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03. Editor's comment
05. Pipeline news
Updates on H2Med pipeline, EACOP and the Ruby pipeline acquisition.
KEYNOTE: NORTH AMERICA REPORT
10. Projects in the pipeline
New pipeline systems for CO2 sequestration and green hydrogen products offer significant opportunities to midstream companies in the coming decade, suggests Gordon Cope.
PIPELINE INSPECTION/PIGGING
39. Down to the last detail
Andro Jimenez, Coordination Manager and Edwin Carbajal, Senior QC Coordinator, Fulkrum, USA.
43. Featuring Italmatch Chemicals
We ask Adam Brown, Technical Sales Manager, Italmatch Chemicals, UK, about pipeline pigging.
REMOTE OPERATION
45. The rise and rise of IoT Adam Weinberg, CTO and Co-Founder, FirstPoint Mobile Guard, Israel.
48. Propelling advancement Morgan Bowling, Industry Principal, Seeq, USA.
15. Simplified protection
Julie Holmquist, Cortec® Corporation, USA.
CORROSION CONTROL
20. Corrosion control for refinery pipelines
Ali Alani, Director of Asset Integrity – Europe, Penspen, UK.
25. A low carbon emissions alternative
Antonio Caraballo, Inspection & Integrity Management Services Director, ICR, UK.
CORROSION CONTROL: MIC
29. Bacteria busting secrets
Reza Javaherdashti, MICCOR, Netherlands.
33. Monitoring oilfield pipelines
Susmitha Purnima Kotu and Jose Vera, DNV USA, Sven Lahme, ExxonMobil Corporation, and Sam Rosolina, Microbial Insights, Inc.
53. Altering offshore operations Ross Macfarlane, Fugro, UAE.
PIPELINE MACHINERY FOCUS
55. Pipelayers Brandt Equipment Solutions, Canada.
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Featured in our news section this month (starting on p.5), is the news that Germany has joined the Mediterranean hydrogen pipeline project. Germany joins its neighbours France, Portugal and Spain in the €2.5 billion H2Med project, which will deliver green hydrogen from the Iberian Peninsula, under the Mediterranean Sea, to the rest of Europe. Expected to be in operation in 2030, the ‘BarMar’ pipeline between Barcelona and Marseille will be capable of transporting 2 million tpy of green hydrogen from Spain, becoming the first ‘green corridor’ in Europe.
H2Med opens up a way to transport renewable gas by sea. By 2050, it is estimated that 20% of all energy in Europe will be renewable hydrogen. Green hydrogen is created by water electrolysis, in a process using renewable energy.
Announced at an EU summit in October 2022, H2Med offers an alternative to the partially built, now abandoned, MidCat pipeline project, which was to have carried natural gas across the Pyrenees from Spain to France. MidCat was cancelled after significant environmental protest, and after Spanish and French regulators rejected investment requests for the project over profitability concerns, and worries about its long-term use.
The new pipeline project paves the way for “the completion of the EU energy market” and to strengthen “the energy transition in the framework of the Green Deal”, according to a statement from the Elysée ahead of a summit last year. According to the French President’s office, the pipeline should still have the capacity to transport, in a “limited” way, natural gas, which it called “a temporary and transitory energy source”.1
Next month’s issue of World Pipelines includes a special feature on green hydrogen pipeline transport. Tree Energy Solutions (TES, Germany) discusses developing a closed loop scenario for CO2 that would facilitate the hydrogen economy. The article states: “A hydrogen backbone is being planned through the EU’s Important Projects of Common European Interest (IPCEI), but until that is ready, we can start by introducing synthetic green methane into the existing natural gas grids.”
In another article next month, Strohm (Netherlands) explains how it sees CCUS as a first step in the transition to sustainable energy, with green hydrogen being the end goal: “Green hydrogen is quickly gaining traction as a scalable alternative fuel that could power a climate-neutral economy. But since it is much less dense than most other energy carriers, it poses a significant and often-overlooked logistics problem –specifically, its transportation from future production sites to points of use.” Strohm is developing pipeline solutions whereby green hydrogen generated at offshore wind turbines can be transported to shore via subsea pipe infrastructure.
Finally, we’ll be featuring a Q&A with Oxford Flow (UK) about repurposing existing gas grids for hydrogen transport, thereby future-proofing gas networks. The piece recognises that “the operational safety implications around transporting, storing and utilising hydrogen are significant.”
As for this month’s issue, our keynote article takes a look at the opportunities for North American midstream companies to diversify in this arena. Gordon Cope outlines the potential for transport of CO2 sequestration and green hydrogen products. Read the article (p.10) to find out how alternative pipeline networks could hold the key to future prosperity in the US and Canadian pipeline sectors.
1. www.euractiv.com/section/energy/news/france-trades-midcat-pipeline-for-an-already-controversial-new-project
SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com
Germany will join a new hydrogen pipeline project between Spain, Portugal and France, according to the Franco-German declaration at the 60th anniversary of the Elysee Treaty (on 22 January).
By 2030, the H2Med project, which will link Portugal, Spain, France, and now Germany, will be able to meet 10% of the hydrogen demand in the EU. The pipeline under the Mediterranean Sea will carry green hydrogen, made from water via electrolysis using renewable energy.
The Spanish government estimates H2Med will be able to supply some 2 million tpy of hydrogen. It comes as Europe scrambles to reduce dependence on Russian energy and shift from fossil fuels to cleaner energy.
At the celebration of the treaty in Paris, German Chancellor, Olaf Scholz and French President, Emmanuel Macron said they were “stepping up our investments in the technologies of
tomorrow, particularly renewable and low carbon energies.”
A joint working group between the two countries will make “recommendations on our strategic choices regarding hydrogen development,” at the end of April 2023.
Macron said after hosting Scholz in Paris, “We started to talk about a strategy for what we want to do on an energy point of view.”
Scholz noted, “We want hydrogen to be available in large quantities and at affordable prices as the gas of the future.”
He added, “This is a technological advance that we can only achieve together. And we have also agreed closely that we want to achieve this together.”
When Madrid, Paris and Lisbon agreed in December to build the pipeline, it was expected to cost €2.5 billion (US$2.6 billion). It isn’t stated how much Germany’s inclusion would add to the costs.
Reuters reports that Russian gas exports to Europe via pipelines plummeted to a post-Soviet low in 2022.
State-controlled Gazprom, citing CEO, Alexei Miller, said its exports outside of ex-Soviet Union will reach 100.9 billion m3 this year. Russian direct gas exports to Germany, Europe’s largest economy, were halted in September following blasts at the Nord Stream pipelines in the Baltic Sea.
According to the Rosstat government body, Russia’s LNG
production rose by almost 10% in January - November to 29.7 million t. Russia has been increasing its sea-borne LNG sales, thanks mostly to Novatek-led Yamal LNG plant in the Arctic.
Before the Ukraine conflict began, Russia exported around 8 million bpd of oil and oil products. The EU, its biggest buyer, cut purchases in response to the conflict, but Moscow successfully diverted supply to Asia and total exports slipped only slightly to 7.6 million bpd.
Sonatrach, the Algerian national energy company, plans to invest more than US$30 billion in the exploration and production of hydrocarbons, notably natural gas, and to upgrade facilities to improve its position in global markets for LNG, as well as pipeline gas for Europe.
“As part of Sonatrach’s five year investment plan (2023 - 2027) the sum of US$40 billion has been set aside and more than US$30 billion will be allocated to exploration and production with the objective of increasing production in the short and medium-term, and preparing a portfolio of future projects, in particular for natural gas,” explained Sonatrach CEO, Toufik Hakkar in his 2023 policy statement. He said the company also planned, within the framework of the investment plan, to invest more than US$7 billion in refining, petrochemical, and gas liquefaction projects.
“These projects will promote the creation of added value to Algerian resources and will strengthen our export potential,” added Hakkar. “Nearly US$1 billion will be devoted to projects aimed at the company’s contribution to the energy transition. These include flared gas recovery projects at production sites and the LNG plants at Skikda and Arzew,” explained the CEO. (Arzew and Skikda are liquefaction plants located on Algeria’s Mediterranean coast.)
“Algeria’s objectives through Sonatrach is to become one of the most important sources of gas supply in the world, thanks to our substantial reserves of natural gas and to the recent increases in production,” added Hakkar. “Discoveries in certain gas fields will generate a significant increase in the volumes of gas available for export, both via gas pipelines and LNG carriers,” stated the CEO.
Hakkar said Sonatrach intended to continue developing its gas potential with several projects to be commissioned in the next two years. These include, among others, the Hassi Mouina and Hassi Ba Hamou fields in southwest Algeria, and the Isarène and TFT Sud fields in the southeast of the country.
He added that other projects are planned for 2023 and 2024, notably in Hassi R’mel, Hamra, Ohanet, and Touat, and he said that he invited European countries to commit to long-term gas purchase agreements to guarantee their security of supplies.
Algerian gas supplies are also carried to the EU on the Medgaz pipeline via Beni Saf in Algeria to Almeria in southern Spain. The Medgaz pipeline has been in operation since 2011, is 757 km (470 miles) in length, and has boosted compression to meet demand from Spain.
Corrosion Resistant Alloys, LLC, has fully acquired PipeSearch, a digital technology company powering global tubular solutions.
Wintershall Dea intends to fully exit Russia following a principle decision of the Management Board, approved by the Supervisory Board. The company will leave the country in an orderly manner, complying with all applicable legal obligations.
Azuli International has signed an extension to its MoU with Australian Gas Infrastructure Group (AGIG), under which the two companies will work together to identify, evaluate, and progress carbon capture and storage (CCS) project opportunities in Australia.
Xage Security has unveiled its expansion to secure and transform critical infrastructure operations throughout the Middle East. To accelerate adoption across the region, Xage has also partnered with Dubai-based CyberKnight, the leading zero trust cybersecurity distributor.
A group of leading US natural gas operators have launched the Appalachian Methane Initiative (AMI), a coalition committed to further enhancing methane monitoring throughout the Appalachia Basin and facilitating additional methane emissions reductions in the region. Enhancing methane emissions monitoring in the natural gas sector will assist in positioning companies for continued greenhouse gas (GHG) reductions, and will further underscore the sustainability proposition of Appalachian natural gas in the global energy system.
Pipeline operators Gascade and Fluxys are moving forward with plans for a green hydrogen pipeline in the North Sea, by applying to the European Commission to qualify for fast-track approvals and funding.
According to Reuters, the two pipeline infrastructure companies said in a joint statement they are seeking to help to speed up the development of a hydrogen economy.
Germany’s Gascade and Belgium’s Fluxys are seeking project of common interest (PCI) status from the EU, under which they could benefit from accelerated
permissioning procedures and funding. Their 400 km pipeline, called AquaDuctus, could become a collecting path, or ‘backbone’, for electricity output from offshore wind power production sites that would be converted onsite into clean hydrogen via electrolysis plants.
Shipments would start in 2030 from the wind park SEN-1 in the North Sea. In subsequent years, wind farms further offshore in Germany’s exclusive economic zone in the North Sea may be linked up to transport hydrogen from plants operated by other countries, such as Norway or the UK, into Germany.
The government of Uganda has approved the application to construct a pipeline by the East African Crude Oil Pipeline Company Ltd (EACOP).
The planned pipeline will run 1445 km from landlocked Uganda’s oilfields in the country’s west to Tanzania’s Indian Ocean
port of Tanga. It is expected to transport the country’s crude to international markets. TotalEnergies is the largest shareholder in EACOP with a 62% stake. Other investors are the Uganda National Oil Company, Tanzania Petroleum Development Corporation, and CNOOC.
The German subsidiary of the consortium behind the Nord Stream 2 gas pipeline has been wound up, according to press reports citing trade registry documents. The winding up of Gas For Europe applies retroactively from 1 January, dissolving an entity set up to seek German certification to allow it to operate.
“The Bundesnetzagentur is not in
touch with Gas for Europe, a spokesperson for Germany’s energy regulator said in a written statement.
“It has no information about a dissolution of the company,” the spokesperson said, but noted a provisional debt restructuring moratorium granted to Nord Stream 2 AG, the company’s Switzerland-based parent, had been extended until 10 January.
Tallgrass has announced the successful completion of its acquisition of the Ruby Pipeline. The acquisition, which was previously announced in December, extends Tallgrass’ reach to west coast markets and adds 683 miles of modern 42 in. pipeline infrastructure capable of moving 1.5 billion ft3/d to the company’s extensive asset base.
“We moved quickly to close the acquisition and we are eager to bring Ruby and our new teammates into the Tallgrass family,” said Zach Rider, Vice President Commercial and Corporate Development. “This is a strategic asset which brings immediate value to our portfolio.”
Ruby also enhances the value proposition that Tallgrass can offer to its existing and future customers by providing access to nearly every major demand centre across the US, as well as supply basin optionality. It also provides an expanded platform for Tallgrass’ continued efforts to offer innovative decarbonised energy solutions.
“Ruby enables cross-continental optionality and access for our existing customer base while providing Ruby’s customers a new partner with a strong track record of performance,” says Dustin Bashford, Segment President for Natural Gas.
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6 - 10 February 2023
Pipeline Pigging and Integrity Management Conference and Exhibition
Houston, USA www.ppimconference.com
7 - 11 February 2023
PLCA Annual Convention
Hawaii, USA www.plca.org/annual-convention-events
13 - 15 February 2023
Pipeline Coating 2023
Vienna, Austria www.ami-events.com
20 - 21 February 2023
Transportation Oil and Gas Congress 2023
Istanbul, Türkiye www.togc.events
20 - 25 February 2023
DCA Annual Convention 2023 Miami, USA www.dcaweb.org/page/Convention
19 - 23 March 2023
AMPP Annual Conference + Expo Denver, USA www.ace.ampp.org
27 - 29 March 2023
European Gas Conference 2023
Vienna, Austria www.energycouncil.com/event-events/ european-gas-conference
1 - 4 May 2023
Offshore Technology Conference 2023
Houston, USA 2023.otcnet.org
Strohm wins second TCP contract with ExxonMobil Strohm has secured a second contract with ExxonMobil to supply more than 24 of its jumpers for the Uaru field development situated offshore Guyana.
This latest award, which is subject to government approval of the project and a Final Investment Decision (FID), follows closely on the heels of a similar campaign confirmed last year with the oil and gas supermajor, and marks the largest commercial agreement in Strohm’s 15 year history. Less than 12 months ago, the business won a TCP ‘Jumper on Demand’ contract for the Yellowtail development, also offshore Guyana.
The TCP bound for the Uaru field – the one of the world’s largest SURF development projects – will be produced at Strohm’s manufacturing facility at its headquarters in the Netherlands, and used for water and gas
Momentum Midstream awards Opero Energy
Opero Energy, an affiliate of Audubon Engineering Company LLC, and a leading provider of processing technology and equipment, has announced the award of a major engineering, design, and fabrication contract for Momentum Midstream’s New Generation Gas Gathering (NG3) project in the Haynesville Shale.
With 4000 miles of pipeline and seven processing plants, NG3 will have an initial treating capacity of 1.7 billion ft3/d, expandable to 2.2 billion ft3/d. The project will also include a carbon capture and sequestration (CCS) component to capture and permanently sequester the associated CO2
Perma-Pipe International Holdings, Inc. has entered into a Joint Venture (JV) with Gulf Insulation Group in the Kingdom of Saudi Arabia to provide pre-insulated piping systems, piping fabrication, internal and external fusion bonded epoxy, 3-layer coating services, and leak detection systems for customers in the Kingdom of Saudi Arabia, Kuwait and Bahrain. This JV will be positioned to participate in Saudi Vision 2030, a strategic framework to diversify the Saudi Arabian economy through development of the public services sectors such as health, education, infrastructure, recreation and tourism.
(WAG) injection. The technology will be supplied to ExxonMobil Guyana in a single continuous length along with associated pipe handling equipment.
This concept and delivery method allows the individual 24+ jumpers to be cut to the desired length, terminated, and tested onsite in Guyana. The jumpers, made of carbon fibre and PA12 polymer, will be installed in deepwater, at depths over 1700 m operating in the region of 10 000 psi.
Strohm’s in-country specialist field service technicians will mobilise to Guyana as the jumper termination campaigns are called off over the duration of the deployment programme.
The use of TCP manufactured by Strohm also allows clients the ability to significantly reduce the CO2 footprint of their pipeline infrastructure.
• Unmanned underwater vehicles industry projected to reach US$7.4 billion by 2027
• Vincent Dicosimo elected Chairman of Texas Pipeline Association
• OPITO names 2022 Apprentice of the Year
• Cadent and National Grid look to kickstart the hydrogen economy
• Equinor and RWE to collaborate
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New pipeline systems for CO2 sequestration and green hydrogen products offer significant opportunities to midstream companies in the coming decade, suggests Gordon Cope.
Over the last several years, North America’s energy industry has been struggling to deal with COVID-19, gyrating demand, the consequences of the Ukraine war, and the move toward net-zero. All the kerfuffle has had a knock-on effect in the pipeline sector, as operators scramble to meet the myriad of constantly changing needs of producers, consumers, governments and NGOs.
Two significant pipeline projects are underway on the west coast of Canada; the Coastal GasLink pipeline construction and the Trans Mountain crude pipeline expansion (TMX). The Coastal GasLink is a 670 km line from the prolific Montney unconventional shale play in north eastern British Columbia (BC) to the Pacific port of Kitimat, where it will supply up to 2.1 billion ft3/d of gas to Shell’s LNG Canada plant (currently under construction). The pipeline, which is scheduled to come online in 2023, has been plagued by sometimes-violent protests from First Nations factions opposed to the ROW crossing ancestral lands. Cost overruns due to labour shortages and logistics related to COVID-19 have also caused the budget to grow from an original CAN$6.6 billion to over CAN$11 billion.
The TMX (which will increase the capacity of the original Trans Mountain line from 300 000 bpd to 890 000 bpd) will be a major export line delivering crude from Alberta to tidewater in Burnaby, BC. In addition to COVID-related issues, the project has also been plagued by protests and inclement weather; the original price tag of CAN$12.6 billion has increased to an estimated CAN$21.4 billion by the time it is completed in late 2023.
The Montney shale, which contains an estimated 450 trillion ft3 of gas, has enough proposed
processing capacity and pipeline expansions to eventually double current levels of production of 5.8 billion ft3/d to 11.5 billion ft3/d. Several pipeline systems are being expanded to meet the expected increase. Enbridge has earmarked CAN$1.9 billion to expand its westcoast natural gas system that services BC and Alberta. In November 2022, it announced an open season to its T-North segment, which runs from Fort Nelson in northern BC to southern and eastern consumers. Sufficient consumer interest could result in an additional 500 million ft3/d of capacity.
In December 2022, TC Energy received federal approval to expand its NGTL network by 40 km of new gas pipeline. While the number may be insignificant to the 25 000 km of existing lines, the new project eliminates a bottleneck in the system, allowing for increased exports to Washington, Oregon, and California states. The West Path Delivery project, expected to be completed by late 2023, will create over 250 million ft3/d of new, south-bound capacity.
In the US, crude pipeline construction has recently focused on capacity expansions and eliminating bottlenecks. In mid-2022, Energy Transfer completed the Ted Collins pipeline, a 275 000 bpd crude line that connects the Nederland terminal to the Houston Ship Channel, both located in the Texas Gulf Coast. Energy Transfer also commissioned the Cushing South Phase II, a 55 000 bpd expansion of the Cushing South project that transports crude from Colorado to Cushing, Oklahoma, and then south to Nederland.
Several major natural gas pipelines were recently completed. Kinder Morgan’s Permian Highway Pipeline (PHP), a 430 mile pipeline that delivers 2.1 billion ft3/d from the Waha Hub in the Permian basin of west Texas to the Gulf Coast, where it has additional connections to Mexico’s interstate pipeline network. Whitewater/ MPLX’s Agua Blanca Expansion Project, located in the Delaware Basin of Texas, transports 1.8 billion ft3/d to the Waha Hub. The Whistler Pipeline moves 2.0 billion ft3/d of natural gas from the Permian Basin to the Texas Gulf Coast.
The next wave of pipeline activity is expected to ensue as LNG producers scramble to deliver product to Europe; in the wake of the Ukraine war, consumers are signing long-term deals to ensure security of supplies.
When the first tranche of LNG development occurred in the US, feedstock was in abundant supply from several basins. Pipeline reversals brought gas from the Utica/Marcellus plays south to the USGC, and new-build in the Permian supplied associated gas from unconventional oil plays.
Now, an estimated 100 million tpy of new projects, representing over 14 billion ft3/d, is on the planning boards, and the focus has shifted to where that new supply might originate. Due to pipeline-building constraints in the Eastern Seaboard, the most likely growth is expected to occur in Texas and Louisiana, where the Permian/Eagle Ford output (currently at 17 billion ft3/d), is expected to surpass 30 billion ft3/d in a decade, and the Haynesville (currently around 15 billion ft3/d), to exceed 20 billion ft3/d.
Several expansions and new pipelines are planned to enter service in the next several years. WhiteWater and partners expect the Matterhorn Express to enter service in late 2024. The 490 mile line will deliver up to 2.5 billion ft3/d from the Waha Hub in west Texas to Katy, Texas, near Houston. The company is also expanding its Whistler Pipeline by 500 million ft3/d, to 2.5 billion ft3/d.
Kinder Morgan is adding compression to its Gulf Coast Express Pipeline to increase capacity from 2 billion ft3/d to 2.55 billion ft3/d, and is expanding capacity on its PHP by 500 million ft3/d, to 2.65 billion ft3/d. Both projects are expected to be completed by late 2023.
In June 2022, Williams reached an FID to build the Louisiana Energy Gateway, a 1.8 billion ft3/d Greenfield project designed to deliver gas from the Haynesville basin to LNG projects on the Gulf Coast. The US$1.5 billion pipeline is expected to enter service in late 2024. In November 2022, TC Energy announced that it would build the Gillis Access project to connect the Haynesville basin to LNG markets. The US$400 million line, which will move up to 1.5 billion ft3/d, is expected to enter service in 2024. In December 2022, Energy Transfer received approval to begin operations on the 135 mile Gulf Run, a 1.65 billion ft3/d pipeline that links basins in Texas, Louisiana, and Arkansas to the US Gulf Coast.
Due to their multi-jurisdictional nature, environmental activists intent on eliminating oil and gas usage find pipelines a tempting legal target. Enbridge’s Line 5 transports 540 000 bpd from Canada (and North Dakota) through Michigan to Ontario and Quebec. In late 2020, Michigan Governor, Gretchen Witmer ordered Line 5 to shut down operations by 13 May 2021, due to the potential for spills where it passes under the Straits of Mackinac in the Great Lakes.
As an international pipeline, Line 5 is governed by the 1977 Transit Pipelines Treaty, which contains provisions guaranteeing uninterrupted transit of light crude oil and NGLs between Canada and the US. In October 2021, Ottawa invoked Article Six of the treaty to instigate bilateral negotiations with the US federal government.
In August 2022, Canada invoked the treaty for a second time in regards to Line 5, this time in Wisconsin where it skirts the
southwestern shores of Lake Superior. The line passes through the Bad River Reservation; band members had sought a summary judgement against Enbridge that would have shut the line down without a trial. Enbridge has stated publicly that it is endeavouring to find a solution to the band’s concerns by re-routing the ROW. In November 2022, a Wisconsin judge denied the request to shut the line down and ordered the two sides to seek solutions that would mitigate the risks of a spill while continuing operations.
The Mountain Valley project, a gas pipeline that is designed to move 2 billion ft3/d from West Virginia to consumers in Virginia and the south Atlantic, languishes on. First proposed in 2018, the line was estimated to cost US$3.5 billion, but a 5 km stretch of the 488 km ROW passes through Jefferson National Forest and, in early 2021, the US Court of Appeals (4th Circuit) vacated the US Forest Service and Bureau of Land Management decisions to allow access. In August 2022, Joe Manchin, a Democrat senator from West Virginia, got the White House’s agreement to tack on an amendment to a multi-billion tax and climate bill that would streamline the completion of the pipeline. The vote failed to pass the Senate in December 2022, however, and the project remains in limbo as costs balloon past the US$6 billion mark.
In 2021, the government of Canada enacted the Canadian NetZero Emissions Accountability Act that provides a legally-binding roadmap to achieve net-zero greenhouse gas (GHG) emissions by 2050. The Act also specifies that emissions are to be reduced up to 45% of 2005 levels by 2030. That same year, the Biden administration announced a target to reduce US GHG emissions by 50% of 2005 levels by 2030.
State and federal incentives, including a low-interest loan programme passed by Congress in 2021, is incentivising CO2 pipeline projects in the US. Summit Carbon Solutions is proposing an extensive CO2 pipeline network to capture the gas produced in Iowa ethanol plants and sequester it in North Dakota. The 2000 mile network is estimated to cost US$2 billion; it would capture up to 12 million tpy (the equivalent of 2.6 million cars), significantly reducing the carbon footprint of the biofuel. Continental Resources, the largest driller in North Dakota, pledged US$250 million towards construction costs.
In addition, the White House set out an ambitious target of promoting hydrogen as a clean fuel source, ear-marking billions of dollars to subsidise the cost of green hydrogen and develop infrastructure.
Hydrogen can be mixed with existing natural gas lines up to around 25% without causing undue complications. Southern California Gas (SoCalGas) and San Diego Gas & Electric (SDG&E) have announced plans to experiment with blending hydrogen and natural gas for customers in California. The US$35.3 million demonstration project would see a 5% hydrogen mix used by residential and commercial buildings. The Sierra Club has voiced its opposition to the project, stating that burning hydrogen would not significantly decarbonise buildings, while posing a hazard risk due to embrittlement.
SoCalGas is also developing Angeles Link, a dedicated, green hydrogen pipeline system that could deliver up to 25% of the
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company’s current gas capacity. Potential customers include electric utilities, heavy transportation, and industry. The system has the potential to displace the equivalent of 3 million gal./d of diesel.
Details are still scarce, but the pipeline system would likely originate in the desert east of Los Angeles where contracted firms would generate hydrogen using abundant wind and solar power and electrolyzers. The pipeline would terminate within the Los Angeles basin near current utility plants or the port of Los Angeles, where approximately 20 000 heavy-duty trucks shift cargo.
SoCalGas, which has an internal commitment to decarbonise its operations by 2045, intends to spend 2023 working to further define the project scope. The company notes that the federal allocation of US$8 billion for the creation of hydrogen hubs is likely to generate wide general interest in their plans. “We see Southern California as a logical location for a hydrogen hub,” said Neil Navin, Vice President of Clean Energy Innovations at SoCalGas. “And we would certainly be looking to work with partners to pursue those funds.”1
When hydrogen content exceeds 25%, it can cause damage to conventional gas networks, and special hardened steels are required to maintain safety. The US has approximately 1600 miles of existing hydrogen pipelines, most of which are located in the refinery and petrochemical corridor along the USGC in Texas and Louisiana. Most of the hydrogen is created using traditional, carbon-intensive processes, but plans are underway to create green hydrogen.
Renewable fuels developer HIF Global has plans for a US$6 billion green hydrogen fuel plant in the Bay City area
of Texas. When completed in 2026, the plant will produce 200 million gal./yr of green fuels. Air Products and partners are building a US$4 billion plant in Wilbarger County, Texas, to produce 200 tpd of green hydrogen. Air Products and partners are building a US$4 billion plant in Wilbarger County, Texas, to produce 200 tpd of green hydrogen. OCI N.V., based in the Netherlands, is constructing a US$1 billion blue hydrogen plant in Beaumont, Texas. While output from the new hydrogen facilities will primarily flow through the dedicated lines currently servicing refineries, petrochemical and fertilizer plants, opportunities for pipeline expansion will arise as new facilities seek low-carbon feedstock and energy inputs.
Conclusion
In conclusion, while the turmoil due to COVID-19 has greatly receded, its effects can still be seen in elevated capital expenditures on new build in North America. Environmental opposition to oil and gas also continues to push up costs and delay projects. Growing demand for LNG in Europe is driving new gas line expansions, both in the USGC and Western Canada. New pipeline systems for CO2 sequestration and green hydrogen products also offer significant opportunities to midstream companies in the coming decade. While there is no lack of challenges, prospects for the pipeline sector look promising for the coming decade.
References
1. www.utilitydive.com/news/socalgas-begins-developing-100-clean-hydrogenpipeline-system/619170
Pipeline construction can take several years or more, especially if the project is delayed by problems with permitting, accidents, or environmental issues, to name a few. One NGL pipeline that was recently completed took five instead of three years to finish due to complications from a drilling mud fluid spill.1 The cost of any such delay is massive. For example, one pipeline development company claimed to have lost US$583 million in project value simply due to legal delays, with ROW maintenance costing close to US$20 or US$25 million per month.2 Yet another pipeline faced an increased price tag of US$1.1 billion at one point after regulatory delays and winter, environmental, and COVID-19 issues affected construction costs.3 In short, delays are both common and expensive.
One side effect of delays that can be avoided is the loss of asset value due to corrosion. Delays mean that assets sit outside for extended periods, often unprotected and exposed to the elements, at high risk of corrosion. Considering that capital costs of crude oil pipeline construction can be between
US$500 000 and US$800 000 per mile, the stakes of losing assets to corrosion are high.4 However, delays or no delays, corrosion is always a threat to asset integrity and value during the pipeline construction period and thereafter. Fortunately, protection does not have to be complicated, as Cortec® demonstrates by its vapour phase corrosion inhibitor technology and related strategies that offer corrosion inhibition through multiple stages of pipeline construction and unwelcome delays.
Pipeline segment protection
The most obvious place where corrosion protection is needed is inside pipeline segments. Although typically protected with a special coating on the outside, pipeline internals are often left bare and open to the environment (Figure 3). On the outside, weld ends are left uncoated and more susceptible to corrosion. Pipe segments sit outside in staging yards by the hundreds until they can be installed. Depending on how quickly the project is moving, this could mean weeks to years for thousands of pipe segments to be left exposed to the elements. Considering that line pipe and equipment could make up 23.8 - 27.2% of crude oil pipeline capital costs, the loss of these assets to corrosion could be a significant financial impairment.5
In contrast, protection is relatively simple and cost-effective with vapour phase corrosion inhibitors that can be used to protect pipe segment internals during shipping, transit, and outdoor
storage. Typically based on salts of amine carboxylates, vapour phase corrosion inhibitors come in many forms but work in the same basic way. These inhibitors vaporise and diffuse throughout an enclosed space until they have achieved equilibrium. When there is no more room in which to disperse, the vapour phase corrosion inhibitors give into their metal attraction and begin to adsorb onto the metal surfaces in a molecular protective layer (Figure 2). As long as the void remains closed – or even if it is briefly opened – the ambient vapour phase corrosion inhibitors continue to replenish the protective molecular layer. Removal and cleaning of the layer is typically not needed before asset commissioning, although compatibility should be verified with each specific product.
One of the newest forms of vapour phase corrosion inhibitor technology is CorroLogic® Fogging Fluid VpCI®-339. This 100% vapour-phase inhibitor product can be fogged into pipe segments and trapped inside by capping the ends for one to two years of protection. Once the caps are opened, the vapour phase
corrosion inhibitors begin to dissipate and there is typically no need for manual corrosion inhibitor removal before pipeline installation.
EcoPouch® is another form of vapour phase corrosion inhibitor application that can be added before transit or storage. This was used in Malaysia for an oil and gas project that needed 24 months of corrosion protection inside pipe spools that would be stored in a harsh environment. EcoPouch contains VpCI-609 powder in a breathable pouch that allows the vapour phase corrosion inhibitors to escape (Figure 4). Two EcoPouches were inserted into each pipe spool before the ends were capped, trapping the vapour phase corrosion inhibitors inside. This offered an easy and clean method of protection as the pouches could be taken out whenever necessary.6
In another case, a subsea LNG pipeline project needed internal protection of 1300 pipeline segments that would be stored outside for 12 - 18 months. The pipeline segments were externally covered in cement for sea floor ballasting, but pipe internals and cutbacks were exposed, and light rust had already started to form in some segments. A vapour phase corrosion inhibitor fogging fluid was applied inside the pipes. External ends were coated with VpCI-389 water-based corrosion inhibitor coating. VpCI-126 Film was then tightly secured on the ends. Upon early inspection it was found that existing corrosion had been arrested and pipes that were initially corrosion free remained so.7
The previous example brings up the important point of coating pipeline weld ends. While ends are often left uncoated to make welding easier, they are also more likely to develop corrosion that must be ground off to provide a clean weld surface when welding does take place. This extra hassle can be avoided by protecting ends with an inobtrusive Cortec VpCI coating. VpCI-391 is a clear water-based temporary coating that dries to a nontacky film. If desired, it can be cleaned off with an alkaline cleaner prior to welding. This eliminates some of the extra steps, such as grinding, that are often necessary to remove rust and ensure a clean weld surface.
Valves are another example of pipeline components that can be expensive and may sit outside while awaiting installation. Preservation of these critical assets can be done even before they arrive at the construction site, as seen by one pipeline valve and fitting surplus company that inventories new components acquired from oil and gas companies. Standard procedure for protecting this inventory, which sometimes includes assemblies of more than 40 000 lb (18 144 kg), is to place a source of vapour phase corrosion inhibitors inside (e.g. VpCI-111 Emitters or EcoAir® 337 fogging fluid) and cover openings with VpCI-126 bags or film. Those stored outside use custom VpCI-126 HP UV bags.8 Depending on how long the equipment has already been outside at the supplier or is expected to sit outside at the staging site, pipeline components preserved in this way may not even need reapplication of preservation materials for one to two years after they have been transported to the field.
Pipe segments are not the only metals in need of corrosion protection at a pipeline jobsite. The quantity of heavy equipment
Figure 3. Pipeline segments stored outdoors are vulnerable to rust on unprotected internals and weld ends.
needed for pipeline construction is massive. Bulldozers and stump grinders may be needed to clear ROWs; excavators and jack hammers are needed to perform a variety of earth-moving jobs (Figure 1).9 While this equipment is made for rough outdoor work, it can still face deterioration if left out in the open for extended periods of time, particularly in harsher environments such as coastal areas or the Middle East. As heavy equipment sits out in the rain, snow, sun, or sea spray, rust develops over time and the expected lifespan of the equipment drops, causing an accelerated loss of value. Some heavy equipment owners in other industries have had good results from applying EcoShield VpCI-386
or VpCI-391 right over existing coatings. These provide an extra layer of corrosion protection for the equipment bodies without affecting their appearance or usability. In the case of VpCI-391, if the temporary coating begins to wear off through normal use, it can be reapplied as part of an annual maintenance routine.
One of the last steps of pipeline construction is hydrostatic testing to ensure pipeline integrity. Large amounts of water are flushed through the completed pipeline at high pressure. While this is critical to verifying pipeline safety, it also introduces corrosives to the internal environment. To protect against flash rusting during hydrotesting and corrosion caused by residual water thereafter, VpCI-649 can be added to the hydrotest water. VpCI-649 is a film forming corrosion inhibitor that leaves behind a protective layer inside the pipeline, with vapour phase protection for hard-to-reach areas like the very top of the pipe. It is widely used in a variety of industries and is an excellent addition to almost any hydrotesting application.
Pipeline construction delays are a fact of life, leaving equipment and construction materials exposed to the risk of corrosion for long periods of time. Even without delays, equipment and pipe segments are necessarily exposed to corrosive elements, often for extended timeframes while construction work is completed. Corrosion protection is an important step to counter the potential asset value loss from environmentally-induced metal deterioration. It also keeps equipment and components in ready-to-use, readyto-install condition and minimises concerns about future failures stemming from corrosion that happened before the pipeline was ever commissioned. By strategically using vapour phase corrosion inhibitor technology and VpCI coatings, pipeline developers can discover an excellent solution to minimise corrosion during pipeline construction and delays.
1. PHILLIPS, S. “Mariner East pipeline project is finished, after years of environmental damage, construction delays.” WHYY.org. 17 Feb 2022 <whyy.org/articles/mariner-eastpipeline-project-is-finished-after-years-of-environmental-damage-construction-delays>. Accessed 7 Nov 2022.
2. TONY, M. “MVP developer calls for Congress to force project completion amid $583M project impairment.” WV Gazette Mail . 1 Nov 2022 <www.wvgazettemail. com/news/energy_and_environment/mvp-developer-calls-for-congress-to-forceproject-completion-amid-583m-project-impairment/article_9899b10d-b9d9-5182-9120b16354a59ff7.html>. Accessed 9 Nov 2022.
3. LOVRIEN, J. “Line 3 pipeline costs increase another $1.1B.” Pioneer Press. TwinCities.com. 16 Feb 2021 <www.twincities.com/2021/02/16/enbridge-line-3-pipeline-costs-mn-nd-wi>. Accessed 8 Nov 2022.
4. O’NEIL, B., et al. “The Economic Impact of Crude Oil Pipeline Construction and Operation.” Consulting Report. IHS Economics. February 2016 <documents.nam. org/Nam.org_Web_Archive/www.nam.org/Issues/Energy-and-Environment/ CrudeOilImpact_March2016.pdf> p. 5. Accessed 7 Nov 2022.
5. Ibid.
6. Cortec Corporation. “Pipe Spool Preservation.” Case History #714. Apr 2021 <www. corteccasehistories.com/?s2member_file_download=access-s2member-level1/ch714. pdf>. Accessed 8 November 2022.
7. Cortec Corporation. “VpCI-126 Film, VpCI-389 Coating, & VpCI 609 Powder.” Case History #311. April 2007 <www.corteccasehistories.com/?s2member_file_ download=access-s2member-level1/ch311.pdf>. Accessed 8 Nov 2022.
8. Cortec Corporation. “Preservation of Pipeline Valve Inventory.” Case History #762. Mar 2022 <www.corteccasehistories.com/?s2member_file_download=access-s2memberlevel1/ch762.pdf>. Accessed 8 Nov 2022.
9. Fractracker Alliance. “Pipeline Construction: Step by Step Guide.” Copyright 2022 <www.fractracker.org/resources/oil-and-gas-101/pipeline-construction>. Accessed 9 Nov 2022.
Figure 4. EcoPouch is easy to place inside new pipe spools for protection. They can be removed at any time, leaving the pipeline segment clean and protected (image courtesy of Cortec).HEAT SHRINKABLE SLEEVES
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he increase in global economic activity following more than two years of a pandemic-induced slowdown has accelerated growth in demand for a wide range of consumer products, increasing pressures on refineries. In August 2022, the International Energy Agency (IEA) estimated refinery throughput, which rose by 1.1 million bpd in July, would increase by a further 350 000 bpd that month. This elevated refinery runs to its highest levels since January 2020. The IEA has predicted global refinery runs will rise by 2.6 million bpd in 2022 and 1.3 million bpd in 2023.1
To meet this increasing demand, refineries must operate at optimal efficiency and avoid unplanned shutdowns. Achieving this balance will be critical but challenging. Refineries are large, complex sites with many processes that
require very high pressures and temperatures. They have a vast pipeline network to transport process fluids throughout the site and externally. Refinery pipelines mainly transport raw materials (primarily crude oil) from receiving terminals for refining, as well as refined products from the refinery to the customer.
One of the key challenges facing refinery pipelines is corrosion. An EU Joint Research Centre study found that 17% of the reported incidents were related to corrosion failures in refinery pipelines, and that failures have increased since 2000.2 The costs of managing corrosion are significant and growing. Figures for corrosion management spent globally are shown in Figure 1.
For asset managers, balancing budgets for preventative maintenance today against the risk of potentially greater operational expenditure in the future is a major challenge.
Pipelines to and from refineries are generally constructed from carbon steel and experience internal and external corrosion. The level of internal corrosion in an incoming refinery pipeline depends on the quality of the crude within it. If the crude is effectively dehydrated and the concentration of acid gases such as carbon dioxide (CO2) and sour gases such as hydrogen sulphide (H2S) is low, the likelihood of internal corrosion is also considered to be low.
However, if these conditions are not met, the probability of internal corrosion can be high. The CO2 in acid gases causes general corrosion, and localised pitting corrosion can occur in the protective sulphide layer formed in presence of H2S. Depending on the partial pressure of the H2S in the acid gas, the pipeline can suffer sour environment cracking, including hydrogen-induced cracking and sulphide stress corrosion cracking. Ineffective biocide treatment in the pipeline can create microbially induced corrosion through increased acidity.
Ensuring current and future demands for refined products are met will require refineries to operate with optimal efficiency, says Ali Alani, Director of Asset Integrity – Europe, Penspen, UK.
Pipelines transporting refined products from the refinery are generally at a lower risk of corrosion because the products they carry do not contain corrodents. However, pipelines transporting fuel grade ethanol or a blend of fuel grade ethanol and gasoline can experience ethanol stress corrosion cracking (e-SCC). Dissolved oxygen and the presence of variable stresses increase the propensity for cracking. Residual stresses in welds, locally cold-worked components, and cyclic stresses (loading and unloading sections of the pipeline) can be affected by ethanol SCC.
The major threat to refinery pipelines is external corrosion, specifically atmospheric corrosion, soil corrosion, and AC/DC stray current corrosion. Atmospheric corrosion occurs due to the reaction of carbon steel with oxygen and humidity in the atmosphere. As a result, the launcher/receiver sections and the sections within the valve chambers of the pipeline can be particularly vulnerable. Soil corrosion impacts the buried sections of the pipeline where exposed bare metal surfaces can react with corrodents in the soil to cause metal degradation.
AC corrosion can occur where high voltage AC power lines run alongside refinery pipelines in the same corridor. The electromagnetic field caused by the power line creates an induced electromotive force in the buried pipeline and causes a current flow. The point where the current leaves the pipeline to enter the earth can generate severe localised corrosion. DC stray current corrosion occurs where the pipeline is crossing or close to a DC traction system. The DC current may be picked up by the pipeline where there is a coating defect, and discharged to the ground at another location. The spot where the current is discharged into the ground can experience severe corrosion.
External corrosion is mostly caused by damaged coating combined with ineffective cathodic protection (CP). As the service life of the pipeline increases, the pipeline will be more prone to coating damage. If the coating becomes unbonded and water congregates behind it, this can prevent the CP from accessing the pipe, creating CP shielding which can be difficult to detect. External conditions such as marine environments, microbial presence in the soil, and stray current sources can also accelerate coating damage and the corrosion of exposed metal surfaces.
Above ground, atmospheric corrosion is a significant issue. This can be exacerbated by pollutants in the air such as sulphur dioxide (SO2) and CO2, as well as humidity. The multitude of short-length, small-diameter pipelines with multiple bends and buried sections within the refinery fence can make inspection challenging.
Outside of the fence, aside from the factors mentioned earlier, third-party damage caused by human activities is the
most significant issue. For example, a section of pipeline coating may be accidentally removed, or a dent created by an excavator. This can create corrosion damage and/or fatigue damage if not detected and repaired.
For internal corrosion, ensuring the effectiveness of the corrosion inhibitor for the incoming pipeline can play a major part. The product should be dry (free from water) with no oxygen ingress into the pipeline. Any leaks in pump seals or storage tank seals can lead to oxygen ingress.
The most effective way to control external corrosion is through an effective corrosion protection system including anti-corrosion coating and CP. For an ageing pipeline, coating deterioration is inevitable. Effective CP should protect the exposed metal at the coating defect locations. It is important to have an effective monitoring and management plan to reduce the opportunities for corrosion.
A detailed material selection study as part of the design stage of the pipeline can determine the appropriate materials to resist the corrosive agents in the process fluid. The study should also identify other appropriate anti-corrosion enablers such as inhibitors and chemical treatments. Demulsifiers and scale inhibitors would also be considered.
Also at the design stage, a suitable anti-corrosion coating should be selected based on the operating and design parameters, particularly temperature. Generally, anti-corrosion coating will be supplemented with a CP system. As part of the design stage, a CP package should be prepared including material requirements, quantity, installation details, and necessary monitoring requirements.
In making decisions on the most appropriate solutions to prevent corrosion formation in refinery pipelines, asset owners need to seek the support of a partner with deep expertise in providing corrosion control and mitigation consultancy services across all stages of the asset’s life. Penspen has successfully undertaken corrosion control projects, and has developed corrosion control standards and systems used by refinery operators around the world.
An asset owner in the Middle East introduced product transportation facilities between its refineries and a storage terminal via a pipeline. The entire refined product requirements for a city are currently supplied from the terminal. A study revealed a major risk of product shortages if the terminal or existing pipelines were to experience disruption. To mitigate the risk, the company is planning to construct a backup storage terminal.
To avoid risks arising from road transportation from the refinery to the terminal, the company intends to implement a pipeline transportation facility from the refinery to a depot for transferring
LPG. Penspen was commissioned to carry out the corrosion risk assessment study for the proposed project. The risk assessment study included:
) A detailed corrosion study to identify internal and external hazards, and corrosion rates for the pipeline and other facilities.
) A corrosion risk assessment of the pipeline and facilities for risk ranking, and a contingency plan.
) A review of the selection of the material for carbon steel pipelines, and associated infrastructure in the design phase, and update if required.
) Review and update material selection diagrams following the corrosion risk assessment.
) Provide recommendations for corrosion monitoring and mitigation for pipelines and other facilities.
The major potential internal corrosion factors were identified as microbial-induced corrosion, oxygen corrosion, and galvanic corrosion. The most likely sources of external corrosion were identified as atmospheric corrosion and soil corrosion. The corrosion rates study revealed the calculated internal corrosion rates would only be applicable in cases of oxygen and water ingress during storage, and would be for very short periods. It also identified that external corrosion rates would only be
applicable in cases of coating damage for above-ground facilities and inappropriate CP for buried pipelines.
The corrosion risk study determined the underground sumps, sump vessels, and slop systems should be ranked as medium risk due to the higher environmental consequences in case of leaks or cracks being undetected, except for the portable water ones. It also recommended that pipelines, underground piping, sumps, sump vessels and storage tanks should be ranked as medium risk, while all other equipment was found to be low risk. The assessment study gave the company a clear picture of the corrosion risk levels associated with the project, enabling them to plan with confidence.
Conclusion
Product refineries are of increasingly critical importance to the global economy. Ensuring current and future demands for refined products are met will require refineries to operate with optimal efficiency. The corrosion of pipelines represents one of the biggest threats to achieving optimal refinery efficiency, and must be a major consideration at the earliest stages of a project. Investing time in detailed anti-corrosion planning at the design stage of a refinery pipe can save asset owners significant operational expenditure down the line.
References
1. www.iea.org/reports/oil-market-report-august-2022
2. minerva.jrc.ec.europa.eu/EN/content/minerva/51beddd7-1149-4230-928da225bf39471a/tr01corrosionrefineriespdf
3. Global Asset Integrity Management Market (million US$) by Type (2017 - 2023).
he repair and maintenance of assets has always been an important element in the oil and gas industry, and is essential to ensuring the reliability and safety of operations. Continuing to be a priority in today’s energy industry, throughout the transition to explore greener energy alternatives, the importance of corrosion control remains at the forefront of operator’s minds. Inadequate or infrequent inspection and management of assets can lead to a range of risks including production failure and loss of containment, potentially leading to catastrophic impacts on the personnel, plant, and environment. As a vital factor in optimising the productivity, production, and downtime of operations whilst mitigating potential risks, corrosion control is essential to minimising operational and repair costs, and extending asset life.
With the risk of health and safety issues and disruption to operations, corrosion can also compromise the appearance, performance, strength, and load-bearing ability of assets. Corrosion management will allow the operator to mitigate any safety and environmental hazards, as well as prevent any production and financial losses. As a key challenge facing the industry today, corrosion can lead to production delays, equipment failure, operational expenditure, and safety hazards.
ICR Integrity is an industry-leading, technology-enabled provider of specialist repair, inspection, and integrity management solutions to a diverse range of industries. The company’s well-established repair and maintenance division offers clients world class repair solutions providing greater asset uptime and reliability while saving time and cost compared to traditional repairs. The newly formed specialist inspection and integrity division reflects the company’s focus on innovation and technology advancements in support of its global clients’ integrity management requirements.
The traditional oil and gas industry, which ICR has a strong presence in, requires solutions that provide validation and assurance on the condition of their assets, as well as any repairs that have been undertaken. With a strong focus on the environment when carrying out testing, avoiding carbon
This integrated approach to implementing composite repair solutions can reduce carbon emissions by 66% compared to traditional methods, says Antonio Caraballo, Inspection & Integrity Management Services Director, ICR, UK.
intensive techniques is essential to the sector. Many ageing assets have composite repairs reaching the end of their design life, meaning there is an increased requirement to revalidate or extend the life of the repairs, allowing operators to avoid costly replacement options that may require a full shutdown of the asset. Regulatory bodies have a strong focus on the integrity management and condition monitoring of repairs. Being able to inspect the defined life of the repairs is therefore a key enabler in ensuring safe and reliable operations for extended time periods.
Based on the principles of acoustic inspection methods with pitch and catch, ICR Integrity’s innovative new nondestructive testing (NDT) technique, called INSONO. It provides resonance and mechanical impedance analysis to detect and size any flaws in the inspection of engineered composite repairs. The technology has been validated by The Welding Institute (TWI) and has patent and UKAS accreditation pending. A hand-held scanner creates 3D models and visual representation of the composite repair, allowing for precise dimensions to be used in the assessment. Any defects in three main areas of concern can then be detected – in the bond line, the interlaminar and the steel substrate.
With over 30 years’ experience, ICR is internationally recognised as a service-leader and a key-player in the ongoing development and adoption of composite technology. INSONO complements its industry renowned TechnowrapTM range of engineered composite repairs and assures operators that their composite repairs are fit for purpose, satisfying regulatory body guidelines regarding inspection criteria. It also allows for the extension of defined life repairs, thus reducing waste whilst avoiding high-carbon emissions from traditional steel replacement alternatives.
Inspection techniques currently available are not practical to deploy in the field, and many are unable to access complex geometries with a single technique or product. INSONO is hand-carried and requires only one technician, meaning inspections can be carried out in higher risk areas where they may not have been previously considered.
ICR is internationally recognised as a service-leader and key player in the ongoing development and adoption of composite technology. The versatile product range offers practical and cost-effective rehabilitation of pressure systems and structural components with minimal disruption to operations, typically delivering valuable cost savings. The repair systems can not only be applied to live systems with no impact on production, but also offer a low greenhouse gas (GHG) emissions alternative to steel replacement. Replacing large steel equipment is energy intensive and requires the production of a new part. By repairing their equipment, ICR’s clients avoid the emissions associated with steel production and transportation as well as the energy required to perform the replacement.
Technowrap repair solutions can be engineered for anywhere between 2 and 20 years, which can be equal to the lifetime of a traditional replacement and as such are directly comparable to a replacement solution, depending on the anomaly type. ICR compared the carbon impact of using its repair system technology for the repair of a 2 m section of 8 in. carbon steel pipework (85.1 kg) located 225 miles offshore from Aberdeen. The findings established that the repair system reduced emissions by 66% compared to the traditional replacement method.
On a recent project in the northern North Sea, an operator client asked ICR to review various sections of pipework that had sustained severe corrosion resulting
Figure 2. An INSONO probe inspecting a composite repair applied to a metallic component. Figure 1. The portable hand-held equipment and specifically designed probes.
Reza Javaherdashti, MICCOR, Netherlands, considers six important misunderstandings about microbiologically influenced corrosion in pipelines.
Microbiologically influenced corrosion (MIC) is an electrochemical corrosion process which, specifically in pipelines, forms the majority of internal corrosion. However good it may have been studied under laboratory conditions, it is not, however, that well-recognised and applied under real life conditions. In this respect, we have identified six important misunderstandings about MIC related to concepts and definitions used in MIC from a practical point of view – from the very basic definitions, to where to expect MIC in pipelines, to the link between cathodic protection (CP) and MIC, to name a few.
When I was asked to participate in a project as a corrosion expert for managing MIC in a 320 km underwater pipeline, it was not my first experience in corrosion troubleshooting, particularly related to post-hydrotest MIC. However, this particular project was very different since the pipe had been hydrotested with seawater. The hydrotest fluid had not been treated with any particular chemical treatment (corrosion inhibitors or biocides), and the water had been left inside the pipe as a wet lay-up practice for about five months. MIC had therefore developed. Additionally, in the water inside the pipe, the number of planktonic sulphates reducing bacteria (SRB) had multiplied after application of a so-called ‘multi-purpose’ inhibitor – this meaning that it is both a corrosion inhibitor (to control non-MIC corrosion) and a biocide (to control MIC). Normally, in the case of wet lay-up, this water must not be the same as the hydrotest water. And if it has to be (to cut down the costs or the interval between flooding and service exceeding one month), then this water must have been treated with a suitable cocktail of corrosion inhibitor and biocide(s). Therefore, this case was exceptional in not only lacking the required initial chemical treatment, but also after the hydrotest had been done. Furthermore, addition of the selected corrosion inhibitor had increased the number of free-swimming SRB. I was told that the cost (including purchase, communications, application) of wrong selection of the inhibitor was at least US$700 000 or more at the time.
In many cases of MIC, I have witnessed main sources of the problem have been (1) lack of knowledge about MIC, (2) mix-up between risk of MIC and its likelihood, (3) misunderstanding MIC, or all of the above!
Below are some of these myths:
) Is biofilm a correct way of addressing the bacterial establishments that induce corrosion?
) Where does MIC happen in pipelines?
) Does the risk of MIC in a pipeline decrease with increasing the linear velocity of the fluid inside the pipe?
) Can we trust the results of the field quick tests about the risk of MIC in our pipeline?
) Is CP effective on prevention and control of MIC in a pipeline?
) How the theory meets the practice: if the MIC is of EMIC, can this prioritise pigging above chemical treatment?
Clearly, there are a lot of published works out there, however, I will offer two works that should be consulted when dealing with MIC.
1.Is biofilm a correct way of addressing the bacterial establishments that induce corrosion?
In 1978, the term ‘biofilm’ was invented to address the bacterial establishments that are often observed on surfaces. The accepted model for explaining biofilm formation in water or water-containing fluids is that the bacteria, dwelling in water, need to find food to let them survive. As long as these bacteria can find food in the bulk water, the bacteria try to reach the food by ‘swimming’ towards it. In this state, they are called free-swimming bacteria, or more technically, planktonic bacteria. However, when the foodstuff – upon the effect of their weight or hydrodynamic conditions of the liquid phase –starts to sink on surfaces, obviously their availability in the bulk water becomes quite limited. Bacteria ‘sense’ this and dive down onto the surfaces to get hold of the food. At this stage, the very same bacteria transform genetically, in addition to becoming motionless on the surface. In this state, they are called sessile bacteria. The genetic changes they undergo will give them the required strength to resist more effectively against hostile external factors such as biocides. The bacterial establishments by sessile bacteria are named biofilm, implying that these establishments are all-biological, as well as acting as a film. Neither of these features are true: in fact, more than 90% of the dry weight of a biofilm is non-biological matter, such as corrosion scales mixed with debris. That could be one of the main reasons that environments with high total dissolved solids (TDS) are more prone to develop MIC. Besides, biofilms have a rather ‘patchy’ fabric and not a uniform, film-like nature. It is via this patchy nature that formation of electrochemical cells – such as differential aeration cells
–occurs (formation of adjacent spots with high and low partial oxygen pressures). It is these electrochemical cells that accelerate corrosion.
In the past, I have suggested the Greek term ‘temenos’ instead of biofilm. The rationale was that the Greek term means ‘cut off’, which puts emphasis on the fact that chemical conditions inside and outside the establishment could be vastly different from each other. For example, while the outer conditions may be oxygenated with a neutral pH, inside the bacterial establishment could be de-oxygenated or acidic. Temenos can protect its habitants from external hostile factors; that is why sometimes, despite using the best biocides, no significant improvement in MIC conditions of the system is observed. Temenos can also – under certain conditions –decelerate corrosion.
2.Where does MIC happen in pipelines?
Due to the very nature of fluids, MIC is highly likely to occur in the bottom of the line (BOL) sector of the pipe, mainly at the 6 o’clock position and/or within a 30˚ sector of the lower part of the pipe. In addition, temenos prefer to be formed on weld zones. The reason MIC is expected to happen in BOL and not TOL sector of a pipe, is that the bacteria need to go after the foodstuff that has sunken on surfaces. BOL is the most appropriate section of the pipe in which MIC risk is high; weld zones, particularly a heat affected zone (HAZ), can provide bacteria with the food they need in the form of alloying elements liberated from the parent material that had been corroded via mechanisms such as weld decay. In fact, post-hydrotest MIC occurs after non-MIC corrosion has already happened. This means that, if non-MIC corrosion starts as a result of welding and post-welding practices not being carried out correctly, then the existence and activity of corrosion-related bacteria will precede. Alternatively, this can be translated as not expecting MIC to happen in seamless pipelines.
3.Does the risk of MIC in a pipeline decrease with increasing the linear velocity of the fluid inside the pipe?
It has been believed that by keeping the fluid flow, likelihood of MIC will decrease. This might be true only before temenos forms. The reason is that after the bacteria managed to enter sessile state and form temenos, increasing the linear velocity of the fluid can serve to ‘spread’ the germs all along the pipeline, possibly contaminating the sections that had been left untouched so far. Therefore, the best advice is not to let stagnation happen in the first place; fluid stagnation can occur due to bad design (too much horizontal branching) and/or low performance pumps, for example.
4.Can we trust the results of the field quick tests about the risk of MIC in our pipeline?
Partially. The current technologies applied to so-called quick field tests relies on reporting bacteria count as cells per millilitre (cell/ml). Obviously, this shows planktonic bacteria. As illustrated earlier, it is the sessile bacteria that are highly likely to form temenos and possibly accelerate corrosion
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via MIC mechanisms. For this, cell/cm2 (number of cells per surface area) will be the ‘Holy Grail’. However, for many practical reasons, it is important to have both numbers of planktonic as well as sessile bacteria.
5.Is CP effective on prevention and control of MIC in a pipeline?
Apart from the case in which MIC occurs on the external surface of buried pipelines, microbial corrosion is a matter of internal corrosion whereas CP is a technique to contain and control external corrosion. Therefore, it is not likely for CP to control internal corrosion in the form of MIC. However, if MIC occurs on the external surface of a pipeline, the impact of CP is inconclusive. Under some conditions, applying a negative
overpotential of -100 mv (vs Cu/CuSO4) may work to control SRB-induced MIC, however, there have been documented cases that applying even -900 mv overvoltage has made no difference in stopping external MIC, and may even enhance it. The reason is still not clear.
6.How the theory meets the practice: if the MIC is of EMIC, can this prioritise pigging above chemical treatment?
While chemical MIC (CMIC) puts the emphasis on chemical factors to explain MIC, electrical MIC (EMIC) assumes that corrosion happens via external electron transfer (EET) between the metal and the bacteria. By EMIC, it is the bacteria that acts like a cathode, and the metal like the anode. The corrosion rate observed via EMIC are about 1.60 times more than that of CMIC and thus much closer to the corrosion rates observed in reality. Two parameters that can be used to estimate if the prevailing reaction is CMIC or EMIC are the weight percentage of iron sulphide in overall corrosion products and the observed corrosion rates.
If the prevailed MIC mechanism is EMIC, it means the bacteria are ‘attached’ onto the internal wall of the pipe. Therefore, even after pigging, there is still a chance the bacteria will remain and thus corrosion will continue. Thus, the best treatment would be to apply a suitable biocide (or a double regime of biocide) to kill as much bacteria as possible, and then begin pigging.
Building on Dairyland’s proven history of industry-leading product lines, the PCRX® represents the next technological leap forward in decoupling technology. Using a sophisticated design, the PCRX’s new camouflage technology renders it virtually invisible to interrupted survey testing making it easier than ever to protect and maintain your CP system.
MIC is a complicated process compared to other corrosion processes. Being electrochemical in essence, mainly because of the involvement of living organisms such as bacteria/archaea, algae and fungi, the expected processes and reactions could be far more complex than it may seem at the first sight.
While under real working conditions in assets such as pipelines, more than one corrosion process could be operative of which MIC could be just one; it is important to distinguish ‘series’ and ‘parallel’ corrosion reactions from each other. In addition, in-depth understanding of MIC is highly required.
1. JAVAHERDASHTI, R., ‘A Pathological Mini-Atlas of Microbiologically Influenced Corrosion and Deterioration (MIC / MID) cases’, Trans Tech Publications Ltd, 2022.
2. JAVAHERDASHTI, R., AKVAN, F., ‘Failure Modes, Effects and Causes of Microbiologically Influenced Corrosion: Advanced Perspectives and Analysis’, Elsevier, 2020.
ctivities during oilfield operations (such as hydraulic fracturing, wet parking, etc.) introduce moisture or water as well as various microorganisms to production infrastructures; under ideal conditions biofilms can develop on exposed steel surfaces.
The metabolic activities of microorganisms inhabiting the biofilms can generate localised differences in electrochemical potentials as they may secrete acidic metabolites or enzymes that can accelerate metal oxidation, thus posing the risk for microbiologically-influenced corrosion (MIC).
The microorganisms likely to cause MIC can thrive in a wide range of conditions – in terms of salinity, pH, temperature, oxygenation, nutrients availability, etc. – and survive in harsh environments. When the situation is unfavourable to biofilm growth, they may enter a dormant stage until circumstances allow them to flourish again, making MIC a potentially recurring issue.
Unfortunately, MIC is notably difficult to detect and monitor in oilfield installations – especially since the available molecular methods used to characterise microorganisms in such environments are limited to some subsets of the microbial groups linked to MIC, and do not create a comprehensive picture of system integrity.
Culture-based tests of water samples may be poorly representative of the biofilm communities that exist in oilfield situations. Moreover, the analysis of molecular data as well as that of data generated directly on oilfield samples typically fall short of establishing a direct correlation between microbial concentrations and actual corrosion (as exemplified by the failed attempt to consistently correlate numbers of sulfate-reducing bacteria to the occurrence of MIC in oilfield infrastructure).
Consequently, current molecular methods do not provide reliable prediction of MIC or evaluation of biocide performance for MIC prevention.
At present, MIC is most commonly identified – generally through material testing and biofilm analysis – after damage has already occurred and abiotic origins have been excluded as root causes. Therefore, microbial activity detection in oilfield facilities is often late, and MIC management is reactive instead of proactive.
While microbial corrosion risk assessment, mitigation, and monitoring is largely understood to be a crucial part of pipeline operators’ integrity management systems, the relative limitations of currently-available methods for MIC prevention poses a great challenge to the industry. Operators are exposed to resources and time waste, and in the worst cases, shortened service life or infrastructure failures if MIC is not controlled in time. Consequences of MIC-related failures can include extensive pipeline rupture, as was the case during a fatal pipeline incident that occurred in Carlsbad, New Mexico in August 2000. The rupture was later revealed to have been caused by a significant reduction in pipe wall thickness due to severe internal corrosion caused by microorganisms in combination with abiotic factors, and a deficient internal corrosion management programme.1 Other instances have caused the temporary cessation of operations and/or loss of containment of various oil and gas assets over the past decades.
A proposed solution to the MIC late diagnosis issue is being explored through a collaborative industry effort that aims to identify biomarkers indicative of generic instances of MIC in oilfield water samples.
Indeed, biofilms often grow in locations unsuited for the installation of microbiological analysis and monitoring devices in appropriate and representative positions (buried piping, subsea pipelines, etc.), but generally produce specific aqueous molecular signatures (DNA, proteins, metabolites, cells,
etc.) that are carried downstream along with process-associated waters where, in principle, they can be collected for analysis.2
The analysis of water samples containing these molecular signatures offers insights into the metabolic potential as well as the actual activity of environmental microbiomes, which in turn can be useful to gain ever deeper insights into oilfield MIC.3,4,5
Shotgun metagenome sequencing can now reveal the genetic blueprint of entire microbial ecosystems, while analysis of the collective proteome of environmental samples allows for the unraveling of the physiological response of a microbial community to its surroundings.5,6,7 At the same time, high-throughput approaches to quantitative Polymerase Chain Reaction (qPCR) tests and immunoassays are making it increasingly affordable to generate large datasets that allow a deeper understanding of specific and quantitative molecular data.
Recent work has already shown that genetic markers for special (NiFe) hydrogenases in methanogenic archaea offer promise as predictive biomarkers for severe MIC caused by oilfield biofilms.1
A 3 year joint industry project (JIP) was recently proposed by DNV, ExxonMobil, and Microbial Insights, Inc., with the idea of combining the expertise and field experience of environmental forensics, microbial ecology, oilfield corrosion, chemicals, and MIC specialists from across the field to unravel the microbial degradation mechanisms at play in oil and gas operations, understand their interrelation with abiotic corrosion, and develop a technology that detects MIC via the molecular analysis of DNA-based and/or protein-based biomarkers in pipeline-associated waters.
The technology would apply advanced molecular biological methods such as (meta) genomics and (meta) proteomics, and develop new mechanistic qPCR and enzymatic immunoassays (EIAs) to discover biomarkers and create a data interpretation chart of about 1200 corrosion-to-biomarker correlation points. These reference points generated on simulated pipelines with actual field waters and service conditions will ultimately allow for the ‘generic’ detection and monitoring of the most relevant types of MIC by translating field biomarker concentrations to integrity threats.
The development of this MIC biomarker technology aims to deliver specific methods for water sample collection, preparation, and molecular analysis, as well as key performance indicators (KPIs) and data interpretation tools that enable the development of better actionable MIC management practices.
Ultimately, this technology is needed by operators for implementing the next generation of MIC detection, monitoring, and mitigation programmes (leading to fewer MIC-related failures, and prolonged infrastructure service life), and for chemical vendors for validating the performance of their products in oilfield pipelines.
The JIP will heavily leverage advanced laboratory (bio)reactors, and molecular analytical platforms that have been specifically developed for MIC biomarker discovery and KPI building. The proof of principle for this approach has recently been demonstrated.2
Laboratory simulation will be conducted using waters or solids collected from operating oilfield assets with either a history of MIC concerns or service conditions of specific interest. Particularly troublesome instances of MIC with samples from assets spanning a variety of conditions across the globe will comprise the core experimental framework.
Developing dependable correlations between molecular data and corrosion solely through the investigation of samples originating from oilfield facilities is next to unfeasible, as such samples intrinsically lack the metadata required to establish a direct correlation between the observed biofilm ecology and MIC rates. Indeed, whether a pipeline experienced active microbial corrosion at the specific time that a sample was collected cannot be known for large numbers of samples.
Alternatively, laboratory sample testing typically fails to accurately simulate oilfield conditions – incubating microbial cultures for prolonged periods when ‘in situ’, water usually has a short residence time in infrastructure, or failing to replicate the combined impact of shear stresses, chemical use, pressure, etc. on MIC.8,9
ExxonMobil’s innovative solution – automated pipeline ecosystem simulators (APES) – are specialised corrosion-testing autoclaves operated in a semi-continuous mode, using actual oilfield waters. Capable of closely simulating field temperature,
Note on Figure 2
Corrosion rates and micC gene count in effluent waters from two APES trains with different sources of microbial inoculation. CO2 corrosion rates (0.5 ± 0.04 mm/yr) from a sterile control experiment are also depicted for reference (shaded area). Biofilm containing large fractions of common oilfield sulfate-reducing bacteria (SRB) grew in both experiments. Biofilm (B) caused little MIC (experiment A), while biofilm (D) caused severe corrosion (experiment C). The biomarker under study in this example is a gene cluster encoding for multi-heme cytochromes (‘micC’) that have a putative role in MIC. The putative biomarker (development ongoing) may detect the presence of a particular group of severely corrosive biofilms in oilfield pipelines. Batch biocide application (1000 ppm glutaral-dehyde, 4 hr) diminished microbial corrosion rates (C).
pressure, shear stress, acid gas composition etc., they allow for testing with and without microorganisms.
APES will be used to generate defined water samples that will be further checked through select analyses of actual oilfield samples to discover biomarkers, and to develop frameworks for data interpretation and system performance (KPIs). APES tests will run over several months to generate the 1200 envisioned water samples, each associated to relevant metadata (including corresponding MIC rates).
By making use of analytical workflows and platforms that were specifically developed for MIC biomarker discovery, and combining available and newly generated data, the project will uncover commonalities to develop generic and widelyapplicable MIC biomarker assays. The JIP will also include tests with chemical mitigation to better understand the impact of biocides on MIC rates and corresponding biomarker concentrations.
Oil and gas pipeline and plant operators have everything to gain from collaborative research like that conducted for the ‘Biomarkers for next-generation, water-based detection and monitoring of MIC’ JIP.
The development of a more dependable framework for the diagnosis of microbial degradation mechanisms will eventually enable the whole industry to implement better MIC prevention and mitigation measures, ultimately saving billions in cost, reducing failure risk, and extending asset life.
1. NATIONAL TRANSPORTATION SAFETY BOARD, ‘Pipeline Accident Report Natural Gas Pipeline Rupture and Fire Near Carlsbad, New Mexico August 19, 2000’, www. ntsb.gov/investigations/AccidentReports/Reports/PAR0301.pdf, (Accessed January 2023).
2. LAHME, S., MAND, J., LONGWELL, J., SMITH, R. AND ENNING, D., ‘Severe corrosion of carbon steel in oil field produced water can be linked to methanogenic archaea containing a special type of [NiFe] hydrogenase’, AppliedandEnvironmental Microbiology (2021).
3. BONIFAY, V., WAWRIK, B., SUNNER, J., SNODGRASS, E.C., AYDIN, E., DUNCAN, K.E., CALLAGHAN, A.V., OLDHAM, A., LIENGEN, T. AND BEECH, I., ‘Metabolomic and metagenomic analysis of two crude oil production pipelines experiencing differential rates of corrosion’, FrontiersinMicrobiology (2017).
4. VIGNERON, A., ALSOP, E.B., LOMANS, B.P., KYRPIDES, N.C., HEAD, I.M. AND TSESMETZIS, N., ‘Succession in the petroleum reservoir microbiome through an oil field production lifecycle’, The ISME Journal (2017).
5. BARTLING, C., KUCHARZYK, K.H., MULLINS, L., MINARD-SMITH, A. AND BUSCHHARRIS, J., ‘Interpreting Omic Data for Microbially Influenced Corrosion: Lessons from a Case Study Involving a Seawater Injection System’, CORROSION 2017 (2017).
6. KLEINER, M., WENTRUP, C., LOTT, C., TEELING, H., WETZEL, S., YOUNG, J., CHANG, Y.J., SHAH, M., VERBERKMOES, N.C., ZARZYCKI, J. AND FUCHS, G., ‘Metaproteomics of a gutless marine worm and its symbiotic microbial community reveal unusual pathways for carbon and energy use’, ProceedingsoftheNationalAcademyof Sciences (2012).
7. BERGAUER, K., FERNANDEZ-GUERRA, A., GARCIA, J.A., SPRENGER, R.R., STEPANAUSKAS, R., PACHIADAKI, M.G., JENSEN, O.N. AND HERNDL, G.J., ‘Organic matter processing by microbial communities throughout the Atlantic water column as revealed by metaproteomics’, ProceedingsoftheNationalAcademyof Sciences (2018).
8. MAND, J., AND ENNING, D., ‘Oil field microorganisms cause highly localized corrosion on chemically inhibited carbon steel’, MicrobialBiotechnology (2020).
9. LIU, T., CHENG, Y.F., SHARMA, M. AND VOORDOUW, G., ‘Effect of fluid flow on biofilm formation and microbiologically influenced corrosion of pipelines in oilfield produced water’, JournalofPetroleumScienceandEngineering (2017).
27-28 March 2023
29 March 2023
In 2023, we will be celebrating the 16th anniversary of the European Gas Conference (EGC) where we will identify who the new suppliers will be to Europe as we phase out Russian gas as well as navigating this volatile landscape.
This will be followed by The European Hydrogen Conference (EHC) which has been created to focus on the latest projects and technologies to make Europe’s hydrogen economy a reality.
Speakers include:
To find out more and get the latest agenda, visit:
https://energycouncil.com/egc-2023
https://energycouncil.com/ehc-2023
Eric Festa VP LNG Infrastructure TotalEnergies Peder Bjorland VP, Gas Trading & Marketing Equinor
Andrew Walker VP Strategy Cheniere Marketing
Pierre-Germain Marlier VP Investment Hy24
Fatemeh Rezazadeh VP, Hydrogen VARO Energy
Christian Synetos Director, Global Energy & Power Team Blackrock
Chikako Ishiguro Senior Analyst, Energy Resources Osaka Gas Co
Andree Stracke CEO RWE Supply & Trading Matthew Baldwin Director, DG Energy European Commission
Patrick Dugas VP LNG Trading TotalEnergies
Luca Schieppati Managing Director TAP
Peter Mackey VP Strategy & Policy Support, Hydrogen Energy Air Liquide
In line with the energy industry’s new demands to meet energy transition goals, maintaining the integrity of assets has never been more important. Helping to accurately identify, forecast, prevent, and communicate any potential corrosion, leaks, or other anomalies, pipeline inspection is vital to mitigating the risk of operational failure or preventing harm to personnel and the surrounding environment. Due to the highrisk nature of the industry, issues like this cannot go undetected or overlooked as it could lead to major damage to the environment or crew. Stringent adherence to compliance and safety policies is essential to ensuring the quality of assets, safety of the crew, and sustainability of the operations. With safety and efficiency at the forefront of all major oil and gas projects, the importance of attention to detail and quality assurance is undeniable.
As eyes and ears for the client, Fulkrum is playing a pivotal role in ensuring compliance and assurance for the largest oil project in Guyana, while simultaneously supporting the development of one of the industry’s most significant gas-to-energy projects in offshore Guyana. Through the delivery of its highly regarded inspection services, Fulkrum provides its clients the opportunity to detect any quality or contamination issues during the entire lifecycle of the project, thereby minimising any potential safety, budget and schedule risks resulting from sub-standard work or non-compliant material.
Fulkrum is a leading global inspection, expediting, auditing, and technical staffing service provider that operates in more than fifty countries across the UK, Europe, the Americas, the Middle East, and APAC. It supports its clients with local market intelligence and an active database of more than a million global engineering, technical, and manpower resources. From offshore S-Lay (shallow and
deepwater) and offshore J-Lay to offshore flexible pipelay and cable spooling, shore-pulls, and onshore installations (including trenching), Fulkrum has worked on a range of global pipe production and pipeline installation projects. With expertise spanning the entire oil and gas supply chain, Fulkrum recognises the complex issues faced in the industry every day and rises to the challenge, strives to mitigate risk, reduce cost, and improve efficiency across the entire energy industry.
With safety and efficiency at the forefront of operations, the expert team is committed to ensuring its clients meet and exceed the requirements for quality and safety, and always deliver what they promise. Fulkrum’s esteemed professionals instil confidence in its clients, ensuring that the purchased equipment will be thoroughly evaluated to ensure the assets are compliant with all relevant standards whether it be regulatory, end user mandated, or voluntary. Ensuring the equipment will arrive to the correct specification, Fulkrum covers all manufacturing and fabrication facilities internationally, and guarantees stringent adherence throughout the entire lifecycle of the project so that its clients will fulfil their contractual obligations with assets that are safe, efficient, and reliable.
When focusing predominately on the coating stage, Fulkrum will ensure the steel pipes and ID/OD coating is
fit-for-purpose, ultimately saving the client time, cost, and materials. From checking for any potential damage from storage and transport, to inspecting the integrity of the asset for compliance, Fulkrum’s local inspectors will begin the project with a pre-qualification test to determine if the pipes are in adequate condition to be approved for coating.
The five-layer polypropylene thermal insulation coating (5LPP) application phase involves two stages, the first being a fast-curing, thermosetting anticorrosion 3-layer polypropylene coating application, comprising FBE, polypropylene, adhesive, and solid polypropylene. When applied properly, these provide the base for guaranteeing an anti-corrosive protective layer that lasts for decades. Upon completion of the first phase of the coating process, the pipe will then undergo a second phase which consists of a syntactic polypropylene layer followed by a polypropylene topcoat application, to provide thermal insulation. With the inclusion of an abrasion resistant overcoat (ARO) system, the 3LLP and 5LLP multi-layer processes benefit from even greater insulation thanks to the carefully applied sequence of materials. The fifth and final layer, a solid polypropylene topcoat, completes the process and ensures complete corrosion protection. Once the coating process is completed and has been fully inspected, the pipes are then released for application and to undergo the quality testing process.
From long-term corrosion protection to abrasion and impact resistance, multi-layer coating ensures pipeline protection in extreme temperatures, even in wet conditions, making it a strong and often easier-to-work-with option for operators. Pairing the multi-layer coating and FBE coating processes is quickly becoming the industry standard.
As the intermediary between the client and the supplier, Fulkrum’s inspectors ensure the quality of work meets or exceeds the industry standards. Since corrosion and coating quality issues can be one of the major contributors to product failure during operations, attention to detail is the top priority for Fulkrum. In addition to environmental damage, unidentified and unrepaired issues can result in delayed production time and pipe needing to be transported back to the shore base to have the coating peeled back and reapplied, substantially increasing cost, waste, and downtime.
Fulkrum’s pre-qualification testing and inspection process involve witnessing pipe movements to ensure they are unloaded correctly at the port and subsequently transported to the coating yard. This is followed by a thorough inspection, examining for damage and contamination by oil, graphite, or other environmental factors encountered during transport that may negatively impact the steel surface of the pipe and bonding of the coating. Throughout the pre-qualification testing, all FBE and multi-layer coating activities and testing, storage, and loading to the client site or vessel, Fulkrum’s inspection and surveillance services ensure compliance of the suppliers and assurance of quality throughout the process. From documentation review and approval, to closing out NCRs and traceability of all batches or lots of materials used for
Figure 1. Pipes after finished production.
coating each piece of pipe, Fulkrum provides its clients with the confidence and assurance that the pipe-coating process is fully compliant.
Throughout the inspection process, Fulkrum inspectors use non-conformance reports (NCRs) to document any findings, inconsistencies, or areas of concern during an assessment or inspection, but most importantly they require evaluation and engineering dispositions to ensure that material is compliant, sustainable, and the risk of the non-conformance reoccurrence is mitigated.
During the inspection of a recent project for a client, the inspectors documented inconsistencies in an NCR following the temperature report of the pipe surface prior to coating. The Fulkrum inspector found inconsistencies during the review of the temperature report throughout the WI flowline PQT on 355.6 mm OD x 30.5 mm WT. It was found that the temperatures recorded at the exit of the induction coil were inconsistent, and the operators were reporting the incorrect temperatures due to the lack of proper training on the equipment and process. The application temperatures were out of the acceptable range according to the calibrated chart recorders, yet reported as acceptable.
Application of any layer of coating at the incorrect temperature is a major concern. Each material used during the application process has a specific temperature range for proper application. When this range is not adhered to, the coating could have issues bonding to the subsequent layers or to the steel, depending on which layer of the process is affected. This lack of bonding can lead to the peeling of that layer of coating (and all above it) and opens the base metal steel to corrosion and eventual failure of the pipe to meet the life expectancy required for an offshore development. In the end, this is a major risk to the environment and an expensive repair if the non-conforming material is not identified prior to the installation of the pipe and is instead identified during subsequent operational inspections, or after a failure.
In conclusion, third-party inspection enables Fulkrum’s subject matter expert QA/QC inspectors to be eyes and ears for their clients. After completing the quality inspection process in these particular projects, it was evident that due to the supplier’s substantial team growth, many of the new employees were lacking the appropriate training and as such, many issues arose, and mistakes were made. Following Fulkrum’s identification of these issues, they were able to take their findings to the client and advise that further training was required and implement a performance improvement plan and approved-only personnel access process.
Held to the highest standard of quality and safety, Fulkrum’s inspection teams can monitor the coating and fabrication of pipelines throughout manufacturing and installation campaigns, which can ultimately lead to early detection of all compliance issues. Compliance is a crucial aspect of any pipeline project, so whether it is rolling pipe, PQTs, coating, cladding, welding, dimensions, NDT, or testing, Fulkrum is on-hand to ensure all safety and quality protocols are followed during pipe production, coating, and installation.
Adam Brown, Technical Sales Manager for Pipelines at Italmatch GB Ltd., is a graduate of RGU with a background in oilfield chemistry. Having joined Aubin in 2013 as a product development chemist, Adam has been able to take products from design through to trial and ultimately, deployment. With 10 years’ experience in product application, Adam continues to work closely with customers to help deliver a solutions-based approach.
ADAM BROWN
Having recently been acquired by Italmatch, the Aubin brand of pipeline pigging chemical solutions remains a proven, reliable alternative to traditional pigging methods both in conventional operations and in co-called ‘un-piggable’ lines.
Whilst not a provider of intelligent pigging tools for pipeline inspections, many products from the Aubin Pipeline Toolbox can be utilised to improve the efficiency or de-risk these operations. Whether in de-watering applications where the highly efficient seal of our EVO-Pig results in significant reductions in air drying, or where our range of gels such as Aubin Debris Pickup Gel can be used in pre-run cleaning, the goal remains to offer a technical led solutions-based approach.
ADAM BROWN
There is obviously, and rightly, many discussions regarding the future of oil and gas pipeline operations. Decommissioning and re-purposing will continue to play a significant part for pipeline operators, with a number of fields and infrastructure working beyond their expected lifetimes. Maintenance and cleaning operations to remove contents can prove challenging with many lines having deviated considerably from their ‘as-built’ origins and without clear plans for abandonment. Aubin EVO-Pigs and Pipeline Gels can offer a safe, and efficient means to de-crude and clean small, <6 in., through to large 48 in. bore lines which may also include challenging geometries, multiple-bore, or flexible nature. The absence of dedicated traps, launchers and receivers, can also be overcome utilising the canister delivery method. Aubin EVO-Pigs, supplied in bespoke canisters, can be introduced into lines where full bore access is available, such as behind a valve.
In addition, the patented Aubin TORT, or total oil recovery technique, provides operators with more flexibility in how they can approach pigging challenges. A common difficulty in de-oiling and de-cruding is that of hydrocarbons remaining within high points in a line, either in deviations or defects, or in off-takes. Traditionally, full line flushes with water would be repeated, resulting in both
high water consumption as well as waste generation. Combining our established pigging technologies with lightweight water-based gels can displace and remove these hydrocarbons with excellent separation, as a result of the varied densities and immiscibility of the products; often in lieu of more invasive hot-tapping operations. Instead of focussing on one product or system, consideration is also made in waste reduction, ease of use, and safety of personnel and the environment.
In the next five or 10 years and beyond, there will always be a requirement for tried and tested ‘traditional’ pigging services. What we feel is required, is for organisations to be more open to explore alternative methodologies. Reliance on applications because that’s the way they’ve always been done can result in overlooking alternatives which may offer improvements for your organisation as well as cost saving benefits. We would hope that more organisations see options like the proven Aubin Pipeline range as go-to tools for their operational methodology.
ADAM BROWN
For us, pipeline integrity is the opportunity to provide technological solutions for the lifetime of your asset. We have been involved in pre-commissioning, cleaning maintenance, through to decommissioning in projects across the globe. Working with our customers we look to provide technical support, alongside our chemistries, to overcome a range of challenges.
Figure 1. EVO-Pig LG removal from open ended pipe.
IoT adoption is almost ubiquitous. According to a study by Inmarsat, 74% of oil and gas businesses have deployed at least one IoT project. 1 IoT streamlines pipeline management, delivering 24/7 monitoring, reducing operating expenses, and collecting operational data that can be analysed to deliver actionable insights.
Cellular connectivity for critical infrastructure, such as oil and gas pipelines, is vital. Since cellular connectivity is highly reliable and resilient, it does not face interference due to weather or power conditions like other connectivity types.
As it provides better indoor and outdoor global coverage, it can optimally serve oil and gas smart IoT devices, for example, unmanned exploration rigs and remote wellhead monitoring sensors. Furthermore, cellular connectivity provides better protection against the increasing number of IoT cyberattacks due to built-in security measures – including standard usage of encryption and the fact that each IoT device identity is authenticated and protected. Cellular NB-IoT and LTE-M in smart gas and oil flowmeters can transmit very low data rates while ensuring the longevity of battery life.
With the introduction and gradual deployment of 5G technology, a new digitisation era has started, connecting more devices at higher density and speed with lower latency, making operations more cost-efficient. This enables better predictions, and gains value-added services such as achieving higher productivity and reliability through automating pipeline processes using automated guided vehicle systems (AGVs).
The key to maximising the value of cellular IoT connectivity within the oil and gas infrastructure is granular policy-driven management and comprehensive security. The granular
Benefitting fully from IoT growth requires a focus on connectivity management and security, says Adam Weinberg, CTO and Co-Founder, FirstPoint Mobile Guard, Israel.
management allows flexibility in meeting the IoT-specific use-case needs, while security is critical to prevent IoT cybersecurity attacks, which are growing at alarming rates.
Inmarsat reports that 55% of survey respondents said that the most critical additional skill necessary to deliver IoT projects is security. Technology, though, is available to address that deficit.
Ideally, a user-friendly platform makes it easy to apply granular policies to different groups of devices to ensure more control over individual device security and operations. For example, stationary IoT devices and mobile IoT devices require different policies, so that if a stationary device such as a smart flowmeter changes location, it likely indicates a security breach. While if the mobile device such as telemetry in exploration and maintenance vehicles changes location within a certain area, that is perfectly normal.
When it comes to data transmission, different devices in different use cases require different connectivity rules related to data volume and rate. For example, surveillance cameras may send significant volumes of data at high rates, while smart flowmeters will send small amounts of data periodically. So, network configurations and policies need to adjust. Once a policy is set but the device shows an abnormal behaviour, if a once-daily sensor starts sending continuous data, it can indicate the device has a defect or a threat actor may be trying to drain its battery so they can make mischief on that part of the pipeline. Such policies can be defined manually or automatically using a wide range of machine learning algorithms, such as anomaly detection algorithms.
Private IoT cellular networks make it easier to control traffic, achieve a higher level of security, and ensure the right capacity is available ‘for the job’. External service fees are eliminated, redundancy is easier to implement, and availability is continuous, as the network is solely owned by the oil and gas company and not shared.
Private networks also face their own challenges. They are location-specific, and individual cells and towers need to be installed close together to maintain connectivity. Of course, a private network can be more easily ‘brought down’ when necessary for maintenance and repairs –but the oil and gas company must be the organisation performing this continuous maintenance, repairs, and upgrades, burdening personnel and administration systems alike. The choice of spectrum and its management is also a challenge – the spectrum can either be licensed from a larger carrier or the oil and gas company can use unlicensed spectrum; however, the amount of spectrum that is available for public and unlicensed use is very small, and the size of the area and the lack of exclusivity mean there’s greater potential for interference from other mobile devices located nearby.
When it comes to the public network, the oil and gas company has two options – become a mobile virtual
network operator (MVNO), or simply be a client of cellular connectivity services. Both options completely eliminate the need for the hardware and software installation, maintenance, and upgrades of building a private network. As an MVNO, the oil and gas company rent the line, maintaining full control over all the network devices, paying the network operator for connectivity usage at wholesale prices. Based on the volume of devices –more than 200 000, for example, when using the right connectivity and management tools, it is much more cost effective to become the MVNO than to be charged on a per-device basis as a ‘regular customer’ of the mobile network operator.
Some organisations are using both private and public networks. For example, the oil and gas company may use a private network for a pumping station and a public network for the length of the pipeline. No matter which way the oil and gas company goes, it’s important to also consider backward compatibility to support brownfields – the devices already in the field – using any cellular technology in the range of 2G to 5G, as well as topologies where the devices connect through a cellular-based gateway.
The key issue facing cellular IoT devices or, in fact, any IoT device, is security.
Just consider; the 2021 Colonial pipeline ransomware attack affected pressure sensors, thermostats, valves, and pumps – all based on IoT. 2 In 2017, a petrochemical plant in Saudi Arabia was attacked via its IoT devices. 3 The attack was a failure simply because of a coding error by the threat actors themselves.
In June of 2022, the cybersecurity company Trend Micro reported that 89% of electricity, oil and gas, and manufacturing firms have experienced cyberattacks impacting production and energy supply over the past 12 months. 4
Here are some of the most common IoT attack types:
• This type of attack exploits cellular network flaws or uses malware installed on the device to deny a device network access.
• The impact: The DoS attack affects the whole network by preventing access to the server or any IoT components, therefore violating one of the essential components of cybersecurity – availability. In case of emergency, or when it comes to missioncritical connected devices, such an attack can be catastrophic. For example, it can cause an entire fuel pipeline outage.
• This type of attack exploits cellular network flaws or weaknesses to remotely track the location of any IoT or mobile device globally, reveal the permanent identity of the target, and even reveal
the associated Mobile Station Integrated Services Digital Network (MSISDN) number.
• The impact: Detecting the location of IoT devices such as ‘smart pig’ (pipeline inspection gauge) robots can become a major threat. Detecting the identity is even worse, leading to highly severe further attacks, as it is much easier to manipulate the device.
• This particularly nasty attack exploits two-way communications, and can listen in on voice and video communication and IP/data transfer.
• The impact: Attackers can gain access to valuable private or business data on the device.
• In this attack type, the attacker poses as a trusted entity to the network on the one hand and to the device on the other, enabling the attacker to present fake data to the network or control the device.
• The impact: Such an attack can be used to cause functionality disorder, for example, by controlling oil pumps, sending fake data or commands between the devices and the network.
• IoT device sensors such as temperature, humidity, acceleration, and pressure sensors, allow real-time intelligence gathering. This makes IoT devices a prime target for information theft by attackers.
• The impact: Attackers can gain access to valuable private or business data on the device. For example, such an attack can gain the attacker information about the pipeline traffic.
For any organisation, cyberattacks are a when, not an if. It’s critical to have a cellular network-focused solution delivering extremely secure connectivity. The solution needs to give IT administrators easy and granular device management with simple network, security, and business policy configurations. The solution should include continuous monitoring of IoT devices and provide alerts when the devices behave against policy. Deployment should be simple as well – either on the cloud or within the existing on-premise or hybrid infrastructure, with APIs easing integration into existing systems.
In addition, the core network technology must be able to support both forward and backward technologies, from 2G to 5G, as well as NB-IoT and LTE-M.
With full network control of IoT cellular devices, oil and gas companies can streamline logistics and operations while ensuring reliable connectivity.
IoT connectivity and cyberattacks are givens in the oil and gas industry, really any industry – or household, even. The challenge is managing and securing the first to prevent the second. Organisations need to understand the tradeoffs between efficiency and security. However, with the proper security technologies in place, oil and gas pipelines can be both efficient and secure.
1. www.inmarsat.com/en/insights/enterprise/2021/research-programme-2021-oil-gas. html#:~:text=IoT%20adoption%20levels%20are%20reaching,the%20technology%20to%20the%20 industry
2. www.bbc.co.uk/news/technology-57063636
3. dergipark.org.tr/en/download/article-file/2160183
OUR BALL VALVES
GO BEYOND THIS DISPLAY AND YOUR
EXPECTA-
ith assets distributed across vast and frequently isolated locations, many pipeline operators are increasingly implementing remote operations centres (ROCs) to monitor their production from afar. But making sense of dispersed operations requires synthesising and contextualising information from several sources.
As companies increasingly adopt Software as a Service (SaaS) technologies in the cloud, the accessibility and connectivity to data continues to increase. And these technologies play a significant role in helping organisations connect all of their data, create insights, and improve operational decision-making. By leveraging these efficiencies, along with lessons learned from distributed working environments during the pandemic, companies are continuing to progress toward remote operations.
While autonomous operations are the ultimate goal for many organisations, remote operations powered by digital solutions are a key steppingstone toward success. Companies are leveraging SaaS technologies, such as self-service advanced analytics solutions, to drive a cultural change across the industry by enabling remote ROCs to perform crucial monitoring activities, for example, exception-based surveillance at scale to optimise site resources on the highest priority issues.
For pipeline operators just beginning the digital transformation journey, the first steps toward remote operations are making asset data available throughout the enterprise in near-realtime, and prioritising asset maintenance. These tasks help engineers and operators become familiar with typical processes and establish operational baselines, centred around the most
critical instrumentation and equipment. But even after this data is made available and prioritised, many challenges lie ahead.
Traditionally, engineers reviewed most historical process data using manual tools like spreadsheets. But these are cumbersome to manipulate and derive analytical insight from, and particularly difficult to scale across more than just a few assets, since keeping track of numerous variables is nearly impossible when left to manual methods (Figure 1). Additionally, spreadsheets provide limited calculation capabilities, restricted sharing and collaboration functionality, and intermittent connectivity to sensors in the field. Fortunately, modern software solutions are easing data connectivity, collaboration, analysis, and scalability pain points.
Many of the largest oil and gas companies in the world are turning to advanced analytics solutions, such as Seeq, to provide automated and self-service analytics capabilities for subject matter experts (SMEs). These modern solutions empower SMEs to identify unique periods of interest in their data, characterised by qualities known as conditions, to identify when equipment is exhibiting abnormal operational behaviour.
These conditions can be established by superimposing multiple operational parameters, then defining time periods of interest by finding rapid process value changes, specific signals, or trends that exceed static operating limits (Figure 2). This
As companies prioritise remote and autonomous operations, advanced analytics applications provide the operational insights, modelling, and data-sharing capabilities to help get there, says Morgan Bowling, Industry Principal, Seeq, USA.
process is easy in a point-and-click environment and can even be configured with machine learning models, without requiring IT resources to assist with data queries.
Once unique conditions are defined for a single asset, advanced analytics applications make it easy to scale the same configuration across a fleet of similar pieces of equipment for near-real-time monitoring. Once SMEs have access to data, and conditions are scaled enterprise-wide, exception-based surveillance at scale in a remote facility can begin.
Marathon Oil, a major oil and gas provider, utilised this approach to deploy their Digital Oilfield Project for exception-based surveillance across their fleet of wells, with only limited onsite resources.1 Before launching this project, the company kept data siloed in disparate systems, requiring intensive manual processes to cleanse and use in calculations, in addition to long lead times for receipt of internal development resources.
By deploying Seeq, this provider established automated and convenient time series analytics and intelligent alerting capabilities across assets throughout the enterprise. These intelligent alerts are used to drive and prioritise maintenance tasks and work orders for personnel in the field, and they empower operational teams to reduce unplanned outages, ultimately increasing productivity and profitability.
Once teams are equipped with the appropriate advanced analytics solutions to complete monitoring at scale, the next step towards remote operations is relocating non-essential personnel from industrial facilities to perform monitoring
and reporting in a central location. Moving separate teams together in an ROC increases natural opportunities for knowledge-sharing and cross-team collaboration, which can have positive results across an entire company. Yet, the idea of remote monitoring was historically foreign to many oil and gas companies because legacy expectations influenced most companies to require their resources report to production sites daily.
ROCs empower companies to monitor assets on a regional, or even global, basis more efficiently than individuals monitoring at each site. Additionally, staff within remote monitoring teams become more familiar with systemwide equipment operations, failures, and faults, enabling them to provide better guidance on how to resolve issues based upon the sheer number of assets they watch each day.
Deepwater Subsea, a real-time monitoring and support services provider in the oil and gas industry, maintains an ROC focused specifically on remotely monitoring blowout preventer (BOP) systems located around the world.2 Using Seeq, synthesising and scaling data from one facility to the next is easy, and SMEs can glean insights both within single facilities and by comparing data and trends from one asset to the next.
SMEs within the ROC apply their domain expertise to help detect BOP system anomalies for near-immediate reporting to the appropriate operations teams. This enables accurate and timely quantification of changes in BOP control system performance, pressure leaks, and more, and the interfaces of the advanced analytics application provide convenient means of sharing this information and linked insights with
oil rig personnel. With this application, users can capture, combine, and overlay relevant historical data to analyse asset performance of many processes, such as pressure tests. This helps personnel monitoring various facilities and rigs ensure equipment mechanical integrity remains in top shape.
Using Seeq, SMEs at Deepwater Subsea accurately quantified the rate of change for a small pressure leak in a customer’s BOP system. After the leak was discovered, the advanced analytics application helped synthesise the required data to submit a report to the governing regulatory agency showing the leak would not impact BOP performance. The agency’s prompt approval of this report allowed the operator to keep its BOP systems in production, avoiding downtime losses valued at approximately US$2.5 million.
In addition to monitoring BOP systems, Deepwater Subsea helped one of its operators extend BOP testing intervals from 14 to 21 days, saving them approximately US$10 million annually per rig. These testing interval extensions not only decreased downtime, but also led to more thorough analyses, which pinpoint issues more specifically. This helped speed up maintenance and repairs by ensuring the right parts and personnel were available to perform the required work.
By relocating non-essential plant personnel to ROCs, oil and gas companies can significantly decrease workforce health and safety risks. These sorts of arrangements can often also lead to flexible working arrangements employees desire, such as hybrid schedules.
For many companies developing digital visions for remote operations before the pandemic, COVID-19 increased the rollout rate because remote operations were often the difference
between staying online and shutting down due to labour shortages and mandated closures.
One of the lasting changes of that era is the increased level at which companies embrace and adopt cloud technologies today. Operators and producers once hesitant to adopt SaaSbased solutions have seen the flexibility they provide, and advanced software and digitalisation solutions once seen as niceto-haves are now the only sensible options for connectivity and enterprise-wide accessibility.
Among looming energy transitions and changes in traditional expectations for onsite work in many industries, oil and gas companies need to keep pace even outside of the industry to maintain top talent. Technical employees in particular, such as engineers, value innovative work environments, and for this reason it is important for companies to rebrand previously hierarchical and rigid structures to incorporate digital advancement and workplace flexibility. In addition to innovation, digital tools help drive sustainability initiatives, including goals such as net-zero emissions.
With many companies in the oil and gas sector on the path of digital transformation, scaling asset analyses and implementing ROCs are some of the next logical steps. These advancements empower producers and providers to innovatively develop and iterate, and decrease operational disruptions enterprise-wide. With these improved capabilities, industry-leading pipeline operators will continue to glean insights, propelled forward by cutting-edge technologies and technical teams to maximise productivity and efficiency.
References
1. lp.hartenergy.com/WBR10-October22AWSSeeq10-13-22_LP-Registration.html
2. info.seeq.com/hubfs/Content%20Pieces/Gated%20Content
3. CSDPWATERSUBSEA_Deepwater%20Subsea_CaseStudy_20200813.pdf
reaking industry conventions requires more than a good idea; value creation is fundamental to driving change. Opening eyes to the potential benefits of change is often where it falls down; however, if it ain’t broke, why fix it? What if you could reduce HSE exposure offshore by 100% and improve operational efficiencies all whilst building a digital representation of your entire network, reducing environmental impact, and enabling parts of the workforce currently inaccessible to the offshore industry? Now it sounds like something worth fixing. Transitioning to remote systems is simultaneously revolutionary, evolutionary, and an enabler for the industry.
Our working methods are entirely guided by the ‘now’. The population explosion, urbanisation, environmental effects of climate change, and technological advancements that have catapulted us into the connected digital age are all factors causing the world we live in to change and evolve more quickly than ever before. As some developing nations speed up the rate at which their economies expand and change, energy demand is anticipated to continue rising. The discussion overgrowth, higher output, and infrastructure replacement is driven by the fact that when global demand increases, the manufacturing infrastructure that supports it does too. This puts decision-makers in the problematic position of guaranteeing the least possible environmental impact whilst meeting economic constraints. So, begging the question, is the way we do things now equipped to handle this expansion?
Nowhere will the strain of this expansion be felt more than in the national and international pipeline networks. These networks are an essential component of the global energy ecosystem and play a vital role in its maintenance. One of the most crucial components of this system for the distribution of resources is
Businesses that embrace remote operations will change the quality of life for their employees, argues Ross Macfarlane, Remote Operations Programme Manager, Fugro, UAE.
the network of underwater pipelines. While the importance of the network cannot be understated, its weakness should also be considered due to its susceptibility to a wide range of damages and abnormalities. Pipes are vulnerable to a wide range of threats due to the often-inhospitable environments in which they are situated. These threats include environmental interaction, construction mistakes, damage from external pressures, etc. In addition to the energy industry’s interests, if the pipelines break down, the safety of the environment is at stake. This emphasises the importance of maintaining these pipelines’ integrity and the hazardous materials they transport. This vulnerability dictates a requirement for subsea inspection, monitoring, and maintenance in order to ensure the safe state of the pipelines. For now, this is a time-consuming and inefficient undertaking.
Luckily the ‘now’ has changed. Fugro has been bringing revolutionary new products and solutions onto the market as part of its ongoing efforts to innovate and improve its client offerings. The game-changing move toward remote operations and the suite of technologies that are now at one’s disposal will profoundly alter the way that asset networks are monitored and managed. Fugro’s fleet of uncrewed vessels, one class specifically developed for inspection operations, enables end users to participate in the inspection campaign in real-time, and receive higher-quality data. These vessels, along with the bespoke cloud-based software solutions provided by Sense Suite, make all of this possible. This paradigm shift in operational capabilities allows all of the experts to be in the same room simultaneously due to the remote capabilities, which combine the acquisition and analysis of realtime cloud data in an office environment. This both improves and accelerates the decision-making process.
Data is the catalyst that truly unlocks value. The ability to digitise assets opens the door to a world of new opportunities in asset management. Fugro takes this one step further by capturing data from iterative inspection campaigns in a single 4D digital representation of the asset network. This extra layer of comprehension allows the optimisation of inspection and maintenance cycles due to the detection of patterns, the identification of field-wide concerns, and an improved understanding of field-wide assets.
Alongside the enormous benefits introduced for the client through digitalising their assets. How the data is now collected also brings additional subsidiary benefits. By moving away from
conventional DP2 vessels for gathering the data and replacing them with an uncrewed vessel:
) Emissions can be reduced by 95%, with the additional 5% targeted in upcoming uncrewed vessel designs.
) HSE exposure is minimised.
) Reduced acoustic interference, causing less disturbance to marine life.
) Faster delivery: cloud-based asset information system delivers data quicker than traditional methods.
Along with the expanding technical capabilities and fast insights into geo-data and analysis, it is easy to overlook one thing from the business sense – ‘The People Factor.’ Remote operations enable advancements in how we deliver data to clients, but for businesses who embrace this new way of working, it changes the quality of life for their employees.
Take Wescley Souza, a qualified remotely operated vehicle (ROV) Superintendent who has worked for roughly 13 years in the offshore pipeline inspection domain. Before he started in our Remote Operation Centre (ROC), he would fly in and out to hazardous offshore environments to do shifts on vessels, barges, and platforms of various clients. He would have no control of his offshore life, being beholden to the constraints of wherever he was sent. Due to the nature of the offshore lifestyle, communication with home could be infrequent, and when he would return home could vary.
Since Wescley has started working in our ROC, he has known stability again in his private life and more structure in his professional life. Fixed rotations allow him to plan his time off in advance, and he can now work to live and not live to work. When Wescley comes on shift for his rotation, he is assured of a comfortable bed, has control of what he eats and, most importantly to Wescley, he can read his son a bedtime story every night via video call.
“Since working in the remote operations team at Fugro, I don’t think I could ever accept going back to an offshore way of working again. My quality of life has improved drastically, and I feel like I am getting to experience my son growing up rather than being a parttime father like before.”
The other significant change to Wes’s working life is his access to resources. Teams of experts who previously were an email or a phone call away, potentially in a different timezone, now sit 20 m from his workstation. This greatly enhances the quality of the deliverable for the client and fast tracks Wes’s learning and development, working with various skill sets and knowledge bases daily.
Having the roles of traditionally offshore jobs transition to a shore environment also expands the potential candidates for the job at hand. People with talent and the ability to perform the role, but would not be able to meet strict offshore requirements for whatever reasons, can now be considered for remote operations. Those potentially put off by the lifestyle that comes with offshore operations, or who could not continue being away from home for extended periods, now have an alternative option to do a job they love in an alternative environment.
When working with pipelayers, safety is often the first thing that comes to mind. And when you want to know what makes pipelayers safest, you go to the experts. That’s exactly what the Brandt Group of Companies’ Equipment Solutions Division did. They reached out to pipeline professionals for feedback on what their ideal pipelayer would be. Then Brandt built it.
Brandt engineers collaborated with the team at John Deere on a dedicated pipelayer with an innovative low-mount side boom, which delivers a wider stance for the lowest ground pressures and highest stability ratings. That was five years ago, and the Brandt pipelayer is still going strong, delivering the safety features professionals asked for.
One of the aspects that makes Brandt pipelayers unique is their exclusive, industry-leading SmartLift TM Dynamic Stability Monitoring system. This system delivers real-time dynamic stability feedback, ensuring the operator always knows the lifting ability at all boom angles over various slopes and pitches.
“This kind of real-time readout is unlike anything that is on the market right now. From moment to
Figure 1. Dynamic stability monitoring delivers safe load management on the spread.
moment, operators know exactly what’s going on, from the load, to the slung load, to how far it’s out, to the ground condition,” says Dan Bonnet, Engineering Manager – Electrical & Hydraulic at Brandt. “The system also warns operators if they are approaching a tipping scenario, so they can react quickly to prevent accidents.”
SmartLift features patented technologies that automatically account for the effect of side slope (roll) and front/back slope (pitch) on the carrying capacity of the tractor while moving, displaying the percentage of the max load in the current location.
Another major advantage of Brandt pipelayers is John Deere’s hydrostatic drive. Never before has a machine this large been so manoeuvrable. With unlimited speed variation and easy zero-radius turns, operators can focus on the job at hand rather than driving their machine.
“This is the toughest, safest, most stable pipelayer in the industry,” says Jason Klassen, Senior VP Sales – Manufactured Products at Brandt. “And it’s made specifically for the challenging terrains and seasons in North America. In this business, you leave nothing to chance. And this is the pipelayer you can count on to get the job done safely and efficiently.”
The Brandt pipelayer is coveted by customers because its design responds directly to their frustrations with competitors’ models. Customers shared their feedback, and Brandt listened. The company’s collaborative product design process delivers innovations that make customers’ working lives better, in uptime, efficiency, and comfort. Not only do customers enjoy participating in the process, but they are also excited about the outcome.
“Everybody talks about wanting to be customer focused, but customers will only share with you if they trust you. Because of the service we’ve provided over the years, our customers have come to trust us, and know that when we ask, we listen, and then we deliver,” says Chris Semple, President – Manufactured Products at Brandt.
With price increases in fuel, parts, and other business necessities, the need to lower operating costs was a common refrain from customers. Brandt engineers came up with an innovative solution: a unique low-mount boom-side winch placement that delivers increased cable life due to the industry’s lowest angle of reeving. They also designed the sideboom to work with John Deere’s proportional hydraulics and ECO Mode, providing full functionality and proportional control at engine idle. Plus, winches can still run at full speed, even with the tractor idled down, resulting in less wear and tear on the engine and lower fuel consumption.
“Safety comes first, last, and always, but you also need a machine that offers maximum uptime and a lower cost of operation, and we are able to deliver it all with Brandt pipelayers,” concludes Klassen.
