ith 7500 km of pipelines to be decommissioned over the next 10 years in the UK and Norway alone, there has never been a better time to explore how these pipelines can be removed and recycled in a way that minimises carbon footprints and encourages the reuse of such highquality steel tubulars. Since its establishment in 2011, this has been the core mission of Decom Engineering – developing innovative solutions for decommissioning that carry a positive environmental impact.

Remove and recycle There are two aspects to this problem - initially how to remove pipelines in a way that is cost effective and results in minimal damage, thus allowing maximum potential for reuse, and then crucially, to find a valuable way to repurpose or recycle it.

Clean removal One of the biggest challenges we have seen with the cutting of pipelines is the efficacy of cutting apparatus subsea and the ability to make multiple cuts on a single deployment.

For example, if hydraulic shears are utilised then this means the pipe ends are crimped, making it harder to inspect, decontaminate and reuse or recycle. Decom has developed a solution to avoid this – a single blade chopsaw with a tungsten carbide tipped (TCT) blade that can clamp through sediment and make a fast (circa 32 min. on 16 in. OD, 45 mm WT, L80 grade material), clean cut of the pipeline (Figure 1). By utilising this method, Decom is able to offer a solution that can be ROV, crane or excavator operated and makes a fast, clean cut through the pipeline whilst the versatile clamping system allows easy movement through various sizes without the need for re-tooling. Additionally, thanks to the longevity of a TCT blade, many cuts can be made before the need for re-tooling on the surface. If the material has concrete around it or other casings or materials to be cut, then Decom has an interchangeable cutting head and motor that can be swapped in that utilises a vacuum brazed diamond blade in a high-speed low torque setup. This is ideal if concrete or umbilicals in the vicinity of the pipeline need removal or repair during the decommissioning process.


With decommissioned pipe coming out in clean cut sections, internal probing and testing for decontamination work can continue unobstructed leaving coated pipe that is

easily handled. The Decom chopsaw achieves this clean cut as seen in Figure 2, making inspection easier and safer. As a summary, utilising the Decom Chopsaw for pipeline removal has a number of advantages: ) Can cut a range of sizes with one setup and be changed for size without coming out of the water (Figure 3 shows Decom’s subsea model with ROV handles). ) Safe clamping mechanism. ) Reverse cut mechanism to cut out of materials where

needed. ) Interchangeable from solid metal cut types to umbilical

style cuts by changing motor and blade type. ) Low consumable costs (10 - 30 cuts per blade, before a low

sharpening or re-tipping cost compared with 1 - 2 cuts for a diamond wire). ) Comparable cut times. ) Smooth cut finish compared with shears which crimp the

cut area thus enabling repairs. Figure 1. Decom Chopsaw excavator mounted for decommissioning a quiksilver gas pipeline.

) Unfortunately, a large barrier still remains - the original

pipe coating.

Coating removal As the scale of pipeline decommissioning increases, the question of what to do with a coated pipeline that has lived its useful life in the ground or underwater is becoming ever more urgent. A coated pipe may be able to be reused as an agri-roller, but other options for resale are very limited. The increase in pipe supply therefore presents a real risk that decommissioning yards will be overrun with decommissioned pipe. As the pipes cannot be effectively recycled with the coating as this contaminates the process, the only viable solution is to remove the coating. Existing solutions for this process are slow, costly, unsafe for operators, environmentally unfriendly, and poor quality. For example: ) Excavator removal – there are some pipe stockists who have developed their own removal attachment for an excavator that acts as a scraping method. This method only works for tar/bitumen coatings unless the pipe is heated up, in which case it can work for 3-layer PE. However, this is slow, expensive, and could damage the pipe. ) Water jets – this method is relatively effective from a

speed perspective but is prohibitively costly as it requires a lot of power. It is also dangerous and environmentally damaging as chemicals leak out through the water escape. Figure 2. A clean cut pipeline using a Decom chopsaw making inspection simpler and safer.


World Pipelines / FEBRUARY 2021

) Simple lathes – some companies have developed a

simple lathe machine that works to remove just the PE

(not the adhesive and PE) but these are very slow, unsafe and are not scalable. ) Reverse heating – pipe manufacturers can remove the

coating only by shutting down their entire plant and reversing the pipe through the heating process for putting the coating on – this is expensive in terms of energy usage, opportunity cost and once again is an environmentally damaging option. Decom has provided an innovative solution to this problem by developing a pipe coating removal system (Figure 4) that utilises a cold method to remove both coatings (FBE/PE) whilst avoiding any damage to the pipe. Specifically, the machine has: ) A multi-tool station, typically 3 - 8 tools, which will process all pipe coated between 4 - 60 in. diameter and 6 - 24 m in length. Average processing speed is 70 m2/h.

Figure 3. C1-24 Chopsaw with ROV setup.

) A waste collection and disposal system using onboard dust

extraction and collection conveyors for PE/PP. ) Achieved a pipe surface that is left 100% clean of all

coatings and welds can be NDT tested (Figure 5). The Decom machine can be easily installed anywhere in the world limiting the additional movement of decommissioned pipe as the carbon footprint of moving pipe, more times than necessary, far exceeds that of moving the machine. Additionally, Decom is able to recycle the captured PE coatings to further improve the green lifecycle of the pipelines.

Reuse or recycle At the end of this process are cleaned steel tubulars thus allowing for the reuse of the pipeline in the most economical and environmentally friendly manner. For example, the pipeline can be re-tested and then utilised for piling in the construction industry (Figure 6), reducing construction costs and carbon footprint and increasing availability compared to ordering brand new steel tubulars for construction. The use of surplus steel in construction and infrastructure projects can deliver huge savings on carbon emissions and be a key part of the ‘circular economy’. Cleveland Steel in the UK prepared an independent research report outlining a comparative analysis of the environmental impacts of reused coated steel tubes against a benchmark of how these compare to prime steel welded tubes.1 Cleveland found that there are no technical, legal or practical reasons that steel tubulars cannot be reused/ repurposed. Over the last 40 years, these products have worked very well where cost effective testing exists to prove material properties and traceability, as this shows they are at least as good as new (prime) products. Carbon savings of reusing steel tubulars was found to be between 95 - 97% compared to using prime steel tubes by Cleveland Steel. This is significantly more favourable than recycling the steel as scrap for new tubes as recycling old tubes back into new tubes present significantly lower environmental benefits.

Figure 4. Decom Coating Removal Machine giving pipe a new lease of life.

Figure 5. Decom Coating Removal Machine cleaned pipe visual.

The commercial rationale The commercial rationale for buyers of the pipe is based on a mixture of cost, regulatory, and brand perception elements. In particular there is growing pressure on the construction industry to be more resource efficient, reduce waste, and to lower embodied carbon impacts. More recently, circular economy concepts are being promoted, particularly at the EU level, with

FEBRUARY 2021 / World Pipelines




3X Engineering




Aegion Corporation




Figure 6. Recycled steel tubulars for use in marine construction.






Electrochemical Devices, Inc.


Girard Industries


Integrity 2021


Intero Integrity






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a roadmap developed to support a shift towards a resource efficient, low carbon European economy. Increased structural steel reuse will support both of these aims and stimulate new business opportunities in the UK in particular, by substituting steel imports. Although new steel and scrap steel prices are volatile, analysis reveals that the long-term price (2000 - 2016) differential between the cost of UK structural steel and scrap sections is over £300/t. This represents the potential profit opportunity through structural steel reuse. Although additional costs (relative to recycling) will be incurred through deconstruction, testing, storage, re-fabrication etc., structural steel reuse can yield cost savings or at least provide an economical feasible alternative to the use of ‘new’ structural steel.2

What about surplus pipe?

OneBridge Pigs Unlimited International, LLC

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It is important to note that we often find that surplus pipe from projects that never made it into a pipeline and have been downgraded, can struggle to find a new home. This pipe is also ideal for coating removal and can be a great way of recovering costs from pipes that remain unused for any reason.

Safer, cheaper, greener - let’s go Specifically, by using a Decom Chopsaw and a Decom Coating Removal Machine to complete the removal and cleaning, the following benefits will be achieved: ) Safer and more cost-effective removal of pipelines. ) Cheaper and more environmentally friendly cleaning of

pipe coatings. ) Reuse of the structural steel within the economy, reducing

costs and carbon footprint. SCAIP S.p.A.

Bound insert



References 1.



Winn & Coales

OFC, 9

World Pipelines



Cleveland Steel & Tubes Ltd, ‘Life Cycle Analysis (LCA): recovered and refurbished coated steel tubes’. SCI - The Steel Construction Institute, ‘SCI P427 - Structural Steel Reuse: assessment, testing and design principles’, October 2019.

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