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03. Editor's comment
05. Pipeline news
With updates on Trans Mountain Expansion pipeline, Mountain Valley pipeline, and the Nord Stream sabotage.
KEYNOTE ARTICLE: SOUTH AMERICA REPORT
8. Viable investments in South America
Whilst opportunities abound in South America, Gordon Cope, Contributing Editor, advises potential investors to keep a keen eye focused on aboveground risks.
WELDING AND MATERIALS
34. Boosting operations
15. Compression options for carbon capture Klaus Brun, Brian Pettinato, Stephen Ross and Todd Omatick, Elliott Group, and Joseph Thorp, Aramco Ventures.
MAPPING AND SURVEILLANCE
20. Disrupting geohazard management
Mehdi Laichoubi, CTO, and Hamza Kella, R&D Simulation Engineer, Skipper NDT, France.
25. Gathering geo-data
Luke Brouwers, Engineering Geologist, and Ibtesam Hasan, Senior Corrosion Engineer, Fugro, UAE.
COVER STORY
29. The best of both worlds Brian Anderson, President Line Intervention, WeldFit Corporation, USA.
41. Efficient electro-resistive welding David Garrard, Director – APAC, Xiris Automation Inc., Thailand.
45. Featuring Stockton Drilling WorldPipelines asked Stockton Drilling some questions about horizontal directional drilling.
PIGGING FOCUS
49. Closures that comply Rolf Gunnar Lie and Neil McKnight, T.D. Williamson.
PIPELINE STEELS AND FABRICATION
53. Exploring CO2 transport Bente Helen Leinum, Senior Principal Engineer, DNV, Norway.
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Iwonder how many World Pipelines readers have visited the American Dream mall, in East Rutherford, a suburb of New Jersey? The story of the mall is fascinating: the 3 million ft2 shopping and entertainment complex was built at a cost of US$5 billion and has a long history of setbacks. It opened six months before the COVID-19 pandemic hit, and has struggled financially since it opened (losing US$60 million in 2021). A fantastic article by Jason Del Rey explains the development’s “complicated 17 year history, marked by ownership changes, false starts, and broken promises” and analyses why this megamall, and other malls, have been failing.1
One aspect of the story that interests me is the importance of marquee department stores in developing and sustaining malls. Historically, these “crown jewels of retail”, as Del Ray puts it, have acted as anchor tenants. Anchor tenants are established department stores or retail chains that commit to leasing some serious square footage (typically located at the end, or middle, of malls), drawing foot traffic through the complex. Malls have relied on the commitments of anchor tenants to legitimise their very existence.
But consumer behaviours have changed, and the middle-class shoppers who once visited department stores now see their money go further in standalone discount chains (TJ Maxx, Ross) and big-box stores (Walmart, Target). They can still get everything under one roof, but the roof no longer belongs to the likes of Macy’s or J.C. Penney. Three of the American Dream Mall anchors – Barneys New York, Lord & Taylor, and Century 21 – have gone bankrupt and closed, and this lack of underpinning threatens the survival of the mall.
If you’re waiting for the connection to pipelines, stay with me! On p.5 of this issue, we report on the news that Trans Mountain Corp. has applied to regulators for tolls on the much-delayed Trans Mountain Extension (TMX) pipeline project, which is about 85% complete. Costs have ballooned over the course of the last decade: a new report from ESAI Energy notes that “since the initial rate filing in 2013 for TMX […] the overall cost of constructing the pipeline has skyrocketed, increasing over four-fold from initial estimates of US$5.5 billion in 2013 when Kinder Morgan proposed the project to about US$23 billion, as of March 2023”.2 Trans Mountain Pipeline was bought by the Canadian government in 2018, after Kinder Morgan Inc. looked to halt the extension project in the face of environmental opposition.
Rising construction costs impact the variable component of the shipping toll: the proposed tariff includes a formula that adjusts the toll for changes in the cost of the project. In the original agreements, Trans Mountain Corp. capped the risk exposure of committed shippers at 25%, meaning that under 25% of the cost increases will be passed on through higher tolls to the companies that will be shipping oil on the line. But ESAI explains that “TMX risks losing its committed shippers if the cost-of-service based tariff rises too much”.
Is it a stretch to say that this is the anchor tenant conundrum of the pipeline shipping sector? The latest news is that committed oil shippers for TMX, including Cenovus Energy, Suncor Energy, and BP plc, have registered to intervene in the toll application. Reuters reports that a number of shippers are concerned that the uncapped cost component of the toll had increased from CAN$1.36/bbl in a 2017 cost estimate, to CAN$6.48/bbl.3 ESAI notes that about 80% of the capacity on TMX is contracted for between 15 - 20 years and the remaining 20% will be available as spot capacity. If the committed tariff ends up being higher than the market spot rate tariff, producers have the right to terminate their commitments on TMX.
A 2022 report from IEEFA says: “To make the project profitable, TMX would have to increase the currently projected tolling rate for using the pipeline’s transport services by 100%. A 100% increase in shipping costs, coupled with Canada’s already high production costs, would result in a price that would prevent Canadian oil from breaking into Asian markets”.4
The Canadian government is likely to sell TMX at a loss once it is complete.
1. https://www.vox.com/recode/21717536/department-store-middle-class-amazon-online-shopping-covid-19
2. North America Watch: Competition Heats Up for Oil Sands Takeaway in 2024’, ESAI Energy LLC, 22 June 2023.
3. https://www.reuters.com/business/energy/oil-shippers-canadas-trans-mountain-expansion-dispute-pipeline-tolls-2023-06-27/
4. https://ieefa.org/wp-content/uploads/2022/03/Trans-Mountain-Expansion-Could-Never-Return-the-Expected-26-Billion-Spent-byTaxpayers_March-2022.pdf
SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com
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Canadian energy company TC Energy Corp’s North Baja Pipeline LLC unit has received permission from US energy regulators to put the North Baja natural gas pipeline expansion in Arizona and California into service.
In a filing on Tuesday 30 May, the US Federal Energy Regulatory Commission (FERC) clarified that its 25 May order included approval for all remaining facilities of the North Baja expansion.
The 0.495 billion ft3/d North Baja expansion will supply more US natural gas to Mexico, including to US energy company Sempra Energy’s Costa Azul LNG export plant in Mexico, which is under construction.
The roughly US$2 billion Costa Azul project on Mexico’s Pacific Coast will be able to turn about 0.43 billion ft3/d of gas into LNG once it enters service around mid 2025. 1 billion ft3 of gas can supply about 5 million US homes for a day.
The North Baja expansion cost an estimated US$127 million, according to US energy data. FERC approved construction of the North Baja expansion in April 2022. North Baja said it completed work on some facilities earlier this year.
North Baja is a bidirectional pipeline that entered service in 2002. It can move gas from Arizona to California and Mexico, and from Mexico to California and Arizona.
Before the 2023 upgrade, North Baja could move about 0.5 billion ft3/d of gas south from Arizona to California and Mexico, and about 0.614 billion ft3/d north from Mexico to California and up to 0.695 billion ft3/d north from California to Arizona, according to federal energy data.
Pakistan and Turkmenistan have signed a joint implementation plan to accelerate the long-delayed Turkmenistan-AfghanistanPakistan-India (TAPI) gas pipeline project.
The signing ceremony took place in Islamabad on Thursday 8 June and was attended by Pakistani Prime Minister, Shehbaz Sharif and a delegation from Turkmenistan led by Maksat Babayev, Turkmenistan State Minister and Chairman of stateowned gas producer Turkmengas.
Prime Minister, Shehbaz Sharif said that the completion of the TAPI project “will be a game-changer for the region in terms of enhanced economic cooperation.”
The accord, signed by Pakistan’s Minister of State for Petroleum, Dr. Musadik Malik and Turkmenistan’s State Minister, Maksat Babayev, aims to expedite the work on the four-nation TAPI gas project.
The TAPI gas pipeline project aims to transport gas from Turkmenistan’s Galkynysh field, the world’s second-largest gas field, to Pakistan and onwards. The pipeline will span approximately 1800 km and pass through Afghanistan. The TAPI inter-governmental agreement was signed in December 2010, however, the project remained stalled because of technical and financial issues and instability in Afghanistan.
The pipeline is expected to carry 33 billion m3/yr of natural gas, from which Pakistan and India would purchase 42% each of the TAPI gas flows. The pipeline will originate in southeast Turkmenistan and traverse Afghanistan, before entering Pakistan through Chaman, Zhob and Multan. It will finally reach Fazilka in India’s Punjab region near the Pakistan border.
The US learned of a Ukrainian plan to attack the Nord Stream natural gas pipelines three months before they were damaged last September by underwater explosions, The Washington Post reported on 6 June, citing leaked information posted online.
The CIA learned last June, through a European spy agency, that a six person team of Ukrainian special operations forces intended to blow up the Russia-to-Germany project, the newspaper reported. The intelligence reporting was shared online on Discord, purportedly by Air National Guard member
Canadian government-owned Trans Mountain Corp (TMC) has applied to regulators for tolls on its long-delayed 590 000 bpd pipeline expansion to Canada’s west coast, noting shipping fees would increase if project costs mount.
The Trans Mountain Expansion (TMX) will nearly treble the flow of crude from Alberta’s oilsands to Burnaby, British Columbia to 890 000 bpd, but the project has struggled with regulatory hurdles, environmental opposition and surging costs.
In March, TMC said the expansion would cost CAN$30.9 billion (US$23 billion), more than four times the original estimate, and that the final bill could rise further. The
Jack Teixeira, who was arrested in April and charged in relation to the leak of sensitive US documents. The Washington Post said it obtained a copy from one of Teixeira’s online friends.
The intelligence report was based on information provided by a person in Ukraine, The Washington Post said, adding the CIA shared it with Germany and other European countries in June 2022.
White House spokesperson, John Kirby, said on 5 June that investigations into the Nord Stream attack were active.
tolling application is a sign TMX, due to start shipping in the 1Q24, is nearing the finish line more than a decade after it was first proposed. The pipeline will struggle to recoup the billions spent during construction, analysts said, adding that the Canadian government, which bought it in 2018 to ensure it got built and plans to sell it once complete, faces a substantial loss.
“TMX is really trapped between a rock and a hard place. It is unlikely to be able to charge a rate compatible with earning viable returns on a CAN$31 billion investment,” said Morningstar Analyst, Stephen Ellis, who estimates the pipeline will be worth around CAN$15 billion once complete.
8 - 10 August 2023
Rio Pipeline 2023
Rio de Janeiro, Brazil www.riopipeline.com.br
5 - 8 September 2023
Gastech 2023 Singapore www.gastechevent.com
5 - 8 September 2023
SPE Offshore Europe 2023 Aberdeen, Scotland www.offshore-europe.co.uk
11 - 15 September 2023
IPLOCA 2023 convention Vancouver, Canada www.iploca.com/events/annualconvention/2023-convention
17 - 21 September 2023
World Petroleum Congress 2023 Calgary, Canada www.24wpc.com
21 - 22 September 2023
Subsea Pipeline Technology Congress (SPT 2023) London, UK www.sptcongress.com
2 - 5 October 2023
ADIPEC 2023
Abu Dhabi, UAE www.adipec.com
24 - 26 October 2023
OMC 2023
Ravenna, Italy www.omc.it/en
Vallourec has signed a Memorandum of Understanding (MoU) with the Ministry of Investment of Saudi Arabia (MISA). The signing took place on 19 June 2023, as part of the French-Saudi investment forum held in Paris.
Following the group’s recent successes in Saudi Arabia, in particular the ten year contract won from oil company Saudi Aramco for the supply of premium casing tubes and services, this agreement testifies to Vallourec’s close ties with the Kingdom, where the group has been present through its Vallourec Saudi Arabia (VSA) plant located in Dammam since 2011.
The MoU provides for close support from MISA in the expansion of Vallourec’s activities in Saudi Arabia, which includes increasing its local presence and deploying its latest innovations, in the fields of energy transition (CO2 capture, utilisation and storage, hydrogen storage and transport), additive manufacturing and the circular economy.
Newly formed specialist manned submersible services provider, AquaTitans, has chosen underwater tracking systems from marine technology company Sonardyne to support underwater vehicles.
The Glasgow-based company, formed by submersibles specialists Alan Green and William Arthur in 2022, will use Sonardyne’s Mini-Ranger 2 Ultra-Short BaseLine (USBL) positioning system as part of its new containerised submersible support system.
For use from small expedition vessels to large, open-decked offshore support ships, vessels of opportunity or even quaysides, the AquaTitans container concept comes with everything needed to operate submersibles. The package includes dedicated support equipment for underwater communications, re-charging batteries, oxygen and air re-supply, together with accurate and reliable underwater tracking.
The company’s first two 20 ft containerised systems will be used with Triton 3300/3 submersibles; three-man vehicles built by Triton Submarines that are able to carry science and research specialists to depths of 1000 m. The first delivery was made in 1Q23.
Strohm, producer of thermoplastic composite pipe (TCP), has been awarded a €3 million contract to supply carbon fibre/ PA12 composite jumpers to Aker Solutions to support work being carried out at TotalEnergies’ Moho Infill project in the Republic of the Congo.
The TCP will be provided in six lengths of 90 m each, with the TCP fittings being directly welded onto the diver-less connectors, providing a seamless connection from end to end. The jumpers, which will be delivered by the end of this year, will be produced at Strohm’s manufacturing facility at its headquarters in the Netherlands, and will be used to provide gas lift service and enhance production.
• Mountain Valley pipeline closer to construction
• Fluxys builds new natural gas and hydrogen pipeline
• ADNOC, Heerema, and MMA Offshore win IMCA Awards showcasing best in safety and sustainability
• DNV: energy industry boosts cybersecurity spending
• AGA applauds NEPA reform in Fiscal Responsibility Act
• Williams to complete two pipe projects in USA
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Latin America is home to over 660 million people, and growing rapidly. It also possesses huge reserves of oil and gas that are needed to support industry, transportation and utilities. Many jurisdictions in this vast area are responding to the needs of their citizens, while others pursue political agendas (and larceny). Here, a brief roundup of its impact on the midstream sector.
Over the last decade, Mexico built up several thousand kilometres of gas mainlines, primarily to deliver abundant Texas supplies to state-owned utility CFE as it gradually replaced oil-fired electricity generators with gas-fired equipment. Major lines now serve the populated central corridor, as well as the Pacific and Gulf of Mexico coasts. Current import capacity exceeds 13 billion ft3/d. US imports are only around 7 billion ft3/d, however, and the new midstream assets (such as the 2.6 billion ft3/d Sur de Texas line which runs offshore from Texas to Veracruz), have ample spare capacity. While CFE has plans to convert another half dozen generating plants in central Mexico, new consumption opportunities are under development. ) Two new LNG plants are being built along the Pacific coast. Sempra Energy’s Energía Costa Azul (ECA) LNG, located in Baja California, is a former LNG import site. The 3 million tpy train is expected to be commissioned by 2025, and could ultimately be expanded to 12 million tpy. The Mexico Pacific Limited (MPL) LNG project is located on the Sea of Cortez. The latest plan is to build three trains totalling 14.1 million tpy capacity in Phase 1, and a further three trains in Phase 2, doubling capacity to 28.2 million tpy. Both ECA and MPL are already served by major pipelines, including the 670 million ft3/d Topolobampo line. In addition, NFE is fasttracking two floating LNG rigs to be stationed
Whilst opportunities abound in South America, Gordon Cope, Contributing Editor, advises potential investors to keep a keen eye focused on aboveground risks.
at Altamira on the Gulf of Mexico, tapping into the Sur de Texas line. Analysts foresee as much as 7 billion ft3/d from Mexico within the decade.
) Mexico currently imports significant amounts of nitrogen fertilizer to meet its agricultural needs. In February 2023, Dutch-based Tarafert announced that it would be spending US$1.5 billion to build an ammonia and urea plant in the state of Durango. The 1 million tpy facility will be built adjacent to the 1.5 billion ft3/d El Encino-La Laguna gas pipeline. In January 2023, PEMEX announced that it would spend US$750 million to upgrade its two urea and four ammonia plants.
) The 340 000 dos Bocas project in the state of Tabasco is the first greenfield refinery to be built in Mexico in several decades. In order to service the US$18 billion refinery and utilities in southern Mexico, TC Energy and CFE announced in 2022 that they would build the 1.3 billion ft3/d Southeast Gateway Pipeline. The US$4.5 billion line will connect to the Sur de Texas pipeline in Veracruz and run 770 km offshore to Tabasco. The line is expected to be in service by 2025.
TC Energy estimates that new-build LNG, fertilizer and refineries, as well as growth in existing markets, will increase Mexico’s demand to 12 billion ft3/d by 2030, soaking up significant pipeline capacity.
Guyana has been the focus of an intense exploration and development project in the offshore Stabroek Block by ExxonMobil and partners, catapulting it from an impoverished nation to one of the largest exporters of crude on the continent. Over 30 deepwater offshore discoveries have resulted in an estimated 11 billion bbls of recoverable oil resources, with the potential for far more discoveries. Several FPSO facilities are already in place; by early 2023, production had reached almost 400 000 bpd. In addition, the FPSOs produce significant associated gas. In 2022, Exxon and partners agreed to develop a gas to energy project that would entail a 200 km pipeline from offshore fields to an industrial zone near the capital of Georgetown. The line would deliver up to 50 million ft3/d to generate 200 MW of electricity.
But the majority of gas is largely reinjected into the fields in order to maintain pressure of producing wells, which the government of Guyana views as a missed opportunity. “We believe gas must be monetised,” said Vice President, Bharrat Jagdeo.1 In addition, Exxon, which made the discovery of the offshore Pluma gas field in 2018, has yet to announce plans to develop the gas. Guyanese officials are discussing a national strategy for using the gas to develop domestic industries, ranging from LNG to petrochemicals, which would eventually require a much more comprehensive gas pipeline network.
The outlook for Colombia’s oil and gas sector is cloudy. South America’s third largest oil producer, with an output of approximately 750 000 bpd, has only eight years of crude and
gas reserves left before it runs out. While the country has an abundance of unconventional reserves, fracking is widely unpopular in the country, and is not seen as a viable alternative to dwindling conventional reserves.
In September 2022, the country elected Gustavo Petro as its new President. The left-wing candidate had run on a platform of eliminating contracts for oil and gas exploration and a ban on fracking. Upon inauguration, he wasted little time replacing the board of directors of state-owned Ecopetrol with his own slate of candidates, cementing control over the largest producer and refiner in the country.
In addition to focusing on a transition to renewables such as wind and solar, Ecopetrol will be paying significantly higher revenues to the government. Tax reforms initiated under the Petro administration removed royalty payments as a tax deduction, and a scalable surcharge that increases in line with the Brent benchmark price is designed to generously increase government revenues. While the changes will benefit the country’s ballooning deficit, it hinders both domestic and international investors from conducting critical exploration and development plans.
In addition, unresolved issues from the long-standing civil war and the proliferation of drug cartels continue to plague the country. In March 2023, Ecopetrol once again temporarily suspended operations on the Cano Limon-Covenas pipeline due to bombing attacks. The 210 000 bpd line runs adjacent to the Venezuelan border, in a region in which the guerrillas of the National Liberation Army operate. The attacks, which have been occurring roughly twice a month in 2023, cause environmental damage due to spillage. Narco groups also frequently cause spills when they drill into the pipeline to steal crude; makeshift refineries then distil a primitive form of gasoline for use in cocaine cultivation.
Argentina’s unconventional shale production is driving massive growth in the country’s oil and gas sector. The Vaca Muerta formation contains an estimated 16 billion bbls of oil and over 300 trillion ft3 of gas. Production has risen from 222 000 bpd and 1.6 billion ft3/d at the beginning of 2022 to 290 000 bpd and almost 2 billion ft3/d by early 2023. In total, the country’s gas production grew to 3.4 billion ft3/d in 2022, approximately balancing annual domestic demand.
But the Vaca Muerta has the potential to surge to 5 billion ft3/d by 2030, creating a huge surplus. Work is underway to expand domestic and export capacity. The first stage of the 1000 km greenfield Nestor Kirchner gas pipeline, expected to enter service in mid-2023, will add approximately 800 million ft3/d, with a second phase of approximately 500 million ft3/d. Total costs are estimated at US$3.4 billion.
Currently, Argentina has about 750 million ft3/d of gas pipeline capacity running to Brazil, Chile and Uruguay, and has already seen exports increase from 30 million ft3/d in 2021 to 151 million ft3/d in 2022. The Nestor Kirchner line will add the potential for exports to Bolivia, but new projects will be needed by the end of the decade to meet the growth in production.
In March 2023, Argentina’s YPF and Malaysia’s Petronas announced an ambitious, US$60 billion plan to deliver gas to
domestic and international consumers. The first phase of the plan would see the building of a pipeline to the Atlantic port of Bahia Blanca and the construction of a 5 million tpy LNG plant. While details of the pipeline have not been released, production lies 300 km to the west of the port, and a 5 million tpy LNG plant would need approximately 650 million ft3/d feed.
Venezuela is the undisputed knave of South America’s oil and gas sector. The country, with an estimated 304 billion bbls of reserves, has seen its output plummet from over 3 million bpd to under 600 000 bpd in late 2022 due to rampant corruption and mismanagement of state-owned PDVSA. In March 2023, the country’s longstanding Oil Minister resigned amidst one of the world’s largest financial scandals. Since 2020, a division of PDVSA has been selling oil cargoes to little-known third parties without repayment. Investigating authorities say PDVSA now has over US$21 billion in commercial accounts receivable. Over 20 people have been arrested on charges ranging from appropriation of public assets to money laundering.
Such stolen funds result in a lack of investment in maintenance, which has had a profoundly negative impact on the midstream sector. Independent observers noted that there were 86 oil spills and gas leaks in Venezuela in 2022, up from 77 in 2021. Most were in the region surrounding Lake Maracaibo, the centre of Venezuelan oil production for most of the last century. The spills are primarily due to lack of maintenance and inspection of tanks and pipelines by cash-strapped PDVSA.
Thanks to the disruptions and sanctions arising from the Ukraine war, the Biden administration has recently made overtures to Venezuela in regards to lifting sanctions; in November 2022, it granted US-based Chevron permission to resume operations at its oilfields for six months. The midstream and downstream sectors, however, need an estimated US$200 billion in investments to restore viability. Considering that most major oil companies have abandoned their assets in Venezuela, any comprehensive revitalisation is highly unlikely.
For the last several years, Brazil has been privatising many different parts of its economy, including the energy sector. State-controlled Petrobras has been divesting itself of major assets, including petrochemical plants, pipelines and refineries. The move was in response to, among other events, the Operation Carwash scandal, which exposed the corruption and mismanagement that had arisen in the state-controlled Petrobras during the administration of President Lula de Silva (Lula). In January 2023, Lula was re-inaugurated as Brazil’s President. In his campaign, he had vowed to redirect profits from the company toward the social wellbeing of the nation.
This turn of events has investors in the oil and gas sector worried. Over the last several years, Petrobras has rallied back from the brink of bankruptcy, posting record profits in 2022 of US$36 billion. The funds are necessary for the continued development of the sub-salt play that has propelled Brazil to the forefront of production in South America; it reached 3.4 million bpd in January 2023, and 8% increase y/y. Prior to the return of Lula, the company had announced a five year plan from
2023 - 2027 in which it would spend approximately US$43 billion developing the play. Under a joint venture (JV), for instance, Petrobras, Equinor and Respsol Sinopec are co-developing the BM-C-33 pre-salt field located 200 km offshore of Rio de Janeiro state. The multi-billion-dollar plan calls for an FPSO with a capacity of 125 000 bpd and 500 million ft3/d; the gas would be shipped back by seabed pipeline to Petrobras’s TECAB site at Cabiúnas. If the administration redirects funds toward social goals, Petrobras will find it increasingly difficult to pay for developments.
In addition, Lula had promised to re-examine the privatisation of Petrobras assets. Recently, Petrobras sold gas pipelines Nova Transportadora do Sudeste (NTS) and Transportadora Associada de Gás (TAG) for approximately US$7 billion each. While there is little probability that the finalised sales will be retroactively cancelled, some pending sales could be scratched, including the Transportadora Brasileira Gasoduto Bolívia-Brasil (TBG), which operates the Bolivia-Brazil (Gasbol) pipeline.
Exports in March 2023 exceeded 2.8 million bpd. In a surprise move, the Brazilian government announced on 1 March 2023 to levy a 9.2% tariff on crude oil exports to compensate for the loss of revenue due to the gradual lift of tax exemptions on fuel. The temporary tariff is designed to run April - July 2023, collecting an estimated US$1.2 billion in revenues. Shell and other companies have protested the unilateral move and have filed an injunction.
Like many other jurisdictions, South American countries are looking to develop a hydrogen economy. Latin America produces approximately 4 million tpy of hydrogen, primarily for crude upgrading in refineries. In 2021, Australian firm Enegix announced plans to take advantage of northeast Brazil’s abundant wind and sunshine in Ceará state to construct a 600 000 tpy green hydrogen plant. The US$5.4 billion project is expected to take up to four years to build after all construction permits are issued; most of the output is destined for the export market. During 2022, Ceará state also signed two MOUs, one with Japan-based Mitsui for the production of green hydrogen and ammonia at the port of Pecém, and the other with ABB Automation, a Swedish-Swiss company that specialises in the hydrogen value chain, from production and transport to consumption. Most of the announced production will likely be transported via ship; unlike other regions (like the EU), there is currently no significant talk of dedicated pipeline networks.
Latin America is a conglomeration of jurisdictions with highly divergent social, political and economic agendas. Newly elected populist administrations in Colombia and Brazil threaten to compromise the tremendous opportunities that healthy oil and gas sectors present to their countries. While Mexico is intent on reversing international participation in upstream assets, midstream gas pipeline networks remain a viable investment as the country actively expands existing and new uses.
In conclusion, while opportunities abound in the vast region, those looking for potential investments are well-advised to prioritise political risk assessments.
References
1. financialpost.com/pmn/business-pmn/guyana-sees-natural-gas-as-the-nextfrontier-after-oil
he promise and potential of hydrogen as key to a carbon free energy economy has generated significant development of technologies to efficiently produce, transport, store, and utilise hydrogen. Because of cost and logistical advantages, most hydrogen entering the market over the next 15 - 20 years will be blue hydrogen derived from fossil fuels such as natural gas, as opposed to green hydrogen derived from alternative energy sources.
For every kilogram of blue hydrogen produced through steam reforming or partial oxidation gasification, or derived from power plant post-combustion flue gas separation or other industrial processes, about 10 kg of CO2 is also produced. This CO2 needs to be compressed from near atmospheric conditions to pipeline operating transport pressure, and then to geological formation storage pressure for long-term sequestration. Consequently, the race toward a low-carbon economy
has fuelled the need for added new CO2 compression capacity for separation, pipeline transport, and storage injection.
Although CO2 compression has been successfully performed for many years in the oil and gas industry’s enhanced oil recovery projects and acid/sour gas injection, the quantity scale of compression required for carbon separation, transport, and sequestration challenges the current state-of-the art.
One promising technology for these applications is a hybrid combination of a centrifugal compressor to compress the gas slightly above its critical point, in series with a dense-phase pump to reach the desired process discharge pressure. Both lowpressure CO2 compressors and dense-phase pumps are proven technologies, but their hybrid combination has not yet seen significant service in the industry.
CO2 is generated by the combustion or burning of fossil fuels including coal, oil, and natural gas in order to produce electricity. Power generation is responsible for over 40% of all energy-related emissions. Worldwide emissions of carbon dioxide from burning fossil fuels total about 33 billion tpy. About 44% of this is from coal, about 34% from oil and about 21% from natural gas.
Natural gas power plants produce about 1 lb of CO2/kWhr of electricity, while coal plants produce about 2.5 lbs of
CO2/kWhr (EPA, 2019). These numbers can vary significantly based on an individual plant’s efficiency. Thus, a typical 500 MW natural gas combined cycle power plant will usually produce 1 - 2 million tpy of CO2, depending on its duty cycle (equivalent full load running hours per year) and efficiency.
Technologies and processes exist to capture the CO2 from the power generation flue gas, which is currently separated and released as a pure stream into the atmosphere (Figure 1).
The majority of hydrogen (95%) is produced from fossil fuels by steam reforming of natural gas, other light hydrocarbons, and coal gasification. In the steam reforming process, natural gas is reacted with steam at an elevated temperature to produce carbon monoxide and hydrogen. A subsequent reaction – the water gas shift reaction – then reacts additional steam with the carbon monoxide to produce additional hydrogen and carbon dioxide.
) CH4 + H2O CO + 3 H2
) CO + H2O CO2 + H2
The CO2 that results from the steam reforming process is currently vented to the atmosphere.
CO2 is an inert gas and is generally considered non-toxic. However, CO2 is heavier than air and poses an asphyxiation risk. Figure 2 shows human exposure limits for CO2. Oxygen detectors are required when working with CO2 compression systems. Although CO2 is non-toxic, its safe exposure limits may be governed by other impurities in the process mixture. In acid and sour gas applications, H2S and SO2 limits are regulated at ppm limits, and exposure limits may be in the order of seconds. For these cases, a special flaring capability may also be required.
Beyond health and safety standards, there are several relevant codes and standards to consider when transporting carbon dioxide in a pipeline:
) Title 49 of the US Code of Federal Regulations Part 195 for pipelines transporting hazardous liquids.
) DNV-RP-J202, Recommended Practice on Design and Operation of CO2 Pipelines.
) ISO 13623:2009, Petroleum and Natural Gas Industries – Pipeline Transportation Systems.
) DNV-OS-F101, Offshore Standard on Submarine Pipeline Systems.
) ASME B31.4, Code for Pressure Piping – Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids.
Figure 1. Flue gas separation.Speed of acquisition
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Access to entire network regardless of ground conditions
) ANSI B31.8 for gas transmission lines.
) API and ISO codes for machinery such as API 617, 618, etc.
This is not a complete list, but these items are a good starting point for relevant standards for CO2 transport and compression.
To reduce carbon emissions, the CO2 generated from power plant applications and industrial processes such as acid gas reinjection, enhanced oil recovery and the production of natural gas, cement and fertilizer must be separated and captured either pre-combustion, or from the exhaust flue gas via a post-combustion process, and then transported and sequestered, or repurposed.
CO2 is a heavy gas that is relatively easy to compress from a thermodynamic perspective. Power plant applications and industrial processes that generate CO2 utilise some of the following compression duties:
) Pipeline header injection and re-compression transport.
) Injection into geological storage reservoirs for sequestration.
) Separation processes (membrane, thermal or chemical).
) Compression from the separation processes to pipeline pressure.
) Power plant cycle compression (Oxy and sCO2 cycles).
) Pipeline boost compression.
These technologies provide important practical experience that can be extended to capture, transport, and store a significant fraction of the CO2 generated from the combustion of fossil fuels. It is also important to recognise that CO2 compression comes with technical challenges that must be
individually addressed in the design process for large-scale industrial carbon capture and sequestration technologies.
For long distances, it is generally accepted that CO2 should be transported as a supercritical fluid above 2100 psi in pipelines. At 2100 psi, CO2 is well above its critical point in a supercritical (dense phase) state for almost all ambient temperatures. Fluids in a dense phase share some physical properties of liquids, such that they have a very low compressibility, and also some of gases, in that they will expand in space to fill voids. The advantage of transporting CO2 at supercritical pressures is that its density does not change much with pressure, and from a thermodynamic perspective, it is basically pumped rather than compressed. The disadvantages of operating at these high pressures are the added injection compression ratio required at the pipeline header station and the significantly higher costs for materials to build a pipeline designed for maximum allowable operating pressures well above 2100 psi.
However, transport at 2100 psi is not required for all applications, and the actual transport pressure very much depends on the starting pressure at the separation process outlet, the distance the CO2 must be transported, and the geologic sequestration injection pressure, which is often well below 2100 psi. Since the CO2 available from separation is usually at low, near atmospheric pressures (<100 psia), the pipeline header station must always use a compressor.
A 2100 psi CO2 pipeline requires a high-pressure ratio header compressor with many intercooled states that can handle the significant volume reduction. The gas is transported in dense phase, either by pump or by compressor in the pipeline beyond the header station. Conversely, if a lower-pressure CO2 pipeline is used, conventional compressors are preferred for the header station, with recompression stations along the line. Clearly, selection of transport pressure depends on the carbon sequestration application, but it is not always advantageous to go to the pressure needed for a supercritical CO2 pipeline.
The pressure of the CO2 gas from the separation process is strongly dependent on the type of separation process utilised, and can vary from slightly above atmospheric to several hundred psi. For example, CO2 from a methane steam reforming process is produced near 30 psia, whereas from a gasification process, it is likely to be at pressures well above 150 psia. Flue gas separation is usually near atmospheric but can be as high as 20 psia. While there is a wide range of possible compressor suction pressures for a CO2 compressor, most of the commercially viable industrial applications produce CO2 somewhere between atmospheric and 50 psia.
There is also significant uncertainty about the compressor discharge pressure since it depends on whether the CO2 will be transported as a gas or dense phase, or will be directly injected into a geological formation. Furthermore, the geological formation injection pressure strongly depends on the type of formation and its drilled depth of injection. For every mile of depth of injection, it is generally accepted that about
1800 psi of gas pressure is required. Since many of the geological formations being considered are relatively shallow, injection pressures well below 2000 psi are often the case. Nonetheless, a typical carbon separation and storage pressure application usually requires CO2 to be compressed from below 50 psia to above 2100 psia. This assumes that most separation processes will produce CO2 somewhere near or slightly above atmospheric pressure. For purposes of simplicity, a 30 - 2100 psia assumption will be used as a basis for a CO2 transport compressor. This assumption may not be valid for all cases and is application specific.
Many viable thermodynamic path options exist to get from the start to the end point in this compression process, including nearisothermal, refrigeration and liquid pumping, and high-pressure ratio compression. Basically, one can compress the CO2 and stay in the gas state on the right side of the vapour dome, refrigerate the CO2, and pump it in the liquid state on the left side of the dome, or one can utilise a hybrid combination of the above two options. Figure 3 shows this from an energy perspective. The total energy required for the compression process is simply the enthalpy difference (compressor head) multiplied by the mass flow. Clearly, an isothermal process (i.e. a process at constant temperature) will require significantly less power than an isentropic process (i.e. a process at constant entropy) since the enthalpy difference is drastically lower.
Turbomachinery design for carbon capture Turbomachinery for carbon capture applications must satisfy many operational and performance requirements. These are primarily driven by the type of application, the service duty, and the plant’s commercial and operational design requirements. Fundamentally, most carbon capture applications aim for low capital cost, wide operating range, frequent starts and stops, and a very high availability. Some of these requirements are inherently contradictory and require compromise design decisions.
A variety of compression paths and technologies for largescale carbon storage applications exist. Some are commercially available, while others are still in development. One promising technology is a hybrid combination of a centrifugal compressor to compress the gas to slightly above its critical point, in series with a dense-phase pump to reach the desired process discharge pressure.
Conclusion
Part I of this article has addressed some of the challenges of CO2 compression. Part II will present the use of a hybrid compressor and pump system for carbon sequestration and transport applications. This solution provides for significantly reduced power consumptions while maintaining the reliability and flexibility of barrel type machinery. Part II will be published in an upcoming issue of WorldPipelines
Mehdi Laichoubi, CTO, and Hamza Kella, R&D Simulation Engineer, Skipper NDT, France, explore the use of technology to evaluate pipeline displacement by geohazards.
atural disasters such as earthquakes, flooding, and hurricanes have a devasting impact on communities. They destroy not only aboveground infrastructure, but also buried infrastructure such as pipelines. After hurricane Ida struck the coastline of Louisiana in 2021, oil spills of several miles long were seen in the Gulf of Mexico. Extreme climatic events are forecast to intensify in frequency and intensity due to the effect of global warming. This threat is taken seriously by governing authorities and specific legislation was promulgated to ensure swift action is taken to protect local communities. The new PHMSA Mega rule Part 2, which went into effect in
2020, requires operators to inspect pipelines within 72 hours of an extreme weather event.
Although pipeline operators cannot control the weather, they can assess the mechanical integrity of their buried pipeline networks. Current methods are either indirect, correlating surface measurements and potential pipeline mechanical strain, or direct, with actual pipeline measurement through the launch of an inline inspection (ILI) tool fitted with an inertial measurement unit (IMU). One indirect method is rapid to deploy, but relies on secondary data and statistical models to obtain information about the pipeline. Another method, based on ILI, is direct but entails significant logistical
constraints making it difficult to be deployed within a short time frame.
The Skipper NDT technology could help bridge this gap by providing an assessment of the pipeline mechanical strain
based on direct data acquired from the ground surface. By leveraging the latest developments in the field of hardware and software, Skipper NDT is able to rapidly and remotely deploy its technology based on the physical principles of magnetism. The objective is to create a high-precision digital twin of the buried structure from which bending strain calculations are performed. The geospatial accuracy of the technology was confirmed in PRCI project PL-1-05, where data provided by Skipper NDT were compared to open ditch measurements on a 24 in. dia. pipeline. The result showed a 5 in. average accuracy with a high degree of reproducibility. This dataset is then used to deploy proprietary data computation to assess the bending strain of the pipeline.
Reliable and repeatable data acquisition is the building block upon which the Skipper NDT technology relies. The main objective is to provide the highest data quality while ensuring the field operator’s safety at all times. By leveraging the latest developments in the field of hardware and software, Skipper NDT uses an unmanned aerial system (UAS) vector to carry the equipment required for capturing the necessary geospatial and magnetic metadata. The system was made as compact as possible to be compatible with a large array of drone vectors. The payload weighs a total of 1.6 kg (3.5 lb) with a span of 160 cm (62 in.), and includes the following elements (Figure 1):
) Four three-component fluxgate magnetometers.
) Real-time global navigation satellite system (GNSS) receiver with centimetric-level precision.
) Tactical-grade IMU.
) Telemetric sensors that measure the distance between the magnetometers and the ground (or canopy).
) Proprietary electronic card responsible for data acquisition, digitalisation, and synchronisation are the system’s core components.
Using this system, large areas can be rapidly scanned regardless of the complexity of access to the site or the soil type/condition.
To ensure data reliability and repeatability, Skipper NDT has created an automated multi-step procedure for deriving the buried pipeline position (horizontal, vertical, and depth of cover). From this metadata, out-of-straightness (OOS) is quantified. The first step is to perform the actual field data acquisition. Simple and fully automated, this requires the drone pilot to
Figure 1. The Skipper NDT Embedded System mounted on an off-the-shelf UAS (DJI M300). Figure 2. Inspected area (red outline) and the trajectory of the drone (green).create, using the dedicated software, a flight plan over the area of interest (Figure 2). The drone will then autonomously scan the area and acquire the data without any manual intervention. Data quality does not depend on the drone pilot’s skills, and difficult-to-access areas can be efficiently surveyed while ensuring the field operator’s safety.
The second step entails data post-processing. Here again, the process is automated and relies on patented algorithms to perform a number of operations, including magnetic data calibration to erase any potential interference and the production of magnetic maps, which will be the basis for determining the pipeline location.
The third step will see Skipper NDT deploy its proprietary magnetic inversion algorithms to pinpoint the exact lateral, horizontal, and depth of cover position of the buried pipeline. Using this data, Skipper NDT has a specific set of algorithms to determine the vertical and horizontal bending strain of the structure to highlight potential zones of abnormal strain which could threaten the safety of the buried pipeline.
Finally, the operator will receive both an inspection report with a data file adapted to the format of its geographic information system (GIS) for ease of integration into the integrity management programme for the pipeline.
A major energy gas distribution operator mandated the services of Skipper NDT to inspect a 450 mm (18 in.) dia. buried pipeline in an area that exhibited signs of ground displacement. The drone was deployed to collect the magnetic data. The average magnetic map dimension was approximately 450 m (1476 ft) by six profiles. The drone flew at an average height of 2 m (6.5 ft) AGL, with an average flying speed of 6.5 km/hr (4 mph). The acquisition time for the inspection was 30 minutes in total. In Figures 3 - 5, the pipeline geometry profiles are presented over a length of about 450 m (1476 ft).
OOS profiles are used to visually capture subtle alterations in the pipeline centreline. These profiles measure the horizontal and vertical deviations from various possible sources which could be the as-built plans provided by the operator, a
previous Skipper NDT survey, or a straight-line assumption. OOS profiles are especially valuable for detecting pipeline direction change due to ground movements.
As shown in the vertical OOS profile in Figure 3, the landslide-induced pipeline displacement has generated a vertical OOS of about 1 m (3 ft) over 80 m (262 ft) with a peak vertical OOS at a relative distance of about 300 m (984 ft). In addition, the horizontal OOS data (Figure 3) clearly indicates the presence of two horizontal bends (32˚ and 5˚) at 200 m (656 ft) and 400 m (1312 ft), which are well-illustrated by the stair-stepped pattern in the azimuth profile in Figure 4 and are known to the operator. The vertical geometry is
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characterised by a clear, two-lobe sinusoidal undulation in the pitch profile in Figure 4 extending over the distance range from about 260 - 380 m (787 - 1246 ft), with a total pitch swing of 2˚.
The vertical bending strain profile, shown in Figure 5 exhibits a distinct and characteristic W-shape with a negative peak value of -0.017% and -0.014% at a relative distance of
about 255 m and 390 m (836 ft and 1279 ft), respectively, and a positive peak value of 0.024% at a relative distance of about 285 m (935 ft) near the middle of the landslide. Moreover, Figure 5 shows a reduction of the magnetic field along the anomaly and helps us to better interpret the results. This indication, obtained without any interference with the normal operating conditions of the pipeline, made it possible for the operator to take the required corrective actions at the precise location affected by the ground movement.
Summary
In summary, the advantages of the Skipper NDT technology for bending strain assessment in case of a geohazard event can be summarised as follows.
Bending strain analysis derived from reliable primary data
• The magnetic data acquired using the Skipper NDT technology is based on the pipeline itself. No models are used to derive this primary information, just as in ILI.
• Primary data input was proven to be reliable and repeatable as shown by the PRCI audit (PL-1-05), showing an average positioning accuracy of 5 in. and a precision of 3 in. Bending strain estimates were also confirmed through field trials.
Easy deployment for compliance with PHMSA requirements
• Data is acquired using a drone vector to rapidly collect the data regardless of terrain conditions.
• Pipelines can continue to operate as the necessary data is collected from the ground surface with no interference with the flow inside the pipeline.
• The field operator is safe as all data is acquired using a drone, ensuring that a safety distance is respected at the site of a geohazard event.
The Skipper NDT technology is positioned as complementary to other technologies, to remove any doubts concerning pipeline mechanical integrity in case of geohazard events. The speed of execution and the data accuracy provided without impacting pipeline operating conditions make it a valuable complement to alternatives such as ILI tool.
Figure 5. Bending strain plots (top) showing vertical anomaly and magnetic map variation (bottom).Mapping and surveillance have shown a repeated high return on investment for asset management, says Luke Brouwers, Engineering Geologist, and Ibtesam Hasan, Senior Corrosion Engineer, Fugro, UAE.
s the world’s demand for energy continues to grow, pipelines remain to be one of the most efficient and safest means to transport oil and gas over a long distance. The long linear nature of export pipelines traverses through a multitude of topographic/geological conditions and often transitions from onshore to subsea. Due to the importance of pipelines in our daily lives, a comprehensive study needs to be performed to assess the feasibility, design and monitoring of the pipeline for the entire lifespan of the asset. Investing in geodata to acquire, analyse and advise on understanding the environment of a pipeline is paramount, and a methodology that has shown repeatedly high return on invested resources is mapping and surveillance. Poor management of pipelines can result in catastrophic environmental and financial consequences. The cost of oil spill clean-up in the sea can vary widely depending on the size of the spill, the location, and the extent of the damage caused. According to a report by the National Oceanic and Atmospheric Administration (NOAA), the average cost of an oil spill clean-up at sea in the US ranges from US$10 000 to US$40 000/bbl of spilled oil, and
this does not take into consideration the significant damage to the environment.
The cost of oil spill clean-up on land can also vary. According to the US Environmental Protection Agency (EPA), the average cost of an oil spill clean-up on land is about US$50/gal. of spilled oil. Similar to clean-up operations at sea, the cost of an oil spill clean-up on land can also include the economic, environmental, and social costs associated with the spill. These costs can include lost revenue for businesses and farmers, damage to wildlife and their habitats, and longterm impacts on the health of ecosystems and local communities.
In the Middle East, due to the shallow sea and oilfield proximity to land, many export pipelines transition, further complicating the management of this fragile asset. Complications come from a combination of internal and external forces in varying landscapes. Internal factors in the initial ground conditions can vary greatly from extremely weak/loose carbonate clay or sand deposits in marine environments to mountainous hard rock on land which presents a different hazard to the pipeline. This is then compounded by changing external factors such as currents, corrosivity, and soil
interaction with pipelines in marine environments to climatic, human interference, and variable erosion of foundations on land. At Fugro, our engineers and experts have developed several tools and techniques that help oil companies map the pipeline networks both on land and at sea, devising a comprehensive surveillance programme to safeguard the asset from geohazards for the intended lifecycle of the pipeline.
Despite the widely acknowledged importance of pipeline surveillance programmes, the adaption of new technology and taking full advantage of the advances in recent years remain limited. Some of the challenges and limitations of conventional surveillance and inspection technology are:
While the conventional methods have been adequate to fulfil the regulatory and legal considerations, the opportunity for technological enhancement has been limited in line with the status quo which was widely accepted, and any further development was considered excessive. Modern IT infrastructure and secure cloud allow faster and simultaneous quality control of the data and enables wider integration with cloud-based asset integrity management software.
Pipeline surveillance and mapping can be challenging due to the geographical and environmental factors associated with pipeline routes. This includes difficult terrain, remote locations, and exposure to hazardous offshore conditions that can impede efforts.
Collecting and analysing sensitive data, such as pipeline locations, operational status, and inspection results is a fundamental part of the surveillance programme. Ensuring data security and privacy is a significant challenge, as unauthorised access or data breaches can lead to safety and security risks, as well as legal and regulatory compliance concerns.
It can be a resource-intensive process in terms of personnel, equipment, and technology.
Human factors, such as human error or lack of expertise, can also impact pipeline surveillance and mapping. Operational mistakes or misinterpretation of data can result in errors or delays in identifying and addressing potential pipeline issues.
In the Middle East, Fugro follows the journey of a pipeline all the way from sea to land. Starting with the mapping and surveillance of pipelines underwater adds several unique challenges to the operations. Fugro still offers conventional ROV subsea inspection, repair, and maintenance. With the objectives of sustainable operations and reducing carbon emissions, Fugro has developed a fleet of highly advanced electrical ROVs (eROV) complemented with unmanned survey vessels (USV). The advanced sensors and modern communication infrastructure has made it possible to acquire high-quality
Figure 1. Fugro’s uncrewed surface vessel (USV), the Blue Essence® performing subsea inspection with electrical remotely operated vehicles (eROV).
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data and transmit it onshore for further analysis, therefore significantly reducing the manpower deployed offshore and improving the safety of the mapping and surveillance operations.
The need to analyse subsea data and transform it into a visual geo-intelligence product raises the need for more innovative software that can utilise the modern information technology infrastructure. Fugro’s Sense.Pipelines is a bespoke cloud-based solution designed to capture, store, process, model, and report on the integrity of subsea pipeline and cable assets. By leveraging custom-built machine learning algorithms, cuttingedge cloud computing technology with the latest sensors and in-house, state-of-the-art ROVs, Sense.Pipelines provides an immersive 3D visualisation and detailed reporting application that is unparalleled in the industry, offering a solution that enables operators to manage and maintain pipeline infrastructure safely.
With the pipeline progressing onshore, it is paramount to reduce the risk posed by landslides, faults, sinkholes, and other geological hazards present by executing qualitative and quantitative risk assessments that can be achieved by integrating multi-discipline datasets through geological and geomorphological mapping campaigns. These mapping campaigns form the base of identifying, evaluating, analysing, and modelling geohazards through desktop studies, natural terrain hazard evaluations, hydrological assessments, debris flow modelling, and seismic fault investigations. Understanding of identified geohazards can be achieved by Fugro through digital terrain modelling, satellite mapping and monitoring, terrestrial and geodetic surveying, laser scanning (e.g. LIDAR), airborne topographic surveys and geophysical techniques to explore the subsurface variability of the soil and rock along a pipeline corridor to reduce the geological risk.
Progressing to the design stage, mapping improves planning for site investigations and mitigates the ground risk by lowering uncertainties and contingencies in the design and construction process. However, this initial site screening is only the beginning,
and continued surveillance of the pipeline is needed to ensure the risks are managed and the integrity of the asset is maintained. Monitoring and surveilling along a pipeline corridor requires an appreciation of the terrain and the environment with the interactions between them. OnSight®, Fugro’s intelligent 3D plant model that acts as a ‘digital twin’, combines innovative technologies to deliver an information management solution that provides valuable data on the condition of the assets to lower operation costs.
The unique combination of state-of-the-art technologies and methods over the entire journey of a pipeline has made reliable, consistent, and reproducible inspection the new standard practice while delivering the following additional benefits to help oil and gas companies achieve their sustainability targets.
) Significant increase in the safety record by lowering the number of offshore going personnel.
) Real-time results.
) Increased efficiency of the operations by maximum utilisation of the IT infrastructure.
) Enabling collaboration and reducing air travel with the option of real-time global access to geo-data.
What’s next
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.
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 higherquality data. These vessels, along with the bespoke cloud-based software solution provided by Sense.Suite, make this possible.
Fugro’s solutions provide clients and asset managers with essential information to meet the demands and rigorous schedule of pipeline construction and operations. Investing in geo-data to acquire, analyse and advise on understanding the environment of a pipeline is paramount and a methodology that has shown repeatedly high return on invested resources is mapping and surveillance.
or decades, hot tapping and plugging (HT&P) has been the go-to procedure for isolating an in-service pipeline prior to maintenance, modification, or repair. But even though traditional HT&P approaches are relatively emission-free compared to the volume of product moving through the system each day, operators face ESG and regulatory pressures that make ‘relatively’ not close enough. Having to vent or flare even nominal amounts of methane during routine operations is no longer acceptable to many pipeline operators, though it’s a hard habit to break; according to the US Energy Information Administration (EIA), in 2019 operators flared or vented 538 billion ft3 of natural gas. Gas recompression systems are often used to remove that last bit of gas from the isolated segment, but even here, it has been impossible to get to 0 psi.
However, the WeldFit ReCAP® Emissions Recovery system with StraightLineTM performance gets closer than any other recompression technology on the market. ReCAP technology uses a simple, three-step process to recover methane during pipeline depressurisation operations as an alternative to routine flaring or venting. The system captures the natural gas, recompresses it, then discharges it into an adjacent pressurised system. By marrying their HT&P operations with ReCAP technology, WeldFit
Turnkey hot tapping and plugging with gas recompression maximises productivity, says Brian Anderson, President Line Intervention, WeldFit Corporation, USA.
provides a single-source solution to help operators meet regulatory requirements and achieve ESG goals.
WeldFit recently paired its HT&P and ReCAP services to isolate and then evacuate product from a 30 in. pipeline that carries 480 million ft3 of natural gas daily. Obviously, the costs of shutting down a line that size would be astronomical in terms of lost productivity, making intervention and isolation the best option, if not the only option.
WeldFit provided:
) Live-line welding of proprietary fittings.
) Hot tapping.
) Double block isolation using proprietary technology.
) Gas recompression.
The successful isolation enabled the operator to install an above-grade block valve and to tie in a 24 in. distribution
system. That system will allow a new provider to send product to the operator’s gas plant.
What’s more, by using ReCAP technology instead of venting during the isolation, WeldFit prevented 550 064 ft3 of methane from escaping into the atmosphere, a CO2 equivalent of 249 t. That saved the same amount of greenhouse gases (GHGs) that would be emitted by 50 passenger cars in a year, and an amount of CO2 equivalent to what would be produced by 42 homes’ electricity use over 12 months.
While HT&P and gas recompression often go hand-in-hand, the hand-off between service providers can leave something to be desired. There is always the risk of delays, additional downtime, and errors.
By bundling their HT&P and ReCAP services, WeldFit ensures a smooth transition and keeps projects on schedule and within budget. Providing turnkey services means bringing everything together to complete the job, including welders,
HT&P technicians, and gas recovery crews. While there are many moving parts to facilitate a project like this, having one provider take on multiple roles makes things go more smoothly.
In this case, for example, in-service welding was the driving factor – line intervention and isolation couldn’t begin
until the welding was completed, which meant the quality of the welding had to be perfect to avoid delays. After the fittings were welded on and the welds inspected, hot tapping could begin immediately. Then, once the line was isolated, gas recompression could start.
While having one provider perform all services is inherently efficient and avoids the kind of risk associated with multiple contractors trying to coordinate their activities, using WeldFit for this project actually shaved an entire day off the initial schedule.
“Bringing everything in under one roof makes it a lot easier to execute large-scale projects and collaborate across the job site,” said Branden Allen, Director of Field Services – Emissions Management. “We’re able to schedule our line intervention and recompression crews to be onsite at the same time, which keeps our customers from having the burden of scheduling multiple contractors.”
WeldFit crews performed the hot tap under full pressure (80 bar or 1170 psi), using the double block configuration to isolate a pipeline section approximately 1500 ft long. The industry is increasingly choosing double block technology to provide an added measure of safety during inline isolation. By providing the redundancy of two seals, systems such as WeldFit’s ensure a safe work zone free from product leaks.
“Our customers are now requesting a double block to mitigate risks and ensure a 100% seal,” Chris Peavy, Service Coordinator – Line intervention, said. “A double block essentially establishes a primary sealing force and a secondary one behind it. Depressurising the section between the two seals creates a no-pressure zone which assures no leakage but moreover crew safety.”
Although the double block isolation was sufficient to keep product from leaking, as part of their normal protocol the operator also used multiple valves to further isolate their gas plant and ensure no product could make it into their facility. With the line and gas plant isolated, the operator was able to install a 20 in. line to bypass the gas around the plant and continue service to downstream customers.
“Our isolation technology allowed the operator to safely divert the product around the gas plant and temporarily
Figure 2. WeldFit’s ReCAP fleet is well-suited to handle a wide range of recompression applications from high frequency, small volume jobs to those jobs that happen less often but require large volumes of gas to be moved in a timely manner.
move product to the next facility downstream,” Peavy explained. “The operator isolated it on their side and we isolated the pipeline portion coming into the gas plant. This allowed the operator to do all the work in between.
“All aspects of the projects, including the installation of the hot tap equipment, went off without a hitch, thanks to the skill of our highly trained technicians,” Peavy added. “For example, we had 100% non-destructive testing and examination of all welds with no repairs. The isolation progressed equally smoothly. There were no problems on this project at all. After performing the isolation, we handed the project over to the customer with a 100% seal.”
The next step was to depressurise to 0 psig across the isolated portion of the line using ReCAP equipment. Using portable ReCAP technology is a simple process, as easy as 1-2-3.
WeldFit crews connect the suction line of the ReCAP unit to the isolated pipeline section to be depressurised and then connect the discharge line to the adjacent pipeline system. During the process, technicians take care to create no-leak seals at all connection points – all in line with HSE and ESG objectives.
With a push of a button, ReCAP depressurises the isolated section and recompresses the methane for discharge into the adjacent pipeline system. What sets the ReCAP system apart is its patent-pending Straight-Line predictability, which allows greater control throughout the process. By maintaining consistent depressurisation and recovery speeds, ReCAP technology improves methane recovery and reduces GHG emissions by nearly 100%.
Control is ensured no matter the pressure differential, from 1440 psig and down as the pressure levels drop. Other systems struggle to maintain consistent depressurisation speeds throughout the process, which slows down their performance and adds to the burden of downtime.
Gas recompression helps improve operational efficiency by allowing the operator to capture and reuse natural gas that would otherwise have been wasted. While the cost benefit might seem minimal on routine projects like replacing a filter or performing maintenance, every time a closure door is opened or a pipeline is tapped, emissions occur. And while switching out a filter or pigging a pipeline might result in a small emissions release, because those operations are done so frequently, the amount of emissions adds up over time. What all this means is that gas recovery isn’t something to be earmarked only for pipeline operations with the potential for large-scale emissions release.
Finally, gas recompression ensures compliance with regulatory and industry standards covering emissions reduction, and addresses shareholder and management concerns about environmental impacts. Recapturing natural gas during hot tapping operations also allows operators to maximise client satisfaction by avoiding downtime, ensuring that gas keeps flowing downstream to its destinations on time.
For WeldFit, helping customers meet regulations, ESG requirements, and their own net-zero ambitions, all starts by putting the right equipment into the right hands. The company provides thorough and specialised technician training to ensure the highest quality performance under strict safety protocols. An integrated approach to the technician certification process emphasises classroom instruction, hands-on training, and extensive personal mentorship, and is one of the company’s keys to employee retention.
In short, the company does everything it can to help operators remain on a steady course toward achieving their goals, no matter how unpredictable the marketplace can be.
“WeldFit’s vision is to provide solutions that prioritise ESG-related issues and keep them at the forefront,” Allen said. “Adhering to ever-changing emissions regulations has become a priority for the company in recent years, while responding to the expectations of pipeline owners, operators, and key stakeholders.”
an digitisation improve weld quality, a process that is inherently manual and analogue? Yes, it can, and a Brazilian company is leading the way with its use of an innovative online document management application software.
Braskem, headquartered in São Paulo, Brazil, continuously seeks ways to streamline and monitor its many operations, and supports technology to achieve sustainable development. Using a cloud-based application to manage weld quality, procedures and documentation received C-suite endorsement, as well as support and engagement from nearly every department in the organisation. The company has transformed its weld quality through traceability, documentation and compliance practices. Root causes of weld failures have been identified. Related risks have been greatly reduced. Contractor performance has improved, and Braskem has saved thousands of hours related to document management.
As with most petrochemical companies, Braskem employs a team of inspectors, welding engineers and quality assurance personnel to monitor and manage processing equipment. These teams then engage local contractors and maintenance companies to provide welding services. To satisfy traceability requirements of its customers and comply with international standards organisations approved for use in local regulations (ASME BPVC), Braskem and its contractors need to document procedure qualification records (PQRs), weld procedure specifications (WPSs), welder certifications, the actual weld seam and non-destructive testing (NDT) results.
Prior to 2018, documentation at Braskem was largely manual, and managing documentation for the hundreds or thousands of welds made on a weekly basis consumed a lot of
With this software, we can verify the company and operator responsible for every weld seam, says Tiago Pereira, Product Manager - WeldCloud Notes, InduSuite, Portugal.
time and inherently introduced the potential for human error, such as through handwriting mistakes or keyboard data entry.
Fortunately, Braskem knew it needed to improve its processes to better ensure quality and minimise liability in the event of a weld failure.
“We didn’t have a system to handle all the documentation. We didn’t have any transparency on the information that we received. We’d only have a huge stack of papers that were dropped on my desk that had to be reviewed,” says Luis Greggianin, Braskem Welding Engineer. “There was not enough testing or traceability, so our subcontractors would end up sometimes cutting out and redoing the weld. We experienced approximately two rewelds a day, and that’s too much rework, too much time and too many delays in productivity.”
“We understood that we had to change,” adds Josias Thomaz, a Braskem Weld Inspector. “This was a risk for our business because all welds are made to handle flammable
material. We started exploring ways we could improve to create a best-case response to an emergency shutdown.”
To find the best solution to its quality and traceability challenges, Braskem established a multidisciplinary team. With early support from its Global Welding Leader (an executive position), the team grew quickly and remained motivated to succeed. The departments involved included engineering, maintenance (which manages welding), IT, and reliability. Many of these departments operate independently and/or work in different locations, but coming together was essential.
“I’m usually working in a field office, and the reliability department is separate from engineering, but the reliability department financed this solution,” says Greggianin. “It was also critical to have IT involved right from the beginning to address data security and for software training purposes.”
“We looked into potential options,” says Greggianin. “A British one, a Brazilian one and a couple of American solutions. In the end, WeldCloud Notes had all the features that we needed and was the most modern platform, so we decided this was the best solution.”
WeldCloud Notes is a software platform from InduSuite, which is backed by welding industry leader ESAB. Ideal for welding engineers, inspectors and quality personnel, WeldCloud Notes streamlines the documentation and reporting process via online applications. Accessible by computer or mobile device, the software enables Braskem and its contractors to monitor four states of weld production: fit-up, welded, tested, and processed.
The digital software applications provide a suite of tools and dashboards. They are accessible from any web-enabled device and are password-protected. Ideal for welding engineers, reliability managers and quality personnel, WeldCloud Notes streamlines the documentation and reporting process by completing four essential tasks:
) Maintain quality and compliance while managing PQR and WPS documents in one place.
) Efficiently review all PQR, WPS and WPQ information with a quick and easy search.
) Generate a PQR or WPQ with all of the essential variables.
) Avoid a missed qualification deadline or wasted resources requalifying welders.
WeldCloud Notes provides full compliance to construction codes (ASME VIII, ASME B31.3, EN 1090), welding standards
Figure 2. A growth and internationalisation strategy, supported by innovations such as using cloud-based applications, has made Braskem a petrochemical industry giant.
(ASME IX, ISO 15614-1, ISO 9606, AWS D.11) and welding quality standards (EN 3834). It enables users to track the productivity of individual welding systems and welders, register weld seam data and manage the calibration records for an entire fleet of welding machines. As an online software tool, every
relevant person on a project can access information (with restrictions specified by the administrator), search for the correct PQR and WPS, introduce welding records, keep track of production and print reports for all the activity completed.
In 2018, Braskem started with 20 licenses for a pilot project for replacement of parts on a pyrolysis furnace during a scheduled maintenance shutdown. Two subcontractors were initially scheduled to make 107 welds. The reality of working in the field required modifications that led to a total of 297 welds completed and documented. By using the software application, Braskem and its subcontractors could:
) Assist in the verification of each weld.
) Identify which welds required the most repairs and/or extra effort.
) Identify which welds were impossible to repair.
) Develop more accurate repair schedules.
) Calculate costs more accurately.
“Because we had an unlimited demo trial, we could test for multiple hours and understand how the software responded and determine any issue that might exist within it. This helped us quickly move forward,” says Greggianin. “And one important thing was that during the tests and even today, we have never encountered any bug or issue that stopped us from working.”
As a result of the pilot programme, Braskem realised, “There were some deficiencies with the welding operators from some of the subcontractors, and WeldCloud Notes helped us identify these issues,” says Thomaz, who helped lead the implementation with subcontractors.
“In addition, we can overview the progress of our subcontractors. There is added transparency to everything, and there is more reliability in our process,” he says. Initially, the subcontractors were reluctant and thought this was just added work. Their opinion changed after they understood that they, themselves, would not have to spend extra time crafting the documentation because everyone
Figure 4. WeldCloud Notes manages and communicates all essential weld seam data to improve traceability and mitigate risk. WeldCloud Notes enables Braskem to verify the company and operator responsible for every weld.involved with the project was using the same software platform.
“The software is also very user-friendly,” says Thomaz. “After using the software and having some training, the contractors saw that it was easy to use and that they had support at all times. We used a chat feature to interact, and we got answers in seconds.”
Braskem decided to pay for their subcontractor’s licenses, which further fostered a positive attitude. Additionally, Braskem’s software administrators can segment and limit the data subcontractors can see. Each subcontractor has proprietary information (e.g., WPSs, welding results), and they didn’t want other Braskem subcontractors accessing that intelligence.
Braskem has now realised that the best approach to reducing the risks associated with weld failures requires creating a more robust and efficient system to increase traceability, documentation and communication internally, and with their welding subcontractors. These functions are inherently linked, so a holistic and systematic approach is essential for success (as opposed to managing these functions as independent silos).
Before implementing WeldCloud Notes, Greggianin estimated that failure to comply with the WPS caused 30% of the rework cases and poor supervision, visual inspection or NDT practices caused the other 70%.
As an example, he points to pipe welds where operators tried to complete the weld faster by using a single pass instead of multiple passes, or used incorrect welding parameters and increased travel speed. In both cases, the supervisor and visual inspection failed to detect the weld flaw, which was ultimately revealed by radiography.
The welding software addressed these quality issues because it accurately communicates the WPS, NDT methods and NDT documents to field teams. Braskem then uses the software to document all test results, which are immediately available for real-time assessment.
“The software cannot assist in the inspector’s work, but it helps with the whole process,” adds Thomaz. “Our new process allows for full traceability, and we have all the records of all the
specs used. The operators now understand that the weld has to be done properly and exact procedures must be followed. Overall, they’re happier because they really hate doing rework.”
Greggianin says that “Everyone involved in the welding processes is more determined to do it properly because of the added scrutiny. Welding software allows us to monitor welds very quickly. We can identify the status of a weld – in fit-up, welded, tested, or processed and complete – from any location. We don’t have to wait for field reports. With the software, we can now verify the company and operator responsible for every weld seam, and this is very important for us.”
40 YEARS, WE’VE BUILT THEM RUGGED SO YOU CAN RELY ON THEM TO PERFORM
David Garrard, Director – APAC, Xiris Automation Inc., Thailand, discusses inspecting large diameter pipe for weld and geometry defects.
he large diameter pipe (LDP) market is usually defined as including all pipes and tubes that have a diameter larger than 12 in. (30 cm). The primary target market for LDP is the oil and gas sector, but uses have also been found in power generation, transportation, petrochemical, construction, and more. Since the 1950’s, these pipes have been welded longitudinally using electroresistive welding (ERW). The ERW’s popularity has grown over time, and so have its technical advantages and efficiency benefits.
The last few decades have seen significant improvements in almost all aspects of steel manufacturing – smelting, metallurgy, and rolling. This has led to improvements in the size, quality, and physical and chemical properties of hot-rolled steel strip used for large and medium-calibre ERW steel pipes. Other ERW process improvements include:
) Automated control of welding parameters.
) Implementation of industry standards such as ISO9000 and APIQI.
) Automated detection technology improvements using online or offline full-weld ultrasonic or eddy current testing.
) Computer supervised hydraulic testing.
) Computer control of heat treatment and annealing (normalising).
Over time, these improvements have allowed mill makers to build, and sell, larger ERW mills to handle larger diameter pipe products. Diameters up to 28 in. (711 mm) with wall thicknesses of 1 in. (25.4 mm) have been achieved recently, providing fabricators with the ability to enter new markets that have previously been served by other slower pipe manufacturing methods. In fact, this new capability has led some countries to prohibit the use of spiral-seam submerged arc welded pipes on long-distance oil and gas pipelines.
Many LDP production lines cater to the oil and gas market, leading ERW LDP fabricators to face a number of special challenges.
API requirements are quite demanding; buyers expect zero defects in the pipe they purchase.
Market demands continue to push fabricators to make pipe with greater wall thickness, making it harder and harder to control the forming process. This requires better quality design of the forming process, particularly the rollers.
Economic drivers always push for higher speed mills. Some of the world’s largest diameter pipe mills using automated HF/ERW (300 KHz) welding processes, with cage and breakdown roll forming, can operate at speeds of up to 45 m/min.
Diameter/thickness ratios at both high and low extremes make for a more challenging fabrication process – contributing to forming related defects.
Properly preparing the strip edge of thicker raw steel roll to allow it to be properly formed in an ERW welding process requires extra effort and control.
Difficult defect control
Various weld quality defects such as seam gap, mismatch and freeze line become more significant and difficult to control with LDP.
Higher cost
Because LDP material costs are greater compared to smaller tube production, any scrapped material can be very costly for the fabricator.
Meeting all the testing protocols for API standards can be quite difficult. Ultrasonic (UT), eddy current (ECT) and pressure testing (PT) can be complex to interpret, requiring expert technical staff with significant experience – something very difficult to find and retain.
But along with these challenges, come benefits:
ERW mills provide a much faster mill processing speed compared to other pipe welding methods.
ERW for LDP is a long, multi-stage fabrication process. Best-in-class-mills implement real-time monitoring at early stages in the mill to identify and correct
• Propipe provides a suite of services to ensure a successful project including full pipeline review, cleaning pigs and Trident SMART gauge.
• Propipe pigs all designed pipelinespecific for best performance.
• Trident pig tracking and APEX AGM plus SMART Gauge and Datalogging for full data assessment.
defects as soon as possible, leading to higher efficiency and improved yields.
When mills operate at higher speed, with higher yields and quality, this can lead to a significant boost in plant profit margins.
In the search for earlier process fault detection to lessen reject rates, progressive pipe and tube mill owners have begun looking to higher technologies. A popular solution is using real-time weld bead and pipe geometry defect detection system, such as the Xiris WI-3000, that uses laser triangulation techniques and is located immediately after the ERW weld box. The system’s large sensor field of view makes it ideal for many LDP welding processes.
These smart sensors act as an intuitive early warning system to line operators who can be alerted when processes are moving out of control, and can adjust the mill before the process makes defective product. Although next-generation sensor solutions such as the WI-3000 are not a replacement for standard non-destructive testing (NDT) systems, they complement them, detecting process variations and flaws that might otherwise be overlooked.
Pipe and tube manufacturers, driven by quality and profitability goals, continue to seek out sensors and process monitoring solutions that integrate with their systems and
Figure 2. Xiris Weld Inspection System installed on a mid-sizedStuart Stephens is a Director of Stockton Drilling, and has been involved in the successful running of one of the leading HDD companies in the UK for the last 15 years. A pipeline engineer by background, Stuart has greatly assisted in the refinement of HDD installation in the UK and with the introduction of Direct Pipe as a technique in pipeline installation in the UK.
: Describe a recent HDD project for an oil/gas pipeline.
: Stockton Drilling Ltd has been involved in the outline design of two landfalls required for 28 in. gas pipelines on the east coast of England, UK. The landfalls required a trenchless methodology due to the presence of Sites of Special Scientific Interest (SSSI) designations on the coastline, combined with steep site topography behind the foreshore.
Informed by the results of topographic, bathymetric surveys and ground investigation, the favoured methodology is Direct Pipe. This offers the benefit of providing a sleeve for the pipeline, therefore de-links the landfall works from the pipeline installation works. This provides more flexibility around construction phases which will be dictated by weather and sea state windows. Direct Pipe also offers the benefit of reducing offshore works for the landfall, avoiding the need for an offshore jack-up barge with the TBM head to be recovered by a barge mounted crane after punching out on the seabed.
: For the Direct Pipe methodology, with exception of the launch and reception pits, there is no impact to the aboveground
environment over the length of the trenchless installation. The profile is designed to be at a sufficient depth to avoid hydrofracture of drill fluids to surface. The casing installed behind the TBM as part of the Direct Pipe process mitigates excessive ground movement.
The launch and reception pits are designed temporary structures utilising braced and propped sheet pile walls with a reinforced concrete base slab. The slab can be grubbed out and piles cut down on completion to return the area to the original condition.
The string out requirements behind the launch pit are similar to HDD, requiring a minimum 30 m (ideally 100 m) of clear level space which would typically be surfaced with Type 1 and removed on completion.
: The HDD technique creates a bore for the pipeline to be installed, this bore is generally 30 - 50% larger than the outer diameter of the pipe. This drastically reduces the risk of any damage to the pipeline protection that could occur during installation.
Before a pipeline is installed into its final position using HDD, it is fully inspected and also subject to a coating test called a holiday detection test. This final test checks for any nicks or
scratches in the pipe coating; should any be found, these are then carefully repaired and the installation can commence. Finally, once installed, another test called a cross bond test is carried out to verify the installed condition of the coating.
Should any minor imperfection be detected during this test, it would be dealt with using the CP system.
When the direct pipe system is used, the product pipe is installed directly and the system advances minimise the risk to the product pipe. The selection of the product material is crucial in terms of looking at coatings, wall thickness and cathodic protection.
: Gravels and unconsolidated ground are generally the least favourable medium for drilling, hence the addition of Direct Pipe to our fleet. If we are involved early enough in the lifecycle of the project, we try to design a solution to cope with the difficult ground; it is more difficult to cope with such ground during the installation if it is unforeseen.
: We have seen a major increase in both enquiries and award of contracts in the last few years, for both pipeline and cable installation projects. This is mainly due to the explosion in offshore wind in Europe and the major infrastructure installation to help the UK achieve its carbon reductions.
• Increase productivity
• Increase quality
• Lower repair rates
• High level of support
Together, we create the most distinctive and integrated welding solutions for the construction of reliable and sustainable pipelines.
Whether it’s oil, gas, or any other fluid, we are here to ensure reliability and make projects run smoothly. Quality is top priority, we settle for nothing less than perfection.
No matter location, challenges, or circumstances, Qapqa is your go-to partner for exceptional welding solutions. From remote deserts to high altitude environments, we deliver our expertise to every corner of the globe.
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Rolf Gunnar Lie and Neil McKnight, T.D. Williamson, discuss a new approach to the safety and design of pig trap quick actuating closures.
elivering quality product at required volumes means leaving nothing to chance, including asset maintenance, which is essential to pipeline integrity. Pigging activities, including inline inspection (ILI) and cleaning, help keep pipelines in prime operating condition and extend useful life, but it takes proper equipment, planning and operator training to ensure safety, especially during pig launch and retrieval. Without the right technology for safe and easy access, opening the pig trap closure door can present
unacceptable risk to both personnel and infrastructure. In fact, opening the closure is considered one of the most critical operations in pipeline pigging.
Why? The key concern is that when the pig trap door opens it will allow air to mix with hydrocarbons, creating an explosive atmosphere. But that’s not the only potential hazard. Sudden releases of pressure and projectiles can also jeopardise the operators’ safety, and valves must be opened and closed in the appropriate sequence to avoid damaging the pigs and the pipeline system itself.
One way to mitigate incidents is to minimise the time and effort involved in opening and closing the pig trap, which is generally a function of the type of pig trap closure in use — some are simply more straightforward and safer to operate than others. For example, it’s easier to open and close a quick actuating closure (QAC) or quick opening closure (QOC) than it is to install or remove a blind flange.
The QAC or QOC can be opened by one person, typically in a single motion, without tools. In fact, the ability to swing the door open with one movement is part of how ASME defines the equipment: ASME
Boilers and Pressure Vessel Code (BPVC) Section VIII standards note that quick actuating means “all elements loosening in a single actuation.” This feature enables the rapid introduction and removal of pipeline pigs without compromising the safety of field personnel, damaging equipment or releasing hydrocarbons into the environment.
By being the main access point into the pipeline system, the QAC is a critical component in minimising the volume of methane emissions that could escape into the atmosphere. Given the world’s net-zero ambitions and the industry’s drive toward sustainability – not to mention regulatory compliance – this is an increasingly important factor. Although it’s difficult to find industry-wide or agency statistics about the amount of methane released during pig trap operation, the UK’s National Transmission System found that each time they averted a failure by replacing pig trap seals, they saved 8.5 t of carbon dioxide equivalent (CO 2e).
By contrast, installing or removing a blind flange requires dozens of bolts and nuts to be loosened and torqued. Not only does this process call for its own set of tools, but it also adds hours of labour and additional risk for field technicians.
Like any other oilfield equipment, QACs must comply with codes that vary by country and product. Although older pig traps were designed to meet pressure vessel codes, that’s no longer the case, and with good reason: the function of the closure is to provide internal access to the pipeline system, not the inside of a vessel.
Instead, pipeline operators now typically require pig traps to be designed according to the same code(s) as the pipeline on which they are installed – for example, ASME B31.8 - Gas Transmission and Distribution Piping Systems or ASME B31.4 - Pipeline Transportation Systems for Liquids and Slurries. This is possible because pig traps are considered pipeline assemblies, meaning the code that covers the pipeline itself also applies to the pig trap.
Of course, different codes have different qualifications – and different ways a pig trap closure design can satisfy them. For a closure to be installed on an ASME B31.4 or ASME B31.8 pipeline, for example, the interface between the closure assembly and the trap must reflect an intentional methodology that meets safety considerations – like keeping the technician out of the ‘line of fire’ in case of a pressure release. ASME BPVC Section VIII says the closure design
Figure 1. Operation of QAC outside ‘line of fire’.
must incorporate a safety locking mechanism so the closure cannot be opened while it is under pressure.
Trying to understand and meet all the applicable codes is no easy task. In an effort to cover all the bases, equipment providers may be tempted to overdesign their pipeline traps and closures, which can be a waste of resources.
Let’s say a pig trap is built entirely to pressure vessel code. Not only is this unnecessary, but it’s also more expensive to manufacture. That’s because pipeline code allows the use of thinner (and less costly) high-yield strength API pipe for the barrel and nominal section instead of the lower yield strength, thicker materials limited by ASME BPVC Section VIII. The codes provide flexibility with regards to raw material selection, which reduces overall cost. Why not take advantage of it? That’s exactly what the split code approach does.
Designing a pig trap using a ‘split code’ approach means the shell of the closure will meet ASME B31.4 or ASME B31.8 pipeline codes while the head of the closure complies with ASME BPVC Section VIII. As highlighted in ASME B31.4, “It is not the intent of this Code to necessarily extend the design requirements of Section VIII, Division 1 to other components in which closure door (heads) are part of a complete QOC assembly.”
The T.D. Williamson (TDW) D2000 QAC satisfies those criteria. It consists of three primary components: a door
or head compliant with ASME BPVC Section VIII, a clamp ring retaining device and a shell or hub that complies with pipeline codes (as shown in Figure 1).
The D2000 QAC also removes the risks associated with personnel standing in the ‘line of fire’ and being exposed to a potentially deadly undetected build up of pressure or projectiles: the technician stands safely to the side, operating the closure by the loosening of all holding elements in a single actuation before swinging the door around the fixed hinge point (shown in Figure 2). In addition, the D2000 QAC’s pressure warning lock (PWL) is located top-centre to minimise the possibility of contamination by pigged-in debris clogging up the pressure release port. The PWL works like a bleed plug: when opened, any pressure will bleed through the plug and warn the operator there is still pressure inside the pig trap that needs to be bled down before opening the QAC. These features allow users of the D2000 QAC to operate safer and exponentially faster than they would if they had to open a blind flange.
In essence, the D2000 QAC represents the best of all worlds, enabling safe, code-compliant operation while allowing critical pigging operations to proceed with minimal time, cost or intervention.
1. STANDARDS AUSTRALIA, ‘AS/NZS 2885.1:2018’, Gas and Liquid PetroleumDesign and Construction (2018).
2. www.nationalgrid.com/sites/default/files/documents/Safety_in_Pig_Trap_ Closures.pdf
Having a suitable infrastructure to transport and store CO2 safely and reliably is essential for carbon capture and storage (CCS) expansion worldwide. CCS facilities can either be standalone ‘point-to-point’ projects or ‘hub and cluster’ networks that bring together multiple CO2 emitters and storage locations using shared transportation infrastructures. Establishing such CCS hubs will help accelerate deployment by reducing costs.
International Energy Agency’s (IEA) analysis of CO2 emissions from power and industrial facilities in China, Europe and the US found that 70% of the emissions are within 100 km of potential storage; but shorter distances can reduce costs further and decrease infrastructure development times.1
According to the IEA’s ‘CO2 Transport and Storage’ report, there are currently around 9000 km of CO2 pipelines – mainly in North America – and seven dedicated geological CO2 storage operations with a combined capacity of 10 million tpy.2 Dedicated CO2 storage capacity could reach 110 million tpy of CO2 by 2030, which is far less than the nearly 1200 million tpy of CO2 that is captured and stored by 2030. However, pipeline infrastructure to support CCS will need to scale substantially. According to the Global
CCS Insititute, reaching climate targets will require 70 - 100 capture facilities to be built each year by 2050.3 These facilities would need to be supported by 200 000 km of pipelines as well, with an average build rate of 5200 - 7200 km/yr. There is currently strong interest within the industry to explore the possibility to repurpose existing pipeline infrastructure to leverage existing CAPEX investments.
Repurposing gas pipelines for CO2
In recent years, several operators have been considering repurposing existing pipelines for CO2 transport. Repurposing, rather than constructing new pipelines, can reduce both project risk, carbon footprint, and costs. Several projects in development, including the Acorn Project in the UK, plan to reuse existing infrastructure. Looking at the whole value chain involved in pipeline transportation of CO2, a series of ‘pain points’ have been identified where development work can add significant value to CCS projects:
) An important decision in the design of a new CO2 pipeline system or repurposing an existing pipeline system, is whether the product is to be transported in gaseous or dense phase. For the design of new pipelines, a general opinion is that transportation of
CO2 in dense phase rather than gas phase is preferable due to increased capacity. However, several re-qualification studies point to the transportation of CO2 in gas phase as an attractive solution, and in many cases the only viable solution due to limitations in the original design pressure. As a result, improved guidance and recommendations for selecting dense phase or gas phase are necessary.
) Generally, it is preferable to have as ‘wide’ CO2 specifications as possible to avoid expensive cleaning of the CO2 stream before it enters the pipeline system. However, the composition of the CO2 needs to be controlled to avoid any negative impact on the integrity of the system. The captured CO2 may contain a range of impurities dependent on the source of the emitters. The presence of acidic gases like SOx, NOx, H2S, may increase the risk of corrosion and cracking of the pipeline. The CO2 composition may also affect the thermodynamics, e.g. saturation pressure. These mechanisms and the risk they pose to the system’s integrity needs to be understood.
) Arresting and stopping running ductile fractures in pipelines transporting CO2 has proven to be more challenging than in transporting natural gas, and many pipelines fall outside the applicability range of the requirements laid out in the DNV recommended practice ‘Design and operation of carbon dioxide pipelines’ (DNV-RP-F104), 2021 version.
DNV-RP-F104 gives recommendations for the design and operation of pipelines transporting CO2. However, it is recognised by the industry that recent experience and research, including upcoming new-build projects and re-qualification studies, have not been fully addressed in the current revision of the recommended practice.
To address these gaps, DNV has invited the industry to the joint industry project (JIP) – CO2SafePipe – which intends to investigate the benefits and disadvantages of transporting CO2 in gas phase compared to dense phase, and how the phase chosen impacts the design and operation of both new and repurposed pipelines for CO2 transport. The JIP will further address the potential of increasing the acceptable level of impurities without raising the risk of corrosion and material degradation, thereby extending the applicability range of the running ductile fracture design requirements in DNV-RP-F104, which also includes evaluations of fracture arrestors. A key deliverable will be input to an updated revision of DNV-RP-F104.
Even though the industry has several decades of experience transporting CO2 in dense phase using onshore pipelines, mainly for enhanced oil recovery (EOR), the experience related to offshore pipelines and transporting CO2 originating from a variety of industrial processes is rather limited. CCS is still considered a relatively young industry compared to oil and gas. Safe and cost-effective solutions for both new projects and existing assets are key for the development of a sustainable value chain. As the sector matures and gains experience, keeping the industry standards aligned with the latest knowledge is central to quickly tackle challenges as they arise.
The upcoming CO2SafePipe JIP, which will be managed by DNV, aims to attract a variety of stakeholders including operators, steel manufacturers, EPC and installation contractors, and authorities.
An important decision when designing a new CO2 pipeline system or repurposing an existing one is whether the product will be transported in gaseous or dense phase. The current revision of DNV-RP-F104 focuses on pipelines for dense phase operation, initially with reference to CO2 pipelines currently in operation.
However, even though dense phase may be considered the most attractive option from a pipeline CAPEX perspective, local regulations and safety risk assessments may favour gaseous phase depending on circumstances. For example, gaseous phase is often recommended for CO2 gathering networks in densely populated areas. Further, for typical design pressures for existing onshore gas pipelines, the reuse potential for CO2 transport is mainly limited to gas phase operation.
It is also acknowledged that the criteria for documenting fracture arrest in pipelines also differs between CO2 in gaseous vs dense phase, considering possible variations in CO2 compositions and the effect on the phase envelope and decompression curve.
The JIP’s main aim is to provide the CCS industry with further guidance on the two options, considering pipeline system design, safety, operability, and transport capacity. The update is motivated by several recent projects aiming for gas phase operation, in particular for onshore applications where the considerations, risks and opportunities differ from dense phase.
The requirement to arrest a running ductile fracture is still a concern for both new and existing pipelines. During the last decade, several full-scale fracture arrest tests have been conducted, and the conclusion is that the Battelle Two Curve method (BTCM) as applied for natural gas has been shown to be non-conservative for dense phase CO2 pipelines. Hence, a pipeline transporting CO2 is expected to require a higher fracture toughness and/or thicker wall thickness, or having restrictions with respect to CO2 composition and temperature to control the saturation pressure which governs the driving force for running ductile fractures.
In connection with repurposing existing pipelines for CO2 transport, it is not possible to increase the fracture toughness or wall thickness, so an alternative is to control the CO2 composition and temperature to arrive at acceptable saturation pressure, or to mitigate fracture arrest by using fracture arrestors where required and possible.
Another alternative is to transport the CO2 in gaseous phase. As the gaseous CO2 is often considered similar to natural gas, DNV is exploring whether ductile fractures could be assessed using the same methodology that is used for natural gas. The current revision of DNV-RP-F104 presents design requirements for fracture arrest for CO2 pipelines based on the available fracture arrest tests sources. However, there
are limitations in terms of pipe geometries and line pipe production methods.
In addition, a rather large minimum value of fracture toughness is required. It is therefore considered of great value to extend the applicability range of the design requirements included in the certification, both for design of new pipelines and repurposing existing CO2 pipelines. There are also uncertainties regarding the decompression behaviour in different dense phase CO2 compositions, and theoretical models do not fully capture experimentally observed behaviour. It is therefore of interest to explore if developments improving the discrepancy have been made or, potentially, to explore the use of experimental techniques such as shock tube testing to determine governing decompression behaviour.
Currently, large-scale testing of running ductile fractures typically requires an expensive multi-pipe layout. It would be of interest to explore whether fracture arrests can be robustly documented with reduced or smaller test set-ups. Similarly, DNV are also looking to review the initiatives towards numerical modelling to assess if these could be used as complementary approaches to large-scale testing.
There are no ‘off the shelf’ fracture arrestor solutions available today, so an alternative may be to introduce pipesections with increased resistance to running ductile fracture at certain intervals. It is however not known how such sections should be selected in terms of thickness, strength, and fracture toughness, so it’s an area worth exploring further.
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If free water is present in the CO2 flow, this could lead to significant corrosion rates for carbon-manganese (C-Mn) steel, and selecting a corrosion allowance to mitigate this will not be sufficient. To prevent internal corrosion, therefore, strict requirement to avoid free water across the pipeline system and foreseeable operating condition are essential. Corrosion resistance alloys may be selected for new pipelines but this
Figure 1. DNV’s technology centres provide leading expertise combined with unique testing facilities to determine CO2 pipelines material performance, corrosion resistance, flow measurement strategies, release simulation and process control.
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comes with an increased cost, and is obviously not an option for repurposing existing C-Mn steel pipelines. Further, corrosion risk assessment also needs to consider the effects of the CO2 composition.
The CO2 composition must be controlled to avoid any negative impact on the integrity of the system or the thermodynamic properties. The captured CO2 may contain a range of impurities dependent on the source of the emitters, with the presence of inorganic gaseous impurities such as sulphur and nitrogen, or sulfuric acid increasing the risk of corrosion in the pipeline. The CO2 composition may also affect the system’s thermodynamics – e.g. saturation pressure.
Whilst it is generally preferable to have wider specifications for pipelines, it is worth considering that some of the impurities may become limiting factors, depending on the source of the captured CO2. DNV is leading a major joint industry effort exploring gas specifications – CO2Safe&Sour JIP. The study’s aim is to analyse the most recent research focusing on the effects of gas impurities on corrosion, and investigate the integrity of CO2 pipelines exposed to H2S, water, NOx, SOx, and other impurities as part of CCS operations. Testing is ongoing to quantify the safe operating limits for H2S content and prospective corrosion in the event of upset conditions during operation. There is a strong focus on sulphide stress cracking, corrosion, and chemical reactions.
DNV is committed to supporting the development of metering technologies to measure the amount of CO2 transported in pipelines. This will be done through a DNVled industry effort looking at CO2 in both gas and dense phase. Even if metering is primarily done for fiscal purposes, it becomes more and more apparent that, due to potential phase transformations in CO2, metering is also critical from an integrity point of view. Controlling the flow is essential for pipeline, well and reservoir.
Larger-scale deployment of CCS will likely require new as well as repurposed pipelines to connect emitters to storage facilities. Many inland facilities will also need to be connected to coastal hubs for CO2 export or subsea storage.
Whilst there are a number of knowledge gaps which must be better addressed, including corrosion, fracture and impurity control, and flow assurance and operational issues, the aim of the CO2SafePipe project is to close knowledge gaps identified in the transportation of CO2 in pipelines. This covers CO2 in both gas phase and dense phase, CO2 stream composition, its effect on corrosion and materials, and the risk of running ductile fracture.
The JIP’s outcome will contribute to a safer and more cost-effective design of both new CO2 pipelines and for repurposing existing pipelines.
References
1. www.iea.org/reports/world-energy-outlook-2021
2. www.iea.org/reports/co2-transport-and-storage
3. www.globalccsinstitute.com/ccs-explained-transport
4. www.phase-trans.msm.cam.ac.uk/2005/LINK/175.pdf
5. www.icmt.ohio.edu/documents/publications/8253.pdf
6. MICHAL, G., DAVIS, G., OSTBY, E., LU, C., RONEID, S., ‘CO2Safe-Arrest: A full-scale burst test research program for carbon dioxide pipelines – Part 2: Is the BTCM out of touch with Dense-phase CO2?’, 8thInternationalPipelineConference IPC2018 (2018).
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