September 2026
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CONTENTS September 2026 Volume 31 Number 9 ISSN 1468-9340 03 Comment
33 New era thinking
05 News 08 African petroleum: volatility and opportunity Nancy Yamaguchi, Contributing Editor, explores how turmoil in the Middle East could prove beneficial for African oil developments, notably in expanding export opportunities.
15 Looping the carbon molecule in a lower-carbon future Miro Cavkov, Euro Petroleum Consultants (EPC), explores how refineries and petrochemical plants can adapt existing assets through CCUS to facilitate decarbonisation demands.
19 Establishing a circular carbon economy Corinne Ziege, Nikkiso Clean Energy & Industrial Gases Group, Germany, considers how carbon capture can become a foundational element of a low-carbon economy.
23 Foundations for industrial AI Simon Rogers, KBC (A Yokogawa Company), discusses how physics-based models, AI, and contextualised enterprise data are converging to improve downstream performance and decision-making.
28 Preparing for the future Joseph Doerfler, FS-Elliott, explores how AI infrastructure and renewable energy are reshaping air and gas compression requirements.
Markus Schürmann and Carl Leonhards, Everllence, Germany, consider how developments in syngas compression can impact green ammonia production.
37 Advancing compressor technology Klaus Brun and Karl Wygant, Ebara Elliott Energy, alongside Rainer Kurz, RKSBenergy, discuss technical advancements in control and application for integrally geared compressors.
43 Systems engineering for surge control – part 2 Attilio Brighenti, Christian Casonato, and Alessandro Mafolino, S.A.T.E. (Systems and Advanced Technologies Engineering S.r.l.u.), Italy, consider the side-effects of early design decisions.
47 Beneath the wrap Hani Taan, NanoTech Materials, explores how operators can address corrosion under insulation through preventative measures in downstream facilities.
51 Reliability amid abrasion and corrosion Todd Gerstenberger, ITT Goulds Pumps, explores how early investment in pump design and specification decisions can outweigh upfront savings through reduced maintenance challenges and improved component life.
55 Delayed coker valve advancements Luc Vernhes, Mike Jacobs, and Duke Tran, Velan Inc., explain how innovations in steam purge optimisation and digital integration are helping to advance the reliability and profitability of delayed coker units.
61 Extending sealing performance limits Seema Gangatirkar, Greene Tweed, discusses how metal spring-energised seals deliver improved reliability and performance in extreme environments.
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O
n 12 August, parts of mainland Europe experienced their first total solar eclipse since 1999. Here in the UK, we didn’t experience totality, but the moon did cover up to 95% of the sun in certain regions and, with clear skies, it was quite the spectacle. On the topic of spectacles – there was a shortage of solar eclipse glasses to safely enjoy the celestial event. There were reports of people queuing outside shops for hours to get their hands on a pair; after all, there won’t be a chance to see another near-total solar eclipse on British shores until 2081. But it wasn’t just glasses that were in short supply during the eclipse – the electricity system was under pressure too. The UK’s biggest energy supplier, Octopus Energy, had urged customers to use less electricity during the event to take the strain off the grid, warning that the eclipse would knock out “a huge chunk of Britain’s solar power”, with estimates suggesting that between 300 MW and 1100 MW of solar power could be lost, just as the UK experienced its fifth heatwave of the summer. The issue was not necessarily the reduction in solar output itself, but the speed at which it happened. The National Energy System Operator (NESO) had to be prepared to respond to a rapid change in solar generation that would normally occur much more gradually as the sun sets. According to The Telegraph, NESO paid £6.2 million for additional electricity on the day, including premium rates to gas-fired power plants.1 While solar eclipses are exceptionally rare and entirely predictable events, they do provide a useful glimpse at a bigger challenge: flexibility. As countries add more intermittent renewable generation to their energy mix, they also need to be able to respond quickly to changes in supply and demand. Although solar eclipses may be unusual events, sudden changes in wind conditions, overcast weather, and extreme temperatures are not. This has important implications for energy-intensive industries too. Refineries, gas processing plants, and petrochemical facilities depend on reliable supplies of electricity, steam, fuel, and cooling water to keep their operations running safely and reliably. As the energy system becomes more complex – and as extreme weather events become more common – operators face a twofold challenge: ensuring access to a flexible and reliable energy supply, while also making their own facilities more resilient to changing conditions. This challenge is particularly apparent during periods of extreme heat. Heatwaves and drought have already disrupted refinery operations across parts of Europe this summer, while experts warn that extreme temperatures are likely to become an increasingly persistent problem. There are already concerns that 2027 is likely to be the hottest on record due to a combination of climate change and the strongest El Niño in living memory.2 The solar eclipse offered a brief but highly visible demonstration of the importance of flexibility. However, as the energy transition progresses and weather patterns become more volatile, reliable energy supplies and resilient operations will become increasingly critical to maintaining safe, efficient, and continuous production in the downstream sector. 1. 2.
LEAKE, J., ‘Eclipse pushes Britain’s power bill to £6.2 million’, The Telegraph, (13 August 2026). RICH, B., and POYNTING, M., ‘El Niño set to be ‘strongest in living memory’, says Met Office’, BBC, (21 August 2026).
WORLD NEWS Nigeria | Dangote Refinery secures
US$1 billion backing ahead of planned IPO
T
he planned Initial Public Offering (IPO) of the Dangote Petroleum Refinery & Petrochemicals has taken a significant step forward with the completion of a US$1 billion underwriting programme, strengthening the capital markets foundation for what could become Africa’s most consequential industrial listing. The programme, structured by Marob Strategies and Consulting DIFC Ltd and Lilium Capital Group, comprises a completed and funded US$600 million
private placement and a further US$400 million underwriting commitment in support of the refinery’s planned IPO. The US$600 million private placement has been underwritten and funded by Pan-African Refinery Investment SPV, a subsidiary of Lilium Capital Group. Marob Strategies and Lilium Capital are now coordinating the distribution of the underwriting participation across Global Africa, engaging sovereign wealth funds, governments, institutional investors, and other eligible investors.
Global | IGU report shows a more resilient gas
system faces a more demanding future
T
he global gas system entered 2026 from a position of strength, with natural gas demand reaching a record 4202 billion m3 in 2025, an increase of 69 billion m3 (1.7%), according to the ‘2026 Global Gas Report’ by Snam and International Gas Union (IGU), supported by Rystad Energy. The system has become more diversified, more flexible and significantly more resilient to disruption. However, the report warns that the next challenge will be
ensuring that this resilience keeps pace with a rapidly changing and increasingly demanding global energy system. The findings come as the global energy landscape faces simultaneous pressures from geopolitical disruption, growing electricity demand, extreme weather, expanding LNG trade, the rapid growth of artificial intelligence (AI) and data centres, as well as from the global gas industry’s continuing need to reduce emissions.
Malaysia | Technip
Energies awarded FEED contract
T
echnip Energies has been awarded a front-end engineering design (FEED) contract for the offshore Regasification Terminal (RGT) Yan project in Kedah, northwest Malaysia. The scope includes evaluating best regasification terminal configurations before completing the full FEED for the selected solution, establishing the project’s technical basis, and supporting its progression towards final investment decision (FID). Jointly developed by Gas Malaysia, Tokyo Gas Asia Pte. Ltd, and VTTI, the terminal will have a capacity of 6 million tpy and will comprise an offshore FSRU, marine infrastructure, a subsea gas pipeline, and an onshore receiving facility. This RGT Yan project will introduce a new LNG entry point in the northern region of Peninsular Malaysia, strengthening the resilience and flexibility of the country’s natural gas supply, supporting growing industrial and power demand, and contributing to energy security across the region.
Poland | ORLEN certified for biofuel component production at
Płock refinery
O
RLEN has secured certification under the Oil and Gas Institute’s KZR INiG sustainability scheme for the co-hydrotreatment of bio-based feedstocks at its Płock refinery, Poland. The certification confirms that the renewable feedstocks used by the company and their processing comply with the EU’s requirements. This enables ORLEN to expand the production of biofuel components and count them towards the EU’s renewable energy targets for transport. The company currently has the capacity to process
approximately 100 000 tpy of bio-based feedstocks, with planned upgrades set to increase this to around 150 000 t. “The KZR INiG certification confirms ORLEN’s readiness to further expand the production of biofuel components from renewable feedstocks. By using our existing refinery units, we can increase the share of renewable components in fuels while preparing to meet the requirements of the RED III Directive. This is an important part of the energy transition and of developing a domestic feedstock base for the biofuels sector,”
said Grzegorz Józwiak, Executive Director for Biofuels and Hydrogen at ORLEN. KZR INiG is a certification scheme recognised by the European Commission. It verifies the origin of renewable feedstocks and confirms that the production process meets the applicable EU requirements. The certification allows ORLEN to further develop co-hydrotreatment, whereby bio-based feedstocks are processed alongside conventional fossil streams within existing refinery units. HYDROCARBON
ENGINEERING
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September 2026
WORLD NEWS DIARY DATES 14 - 17 September 2026 Gastech Bangkok, Thailand www.gastechevent.com
20 - 23 September 2026 GPA Midstream Convention San Antonio, Texas, USA www.gpamidstream.org/gpa-midstream-convention
22 - 24 September 2026 Turbomachinery & Pump Symposia Houston, Texas, USA tps.tamu.edu
2 - 5 November 2026
sale of ECS assets to Lummus Technology
S
hell Catalysts & Technologies has sold a number of intellectual property assets and experienced personnel relating to its Environmental Catalysts and Systems (ECS) business to Lummus Technology (Lummus). For Shell Catalysts & Technologies, the divestment supports the ECS business’s continued growth within a complementary environmental solution technology platform.
The ECS business provides advanced systems for emissions control for environmental applications across a broad range of industrial markets. Under the agreement, Shell Catalysts & Technologies will continue to support ECS’s customers during a transition period to help ensure continuity of supply and service.
Australia | Nextchem awarded contract for a
SAF project
ADIPEC Abu Dhabi, UAE www.adipec.com
18 November 2026 Global Hydrogen Conference Virtual www.globalhydrogenreview.com/events/global-hydrogen-conference-2026/
30 November - 3 December 2026 ERTC Madrid, Spain www.worldrefiningassociation.com/event-events/ertc
1 - 3 February 2027 NARTC Houston, Texas, USA worldrefiningassociation.com/event-events/nartc
16 - 19 February 2027 Laurance Reid Gas Conditioning Conference Norman, Oklahoma, USA https://www.ou.edu/pacs/lrgcc
11 - 15 April 2027 AMPP Annual Conference & Expo Columbus, Ohio, USA ace.ampp.org
20 - 22 April 2027 Sulphur World Symposium Vienna, Austria www.sulphurinstitute.org
8 - 10 June 2027 Global Energy Show Canada Calgary, Alberta, Canada www.globalenergyshow.com
September 2026
USA | Shell Catalysts & Technologies agrees
6
HYDROCARBON
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AIRE (MAIRE.MI) has announced that Nextchem, through its subsidiary MyRechemical, has been awarded licensing, Process Design Package (PDP), and engineering services by SKY Renewables Burdekin Pty Ltd, an Australian project development company focused on the production of sustainable aviation fuel (SAF), for the syngas section of Project Lion, in North Queensland’s Burdekin region, Australia.
The project will use locally available sugarcane residues as feedstock to produce purified chemical grade syngas through the application of NX CircularTM Gasification technology. The syngas will then be used for subsequent conversion into SAF and renewable diesel through third-party solutions. Once at full operational scale, Project Lion has the potential to produce up to 125 000 tpy of SAF.
Vietnam | Wood secures contract for
Dung Quat project
W
ood has been awarded a new contract from Binh Son Refining (BSR) to carry out Project Management Consultancy (PMC) services for the Dung Quat Refinery Upgrade and Expansion Project in Vietnam. Following completion of the feasibility study and front-end engineering design (FEED) phases, Wood will manage and supervise delivery of the project on BSR’s behalf – covering design and engineering review, procurement, and contract management, project controls, quality, HSSE, construction management, and commissioning support.
The US$1.5 billion upgrade and expansion will modernise Vietnam’s first oil refinery which is critical to the country’s energy security. Commissioning is scheduled to begin in 2028, with the expansion increasing refining capacity to 171 000 bpd and adding six proprietary technology units which will enable the site to process varying types of crude oil. The upgraded facility will also produce fuels that meet Euro 5 emission standards supporting Vietnam’s environmental objectives and regulatory requirements.
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Nancy Yamaguchi, Contributing Editor, explores how turmoil in the Middle East could prove beneficial for African oil developments, notably in expanding export opportunities.
T
he African continent is the world’s second largest, with the second-largest population. The 54 African countries possess a wide range of natural resources, and their energy strategies vary widely. The recent high prices for oil will boost this year’s revenue and may create opportunities for African producers, but only 21 of the 54 African countries produce oil. Most countries are wholly dependent on imports, and high prices are a burden rather than a boon. In 2025, according to the Energy Institute (EI),1 Africa produced 7.601 million bpd of crude, and African demand was 4.674 million bpd, leaving a rough surplus of 2.927 million bpd. It is possible that expanding Africa’s net oil export capability in the near-term can provide a double benefit: producers can receive additional revenue both from higher prices and from higher volumes as consumers seek alternatives to Middle Eastern oil.
September 2026
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The question of the day is: can market volatility create opportunities for African oil developments when Middle Eastern oil exports are constrained by war? Or does market volatility spill over onto Africa, making investors wary? African crudes command premium prices, partly because of their quality, and partly because they can reach markets in Europe and Asia without traversing the Strait of Hormuz. Is this a temporary situation, or is a structural change underway? This article discusses the African oil sector amidst the current market upheaval.
Current market volatility To briefly summarise current market conditions, on 13 June 2025, Israel launched major airstrikes on Iran, and Iran quickly retaliated. The US entered the conflict on 22 June 2025. Iran quickly responded. A ceasefire paused the fighting but attempts to find diplomatic
solutions failed. On 28 February 2026, the US and Israel launched coordinated strikes against Iran. Iran retaliated against Israeli and US targets. Monthly average spot prices for Brent crude jumped from an average of US$66.60/bbl in January 2026 to US$103.13/bbl in March and US$117.29/bbl in April. The US claimed that the attacks would quickly win the war, but the conflict stretched on. The current year has brought a dizzying array of announcements about the conflict, attempts at diplomacy, ceasefires, and proposed deals. Markets have surged and retreated in response. On 10 June 2026, Iran began blocking the Strait of Hormuz in response to US strikes. On 20 June, Iran announced another closure of the Strait of Hormuz in response to Israeli attacks on Lebanon. Iran had used the threat of Hormuz closure in the past, but this was the first time it carried through with the threat. The International Energy Agency (IEA) notes that approximately 25% of global seaborne oil
trade transits the Strait of Hormuz. The disruption forced the US and Europe to draw down strategic stocks of crude oil and refined products. The IEA announced on 11 March that there would be a coordinated release of 400 million bbl over 120 days, equating to approximately 3.3 million bpd. This was the largest coordinated stock release in the IEA’s history. To date, the drawdowns have not been as severe as possible because of reduced demand and significant reductions in Chinese imports, ostensibly from demand management and employment of its own stockpiles. If the Middle Eastern supplies continue to be constrained, however, strategic stocks will begin to deplete, and supplies could grow tighter. To partially circumvent the Strait of Hormuz, Saudi Arabia has been sending 7 million bpd of crude through its East-West Crude Oil Pipeline (also known as Petroline) to Yanbu, on the Red Sea. Some of the crude is refined there, and some is exported. However, the Houthis in Yemen HYDROCARBON
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September 2026
declared a maritime embargo on Saudi Arabia on 20 July 2026. The Houthis threatened to block the Bab el-Mandeb Strait, which is the southern gateway to the Red Sea. The Houthis are a strong force in Yemen’s civil war. Although they are unlikely to be able to fully close or block the strait for long, the threat caused an increase in shipping rates and insurance charges. If Middle Eastern oil transport costs remain elevated because of risk premia, some African crudes may become more cost competitive. On 18 June, the US and Iran signed a memorandum of understanding (MoU) to end the conflict and reopen the Strait of Hormuz. Iran committed to remove mines and obstacles, and the US agreed to remove its naval blockade. Both sides committed to seek a deal, with a 60-day negotiation window, though there has not been any agreement on difficult issues. On 29 - 30 July, the US launched strikes on Iranian targets. This did not automatically void the ceasefire. The US announced, then cancelled, additional strikes at the beginning of August. There do not appear to be any formally recognised peace negotiations underway as of the time of this writing in early August 2026.
Slumping prices under tariffs reverse to high prices under war It has been four years since Brent spot prices were above US$100/bbl, occasioned by the Russian invasion of Ukraine. The US-Israel-Iran conflict changed that. In April 2026, monthly average spot prices for Brent crude hit a high of US$117.29/bbl. The current year has been so eventful that it is jarring to recall that just last year, there were concerns that oil demand and prices would slump in response to economic uncertainty caused by the US tariff programme. In April 2025, the US administration levied a 10% baseline tariff on nearly all imported goods, with a host of country-specific and sector-specific tariffs.2 Some African countries faced tariffs as high as 30 - 50% (including Mauritius, Madagascar, and Lesotho).
Brent crude spot prices fell to US$64.45/bbl in May 2025. In February 2026, the US Supreme Court invalidated the idea of reciprocal tariffs. The White House then instituted a flat 15% tariff on most imports on 24 February 2026. These tariffs had a 150-day expiration, ending 24 July, but other tariff options remain, affecting African countries. According to the US Census Bureau,3 in 2024, Africa exported approximately US$39.6 billion worth of goods to the US. To compare 2025 with the latest data available in 2026, during the January to May 2025 period, US imports from Africa totalled US$19.75 billion. During the January to May 2026 period, this fell to US$17.633 billion. The tariffs have reduced US imports from Africa, including minerals, clothing, and manufactured goods. The Budget Lab at Yale4 calculates that the total revenue to the US from tariffs is outweighed by negative impacts from inflation, slower GDP growth, and job losses. The US tariffs have already cost African nations billions of dollars. African oil exporters in 2026 will receive a windfall in export revenues, but only five countries reap meaningful benefits: Nigeria, Angola, Libya, Algeria, and Gabon. Most African countries are net importers of oil, and they face higher energy costs and reduced export revenues for their commodities.
African crudes and freight comparisons
Will the Strait of Hormuz ever again be treated as an always-available international waterway? If not, can the world expect a sustained period of higher oil prices, with insurance, potential tolls, and surcharges keeping prices high? This could be an opportunity for African producers hoping to capitalise on undeveloped reserves. Even if the conflict ends soon, it is estimated that it will take six to 12 months to normalise flows and inventories. A ceasefire is not a final peace treaty. The current thinking is that ending the conflict before the end of 2026 will require skilled diplomacy and a firm, lasting ceasefire while negotiations proceed. Therefore, the world must wait until 2027 to see resolution, and hope that peace and regional stability are achieved. African oil producers may therefore be operating under an assumed timeframe of conflict resolution in 2027, with additional time for market normalisation. This is a long time to consumers, but it is a short time to new investors. There are projects underway and firmly planned that will receive a boost from the current disruption. In the mid and longer-term, there may be more development opportunities if Middle Eastern exports continue to be constrained, or if insurance and risk premia remain high, since much African output can reach markets without facing global chokepoints. Freight costs play a huge role in choice of crude oil imports. As a Figure 1. Monthly change in active rigs, Africa and the Middle East, rough guide, a voyage from Nigeria to January 2025 - June 2026. China is 10 500 - 11 500 nautical miles
September 2026 10 HYDROCARBON ENGINEERING
12000
US$100/bbl level in March. At this point, the active rig count took a dramatic turn. Active 10000 rigs in the Middle East dropped to 480 in April 2026, then crept back up slightly to 488 in June 2026. In contrast, Africa’s active 8000 rig count, which had been roughly stable during 2H25, jumped to 120 in June 2026. Figure 1 presents the trend in the active 6000 rig count, indexed with January 2025 serving as 1.0 to compare the relative changes. The active rig count in Africa and the Middle East 4000 declined during 1H25, but Africa’s count rebounded, then rose to 1.19 (in other words, a 19% increase) by June 2026. The rig count 2000 in the Middle East was 0.9 in June 2026, 10% below its level in January 2025. Although the number of active rigs does not predict oil 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 production exactly, the data reveal a great Algeria Angola Egypt Nigeria Other Africa Libya deal about what producers believe. Will Africa be able to continue to Figure 2. African crude production, 2000 - 2025, ‘000 bpd. Source: expand its output, reversing the declines Energy Institute. experienced over the last two decades? Figure 2 presents the trend in African crude production, as reported by EI. Output peaked in 2008 at and can take 30 - 35 days. A voyage from Saudi Arabia 10.221 million bpd. It fell to a low of 7.002 million bpd in 2020, (Ras Tanura) to China via the Strait of Hormuz is during the COVID-19 pandemic. It recovered by 0.6 million bpd 6500 - 7000 nautical miles, taking roughly 20 - 23 days. to reach 7.601 million bpd in 2025. Most forecasts expect flat or Shipping Saudi crude from the Red Sea (Yanbu) to China is a modest growth in 2026 and 2027, but there is upward potential. slightly longer voyage of 6800 - 7800 nautical miles. Many of the peaks and valleys seen in Figure 2 were North African crudes from Algeria, Libya, and Egypt face caused by civil war and continuing strife in Libya. In 2007, Libya simple Mediterranean voyages of 3 - 4 days to European ports. produced 1.837 million bpd of crude oil. In 2011, civil war hit However, reaching Asia relies upon the Suez Canal and the and production plunged to 0.511 million bpd. Production Red Sea, which as noted can be complicated if the became unpredictable as the conflict continued. In 2020, Bab el-Mandeb Strait is threatened. Re-routing these a nationwide ceasefire was negotiated. The country remains crudes through the Mediterranean Sea then around the divided and politically unstable, but oil production has been Cape of Good Hope is impractically long. recovering, and it reached 1.4 million bpd in 2025. Libya’s The closure of the Strait of Hormuz made importers face National Oil Co. (NOC) is aiming for 2.1 million bpd production not only higher costs for crude oil, but it also raised the within the next three to five years. Without a stable question: what happens if the physical flow from the government, Libya would not be considered a secure source Middle East is reduced? Already, Asia imports African crudes of supply to offset unrest in the Middle East. If security for quality and strategic reasons. These imports could grow if conditions improve, however, Libya has ample reserves and African crudes were available at competitive prices. convenient access to Mediterranean refineries. Six African countries are members of OPEC: Nigeria, African crude exports and prospects Algeria, Libya, Republic of the Congo, Gabon, and According to the EI, the Middle East produced Equatorial Guinea. Angola is a former member of OPEC, 31.116 million bpd of oil in 2025, whereas Africa produced having left the group in January 2024. Senegal may join as an 7.601 million bpd. Africa could not supplant the Middle East as observer because of its plans to expand oil and gas the world’s largest oil exporting centre, but it could expand its production. Sudan and South Sudan are allied with OPEC via market presence and prove itself as a swing supplier. In the membership in the Declaration of Cooperation (DOC), also short-term, there is some capability to shift active drilling known as the OPEC+ Group. Despite their experience in the operations. Baker Hughes publishes its Rig Count report each global oil market, their countries suffer from underinvestment. month, with data complete through June 2026 as of the time The national oil companies (NOCs) have often prioritised of this writing. In January 2025, there were 540 active rigs in short-term profits and government revenue rather than the Middle East and 101 active rigs in Africa. In early 2025, the optimal allocation of resources and long-term profitability. US tariffs programme caused an economic downturn. The The NOCs are often strapped for cash, making outside number of active rigs in the Middle East fell to 501 in June, and investment essential, but international oil companies (IOCs) the number in Africa ticked up by one to reach 102. The are cautious. Some of the best fields are now ageing, as is Middle Eastern rig count climbed back to 538 in February 2026, infrastructure. Nigeria, which is Africa’s largest producer, has and Africa’s rig count rose by one more to 103. suffered sabotage, theft, and vandalism along pipeline routes. By the end of February, the US and Israel attacked Iran The current high prices will increase revenue, however, which again, and Iran responded. Oil prices surged past the September 2026 12 HYDROCARBON ENGINEERING
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4500 4000
3500 3000 2500 2000 1500 1000 500 0 1965
1970
1975
1980 1985 1990 1995 W. Africa S. Africa N. Africa
2000 E. Africa
2005 2010 Mid. Africa
2015
2020
Figure 3. Strong growth in African oil demand, 1965 - 2025, ‘000 bpd. Source: Energy Institute. possibly could be used to improve security and encourage additional investment, creating a positive circle. Production growth from new projects is expected in 2028 - 2035. The Ivory Coast, for example, is planning to triple its production from 60 000 bpd to 270 000 bpd in 2027. Namibia is developing deepwater deposits and plans to produce 200 000 - 350 000 bpd during 2030 - 2035. Senegal’s Sangomar field achieved stable output between 2024 - 2026 and is looking to Phase 2 development. If international prices remain high, the scope and schedule of some of these projects may be accelerated. If African output grew by 500 000 - 600 000 bpd, it would be back to the levels seen before the COVID-19 pandemic. Adding 1.0 - 1.5 million bpd would restore it to some of the peaks achieved before the Libyan civil war. This level of growth is technically feasible, with multiple projects having price thresholds in the US$70 - 90/bbl range. African producers are therefore watching the Middle East closely. Spot prices for Brent crude were above US$100/bbl during the March - May period, but the average declined to US$83.76/bbl in July 2026. The US Energy Information Administration (EIA) forecasts that the Brent crude spot price will average US$81.91/bbl in 2026 and US$64.76/bbl in 2027. If negotiations fail to produce a full peace treaty, however, US-Iran tensions could re-escalate and prices could move back into to US$80 - 100/bbl range. This puts Africa in a delicate spot because US$65/bbl prices do not support most deepwater prospects, while US$90 - 100/bbl prices do.
A growing domestic market Over the past year, it seems that market volatility has created opportunities, dashed them away, and then brought them back for another round. Many African countries seek to develop their energy sectors, but investors cherish certainty. Africa has a key advantage, however: a vibrant and growing domestic market. Most of the OECD countries have flat or declining demand, but Africa is a growth market. Energy sector developments need not fully compete as export-oriented enterprises when domestic enterprises require growing amounts of fuel. Indeed, if African oil production does not pick up, the continent’s net export capability will begin to dwindle as local demand begins to catch up with supply. September 2026 14 HYDROCARBON ENGINEERING
2025
Figure 3 illustrates the long term-trend in oil demand for African regions. The EI notes that African oil demand grew at the robust rate of 1.3% per year during the decade 2015 - 2025. In 2015, African oil demand was 4.107 million bpd. This grew to 4.674 million bpd in 2025. The COVID-19 pandemic caused demand to collapse to 3.843 million bpd in 2020, but the recovery has been strong. According to the EI, Africa’s oil demand grew 3.8% between 2024 and 2025, the fastest of all major world markets. International agencies including the EIA and IEA forecast that Africa will be a modest-growth market, adding 0.1 - 0.13 million bpd of new demand annually. The African Energy Chamber (AEC)5 is far more bullish, expecting 0.4 million bpd per year of new demand. AEC points to rapid population growth (reaching 2.4 billion), rapid urbanisation, rising vehicle ownership, restoration and growth in aviation, and growth in industrialisation and mining.
Conclusion: African opportunity African oil production peaked at approximately 10 - 10.2 million bpd during the years 2007 - 2010. Thereafter, Libya slid into civil war, and oilfields in other key countries began to age. Africa has never returned to its peak level of production, but it could. The US-Israel-Iran war has not only strengthened prices, but it has also forced the world to experience the ‘what if’ scenario regarding the Strait of Hormuz, and to a lesser extent, the Bab el-Mandeb Strait. Most African supplies do not transit global chokepoints. High-quality African crudes are already a part of the refiner diet in Europe and Asia, and they could grow in importance. Volatility creates opportunity, but it also tends to stifle investment. Many oil companies in Africa were unable to properly maintain existing assets and invest in longer-term development. Governments often failed to provide the type of political stability, support infrastructure, and security to attract and keep investment by international oil companies. Regardless of the current conflict, Africa’s governments and oil companies should hope to solve these stubborn problems, and this may be a time of opportunity. A prolonged regime of high oil prices would help mainly the oil-rich African countries, and most of Africa is import dependent. Still, if Africa’s oil-producing countries manage to create the conditions that foster hydrocarbon development and investment (such as government stability, rule of law, infrastructure repair and security,) it is likely that these improvements would flow into other sectors of the economy. One success could build upon another. The ingredients are there: Africa has a significant resource base. It has access to international markets. It has a large and growing population, providing a market for energy products and other commodities, serving as the human resource essential to any long-term prosperity.
References 1. 2. 3. 4. 5.
www.energyinst.org › statistical-review hts.usitc.gov www.census.gov www.budgetlab.yale.edu energychamber.org
Miro Cavkov, Euro Petroleum Consultants (EPC), explores how refineries and petrochemical plants can adapt existing assets through CCUS to facilitate decarbonisation demands.
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or refiners, the appeal of carbon capture, utilisation, and storage (CCUS) lies less in ideology than in engineering pragmatism. It offers a way to keep capital-intensive assets running reliably, extend the operating life of process units, and improve production economics, while progressively lowering the carbon
intensity of the feedstock. Rather than displacing existing infrastructure, CCUS works with it: hydrogen plants, fired heaters, FCC units, and utility systems all become candidates for integration into a carbon management strategy. The result is a practical decarbonisation pathway built on the idea of preserving the carbon molecule rather than
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discarding it, capturing CO2 before it reaches the atmosphere, and either storing it permanently underground or routing it back into industrial value chains as a feedstock. As policy frameworks evolve and capital markets place greater weight on emissions performance, CCUS is increasingly the technology that lets refiners protect both their assets and their licence to operate.
Inside the refinery: where the carbon comes from Any serious CCUS strategy has to start with an honest accounting of where CO2 is actually generated across a refinery’s process units. The major sources are well known to operators, but each presents a different capture challenge in terms of CO 2 concentration, flue gas volume, pressure, and temperature: n Hydrogen plants: steam methane reformers (SMRs) and autothermal reformers (ATRs) produce concentrated, high-pressure CO2 streams that are comparatively straightforward to capture, making hydrogen production one of the most attractive entry points for CCUS. n FCC regenerators: fluid catalytic cracker regenerators emit large volumes of dilute flue gas, a more difficult but high-value target given the scale of emissions involved. n Fired heaters and boilers: distributed across the site, these combustion sources contribute a significant share of total refinery CO2 but typically operate at low concentration and atmospheric pressure, complicating capture economics. n Delayed cokers: coking operations generate CO2 both from combustion and from the coke itself, adding a process-specific emissions profile that requires tailored capture approaches. n Utilities and cogeneration units: steam and power generation assets, often running continuously, represent a stable and substantial emissions source well suited to centralised capture.
SMR or ATR process flow, where CO2 is removed from a more concentrated, higher-pressure stream before the hydrogen is used downstream, an approach central to blue hydrogen production. n Membrane separation: offers a lower-energy alternative for certain process streams, using selective permeability to separate CO2 from other gases, with growing interest for retrofit applications where footprint is constrained. n Cryogenic separation: exploits the differing boiling points of CO2 and other gas components, particularly attractive for high-purity CO2 streams destined for utilisation rather than storage. n Emerging solid sorbent systems: still scaling towards commercial deployment, these solid-state materials promise lower regeneration energy than conventional amines and are being piloted across a range of industrial sources. No single technology fits every source. Matching capture method to stream characteristics, and sequencing investment accordingly, is increasingly central to how refiners build out their CCUS roadmaps.
Blue hydrogen: capture built into existing assets
Mapping these sources is the first step towards prioritising where capture investment will deliver the greatest return, both in terms of tonnes of CO 2 abated and in compatibility with existing plant layout.
Hydrogen production remains the clearest near-term opportunity. For decades, refineries have relied on SMR units to supply hydrogen for hydroprocessing, desulfurisation, and other hydrogen-addition reactions, a process that has traditionally generated significant volumes of CO2 and produced what is commonly termed grey hydrogen. Integrating pre-combustion capture into these units shifts that output to blue hydrogen, without requiring refiners to abandon assets they have already paid for. The operational case is as compelling as the environmental one. Retrofitting capture onto reformers, crackers, and associated pre-heat trains extends the useful life of CAPEX-heavy equipment, allowing it to keep operating at high reliability while meeting tightening emissions requirements. For plant operators, that combination of continuity and compliance is the practical argument for capture investment, well before policy incentives enter the conversation.
Capture technologies maturing for refinery service
CCUS as an extension of existing refinery infrastructure
The technology landscape for capturing this CO2 has matured considerably, and refiners now have several proven and emerging options to match against their specific source profiles: n Amine-based post-combustion capture: the most commercially established route, using chemical solvents to strip CO2 from flue gas after combustion. It is well suited to fired heaters, boilers, and FCC flue gas, though solvent regeneration is energy-intensive. n Pre-combustion capture from hydrogen units: applied upstream of combustion, typically within
Unlike many decarbonisation pathways that demand wholesale replacement of industrial infrastructure, CCUS allows refiners to build on what they already have. SMRs, process heaters, utility systems, hydrogen networks, and petrochemical complexes can all be folded into a broader carbon management strategy without requiring a clean-sheet redesign of the site. This matters because it changes the investment calculus: rather than competing for capital against entirely new technology platforms, CCUS competes on the basis of incremental modification to assets that are already generating revenue. Operators can continue
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extracting value from capital-intensive units while progressively reducing their carbon footprint, a far more attractive proposition for boards and investors than a full asset transition.
Refineries as future carbon management hubs This logic extends beyond a single site. Refiners already possess much of the capability base required for large scale carbon management: hydrogen production units, utility systems, storage and pipeline infrastructure, process integration expertise, and experienced operating personnel accustomed to handling high-pressure gas streams safely. Few other industrial sectors combine all of these capabilities under one roof. That positions refineries to evolve into regional carbon management hubs, serving not only their own emissions sources but also third-party industrial emitters nearby who lack the scale or expertise to build standalone capture infrastructure. Several European projects are already exploring this model, connecting hydrogen reformers, power plants, and petrochemical sites to shared CO2 pipeline networks and storage basins in the North Sea. For refiners, hosting third-party CO 2 streams creates a new revenue line built on infrastructure they already understand how to operate.
From capture to value: utilisation pathways Captured CO2 need not be destined solely for geological storage. When paired with renewable hydrogen, it becomes a feedstock for synthetic hydrocarbons, opening a route into sustainable aviation fuel (SAF), low-carbon transport fuels, chemicals, polymers, and even construction materials. Methanol production is one of the more established entry points: CO2 and hydrogen react over a catalyst via the Fischer-Tropsch process to yield liquid hydrocarbons, after which refiners can apply well-established downstream conversion routes to produce renewable fuels and chemicals. Alcohol-to-jet and methanol-to-jet pathways are advancing in parallel, giving refiners multiple routes to convert captured carbon into products that satisfy rising SAF mandates rather than simply offsetting emissions on paper. These utilisation pathways also let refiners diversify their product slate, an increasingly relevant consideration as demand patterns for conventional fuels shift over the coming decades.
Cost, infrastructure, and the path to scale None of this is without friction. The Intergovernmental Panel on Climate Change (IPCC) has estimated that the world will need to remove up to 10 billion tpy of CO2 to stay on track for net zero by 2050, and direct air capture and industrial point-source capture both sit within that broader portfolio. Cost remains the dominant constraint: end-to-end direct air capture currently runs between roughly US$600 - 1000/t of CO2 depending on the region, far above what most September 2026 18 HYDROCARBON ENGINEERING
industrial emitters can absorb. Bringing that figure below US$200/t, and ideally closer to US$100/t, is widely seen as the threshold for mainstream commercial viability, a trajectory not unlike the cost curve solar power followed over the last four decades. Refinery clusters offer one of the more cost-effective routes to get there. By sharing capture, compression, and transport infrastructure across multiple emitters on a single industrial site or regional network, the per tonne cost of abatement falls significantly compared with standalone capture projects. Financial mechanisms are evolving alongside the engineering: carbon trading systems such as the EU Emissions Trading Scheme give refiners a liquid market in which to hedge carbon price exposure or monetise captured CO2 through verified credits, while Carbon Contracts for Difference and targeted tax incentives are helping close the remaining cost gap.
Policy and collaboration: the enabling framework Technology and shared infrastructure can only go so far without consistent regulatory support. Differing rules across borders on carbon accounting, storage permitting, and credit recognition create real risk for investors weighing multi-year capture projects, and industry stakeholders have been consistent in calling for clearer, longer-term policy signals and cross-border standardisation. ESG-linked capital allocation is reinforcing this pressure from the investor side, rewarding companies that can demonstrate measurable, auditable emissions reductions rather than aspirational targets. None of this can be delivered by any single party. Refiners bring operational experience and existing infrastructure; technology providers bring capture, compression, and digital monitoring solutions; governments and policymakers bring the financing frameworks and regulatory certainty that make long-duration projects investable. Digital tools, including process simulation, digital twins, and predictive analytics, are increasingly the connective layer between these groups, letting operators track CO2 flows in real time and providing investors and regulators with verifiable performance data that they can rely on.
Conclusion The molecules moving through a refinery are not changing. What is changing is how they are processed, captured, accounted for, and in many cases reused, rather than released. By building CCUS onto the hydrogen units, fired heaters, utility systems, and process infrastructure refiners already operate, the downstream sector has a route to material decarbonisation that does not require abandoning the assets that generate its returns. The technology is proven – what remains is the work of scaling it, cluster by cluster, through the kind of collaboration between refiners, technology providers, and regulators that turns engineering capability into industrial reality.
Corinne Ziege, Nikkiso Clean Energy & Industrial Gases Group, Germany, considers how carbon capture can become a foundational element of a low-carbon economy.
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he path to net zero is often described as a transition away from fossil fuels toward renewable energy. While renewable power deployment remains critical for base load capability, achieving net zero requires a broader transformation of the energy system itself. Carbon dioxide remains embedded within energy infrastructure, industrial processes, and supply chains, making carbon management an essential component of long-term decarbonisation. As industries seek to reduce emissions while maintaining energy security and operational reliability, a new perspective is
emerging: carbon should no longer be viewed solely as waste. Instead, carbon must become a managed resource that can be captured, purified, reused, and integrated into circular energy systems. From this perspective, carbon capture is not a niche technology or a temporary bridge, instead it is a foundational element of a future low-carbon economy. This principle presents the opportunity for technology and equipment providers to close both the energy loop and the carbon loop. Decarbonisation alone is not enough; the energy transition must also create pathways for circularity,
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enabling carbon and energy resources to remain productive within the economy rather than being released into the atmosphere.
Closing the carbon loop through Power-to-X One of the clearest examples of circular carbon utilisation can be found in Power-to-X technologies. Processes such as methanation use captured carbon dioxide and renewable hydrogen to produce synthetic methane; while emerging sustainable aviation fuel (SAF) pathways increasingly rely on captured carbon as a feedstock. These technologies demonstrate how carbon capture can enable renewable energy storage, fuel production, and emissions reduction simultaneously. In these applications, carbon dioxide becomes a valuable raw material rather than an unwanted by-product. The ability to recover, purify, and condition CO2 therefore becomes a critical enabler of future clean-energy systems.
Decentralisation is changing the carbon capture landscape At the same time, energy systems are becoming increasingly decentralised. Driven by energy security concerns, geopolitical developments, and the need for resilient infrastructure,
energy production is shifting towards localised and distributed assets. This trend can already be seen across biomethane facilities, waste-to-energy plants, distributed hydrogen production systems, geothermal resources, and natural gas-fired generation supporting grid stability. While decentralisation improves system resilience, it introduces a significant challenge for emissions management. Historically, carbon capture focused on a limited number of large industrial emission sources. Future energy systems will generate emissions across a much larger number of smaller, geographically dispersed facilities. This creates what might be called the decentralisation paradox: energy production becomes more local and resilient, while emissions management becomes more complex. For this reason, retrofit and bolt-on carbon capture solutions are becoming increasingly important. Scalable carbon capture technologies allow operators to: n Decarbonise existing assets without replacing entire facilities. n Deploy solutions across distributed emission sources. n Adapt to varying operating conditions. n Create additional revenue streams through CO2 recovery and utilisation. In many cases, retrofit carbon capture may represent the most practical pathway for accelerating near-term decarbonisation while preserving existing infrastructure investments.
Transforming carbon dioxide from cost to value
Figure 1. Decentralised small scale LNG liquefaction.
Figure 2. Containerised bolt-on liquid CO2 plant for a biogas plant.
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The economics of carbon capture are evolving alongside the technology. As carbon pricing mechanisms expand globally, emissions increasingly carry a measurable financial cost. Simultaneously, demand for high-purity carbon dioxide continues to grow across food and beverage production, healthcare, manufacturing, chemicals processing, and electronics industries. This shift is changing the role of captured carbon. Rather than representing solely a compliance obligation, CO2 is becoming a tradable product with commercial value. High-purity carbon dioxide can command significantly higher market values than the costs traditionally associated with emissions management, creating opportunities to monetise captured carbon streams. However, realising this value requires more than simply separating carbon dioxide from a process stream. The purity of recovered CO2 is often the defining factor that determines its commercial viability. Applications such as beverage carbonation, food processing, and medical use require carbon dioxide with purity levels approaching 99.9%, while semiconductor manufacturing and advanced industrial processes may demand purities of 99.9999% or greater. Contaminants including sulfur compounds, oxygen, hydrocarbons, moisture, and trace substances must be carefully controlled to meet market requirements and protect downstream processes. As a result, purification technology is becoming a critical component of the carbon capture value chain.
Process improvement is ensuring plant availability while ensuring compliance. In the oil and gas industry, ensuring highest safety and plant availability is crucial, while achieving decarbonization goals has also become a critical imperative. Our comprehensive portfolio and expertise enable process improvements that increase operational reliability and move us towards net zero targets.
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Recent developments in advanced carbon sorbent preparation techniques have shown promising results. By modifying sorbent surface chemistry, it is possible to reduce interactions with polar gases such as water vapour and carbon dioxide while improving selectivity toward heavy noble gases. These advances support the production of higher-purity carbon dioxide streams suitable for industrial reuse and commercialisation. More broadly, they demonstrate that carbon capture and purification technologies can operate successfully in decentralised and highly variable energy environments.
Carbon capture as a system enabler
Figure 3. Amine washing system for off gas treatment and CO2 capture for industrial decarbonisation. As carbon dioxide increasingly transitions from a regulated emission to a valuable industrial resource, purification requirements are becoming a key driver in the design of carbon capture systems. Compliance with internationally recognised standards, such as EIGA and ISBT, is an important consideration in developing solutions capable of supporting high-value CO2 utilisation pathways.
Geothermal energy: a real-world carbon capture challenge A practical example of these challenges can be found in geothermal energy systems. Although geothermal power is widely recognised as a renewable energy source, geothermal gas streams often contain significant concentrations of carbon dioxide alongside water vapour, nitrogen, and other trace components. These characteristics create a complex operating environment for gas treatment and purification technologies. For organisations seeking to maximise the value of recovered carbon dioxide, addressing these impurities with advanced gas treatment technologies specifically designed for CO2-rich environments becomes essential. Experimental systems tested under geothermal conditions have demonstrated continuous carbon dioxide purification under industrially relevant operating parameters. These systems are designed to operate across a broad range of temperatures and pressures, reflecting the realities of geothermal energy production and other demanding industrial applications. In addition to conventional contaminants, geothermal gas streams may contain naturally occurring radioactive species, such as radon. While present only at trace concentrations, radon can prevent captured CO2 from being used in food, beverage, medical, or semiconductor applications if not effectively removed. Unlike conventional gas purification challenges, radon exists at extremely low concentrations within gas streams dominated by carbon dioxide and water vapour. Effective removal therefore requires highly selective adsorption materials capable of targeting heavy noble gases while minimising competitive adsorption effects. September 2026 22 HYDROCARBON ENGINEERING
The geothermal example illustrates a broader lesson for the energy transition. Carbon capture should not be viewed as a standalone emissions-control technology. Instead, it is increasingly becoming a system-level enabler that connects energy production, industrial operations, and carbon utilisation pathways. Future decentralised energy facilities may integrate: n Renewable energy generation. n Carbon capture and conditioning systems. n Advanced contaminant removal technologies. n Carbon utilisation and commercialisation pathways. In this model, captured carbon dioxide becomes an asset capable of supporting food and beverage production, industrial manufacturing, healthcare applications, synthetic fuels, and future Power-to-X pathways. The result is a more circular energy system in which carbon remains productive rather than being discarded.
Closing the loop of decarbonisation and utilisation of CO2
While carbon utilisation opportunities continue to expand, industrial sectors remain the primary drivers of carbon capture deployment. Cement, steel, refining, chemicals, and other hard-to-abate industries face emissions that are fundamentally linked to their production processes. In many cases, carbon capture represents one of the few viable routes to deep decarbonisation. At the same time, decentralised energy systems are providing new opportunities to deploy carbon capture closer to the point of emission and closer to potential utilisation markets. The next phase of the energy transition will therefore require more than reducing emissions. It will require managing carbon as a resource across industrial and energy systems. For technology providers, industrial operators, and policymakers alike, the challenge is clear: build the infrastructure and technologies necessary to capture, purify, transport, utilise, and store carbon at scale. By combining carbon recovery, purification, and utilisation pathways, industries can transform emissions from a regulatory burden into an economic opportunity. Net zero will ultimately depend not only on reducing carbon emissions, but on creating systems capable of managing carbon responsibly and productively. The future belongs to organisations that can successfully close both the energy loop and the carbon loop.
Simon Rogers, KBC (A Yokogawa Company), discusses how physics-based models, AI, and contextualised enterprise data are converging to improve downstream performance and decision-making.
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he question is no longer whether refineries will adopt industrial AI, but whether they can trust AI to support safe, operationally sound decisions worth millions of dollars each day. As AI becomes increasingly embedded across refinery operations, its effectiveness depends on more than algorithms alone. It requires physics-based engineering models, live operational data, and the operational context needed to keep decisions aligned with changing plant conditions. Process twins provide that foundation by transforming raw data into decision support that improves optimisation and enables progressively more autonomous operations. This article explores how process twins and digital-thread architectures are enabling the next generation of industrial AI.
Building the digital foundation Refineries already possess large amounts of operational and engineering data. The challenge is using that data to support coordinated, trusted decision-making across complex industrial environments. As refinery systems become interconnected and data rich, operators must maintain safe operations while balancing performance and sustainability objectives. Industrial AI adoption now spans the refinery enterprise, increasing both the volume of available insight and the complexity of maintaining the models. The challenge centres on keeping engineering models, planning systems, and live plant conditions synchronised
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as AI-driven decision-making expands. In many facilities, separate versions of the same process model evolve independently across planning, engineering, optimisation, and monitoring teams. Over time, this increases maintenance complexity and inconsistencies between operational and planning environments. The process twin extends beyond dashboards and visualisation layers. It maintains alignment between engineering models and changing plant conditions rather than relying on disconnected dashboards or black-box analytics. AI without a trusted operational twin offers interesting analytics. AI with a process twin becomes industrial decision support.
Grounding industrial AI Industrial AI systems must operate within physical constraints and refinery objectives. Decisions must be explainable, and grounded in engineering reality beyond pattern recognition alone. Process twins support real-time monitoring, anomaly detection, what-if simulation, model assurance, drift tracking, and real-time optimisation to provide a practical bridge
between physics and AI. Model health scoring and calibration monitoring further support operational alignment over time, as shown in Figure 1. In hydrocarbons, AI scales when grounded in physics, governed by logic, and connected to live operational context. AI models trained outside engineering environments may identify correlations whilst struggling to explain process constraints, operational risk, or downstream impacts.
Connecting the intelligence layer Modern refinery process twins are evolving beyond standalone engineering tools into continuously connected systems integrated with operations, maintenance, engineering, and planning data. The twin functions as an operational intelligence layer that maintains continuity between plant performance and planning workflows. It provides secure, scalable cloud execution of simulation models across operational and planning environments. Operationalising process twins requires automated data management and governance processes capable of sustaining alignment between plant conditions and model predictions. Process twins become valuable when they evolve from isolated engineering models into governed systems of enterprise-connected operational intelligence.
Advancing refinery optimisation
Figure 1. Simulation health scoring helps maintain alignment between process twin models and live plant conditions.
Figure 2. Process twin workflows continuously compare plant conditions against simulation models.
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In one refinery implementation, continuous synchronisation between simulation models and linear programming (LP) planning reduced LP model update cycles from approximately two weeks to two days. The approach also improved alignment between planning predictions and actual operating conditions. Engineers also gained a more quantitative basis for recalibration, reducing repetitive analysis and supporting more responsive planning workflows. As part of a broader LP upgrade initiative, improved LP planning delivered sustainable benefits of US$2 - 3 million/yr. Why does the ‘plan vs actual’ gap persist despite decades of refinery optimisation investment? Process twins reduce this gap by continuously synchronising plant conditions, simulation models, and planning environments. Figure 2 illustrates how synchronised process twins support planning and operational alignment. What-if decision support allows teams to investigate
operational changes, assess process constraints, and evaluate optimisation opportunities within a continuously updated operational environment. Optimisation supports alignment between planning objectives with operational execution. Simulation and operational data can be combined to support yield improvement, energy optimisation, and process reliability across refinery operations. As process twins expand beyond traditional engineering workflows, the challenge shifts from simulation accuracy to connecting knowledge across the enterprise.
Figure 3. Digital-thread architectures provide a single source of truth.
Connecting the digital thread What happens when critical refinery knowledge remains trapped in disconnected islands across historians, laboratory systems, planning tools, maintenance platforms, engineering systems, and departmental workflows? A process twin becomes far more valuable when connected to a semantic layer that links engineering and operational Figure 4. Centralised visibility into process twin calibration and refinery data into a shared asset context. The model health. semantic layer describes asset hierarchies, standardised data structures, and ontologies to form an asset knowledge graph. Integrating refinery functions Industry standards such as ISO 15926, ISO 14224, and A process twin becomes more valuable when it operates as a ISO/IEC 81346 support structured asset hierarchies, equipment shared decision layer across engineering, operations, relationships, and lifecycle data management across industrial maintenance, and planning rather than as one simulation tool operations. Together, these standards help establish the digital used by a small group of specialists. Figure 4 shows how shared thread required to connect simulation models, plant data, and dashboards extend visibility beyond engineering teams into enterprise workflows across the refinery. broader operational workflows. As shown in Figure 3, digital thread architectures integrate Automated workflows compare live plant measurements simulation, plant data, and AI orchestration into a connected against simulated and planning-model predictions using refinery framework. reconciled historian and laboratory data. These systems AI is most effective when grounded in engineering context support model assurance and KPI monitoring across refining rather than operating independently of it. In refinery and petrochemical operations. environments, AI supports model calibration, anomaly Planning and scheduling functions become more closely detection, and prescriptive analytics while remaining grounded aligned with operational reality as planning assumptions, in physics-based process understanding. process simulations, and optimisation activities operate within The architecture resembles a refinery knowledge system in the same coordinated framework. which: The real value emerges when the process twin transforms n Simulation models provide process understanding. from a specialist tool into a shared decision layer across n Plant data reflects current operating conditions. functions. n Orchestration layers manage workflows and As these systems mature, the role of the process twin synchronisation. expands beyond visibility and monitoring toward broader n AI systems assist with interpretation, prioritisation, and coordination and decision support. decision support.
Advancing toward autonomy
As process twins mature, the strategic differentiator becomes the refinery’s ability to connect knowledge, workflows, and decision-making into a shared refinery context. The ontology does not replace the twin; it gives the twin enterprise context.
The next stage moves toward more automated and closed-loop optimisation environments. In these environments, process twins continuously compare actual vs predicted performance to support optimisation recommendations. HYDROCARBON 25
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Progress toward supervised autonomy will involve AI systems coordinating activities across engineering, operations, and planning using contextualised twin data. In practice, AI will perform more of the analytical ‘heavy lifting’ while humans supervise. Several industry roadmaps position industrial AI as an evolution from monitoring and advisory systems towards more autonomous refinery coordination. The future centres on hybrid refinery environments where AI enhances engineering expertise and continuously calibrates physics-based simulation. The objective is AI operating within engineering constraints defined by simulation, thermodynamics, and continuously validated plant data. This becomes particularly important in hydrocarbon operations where governance, explainability, cybersecurity, and auditability become foundational requirements rather than optional features. Progression toward autonomy will likely occur in the following phases: n Monitoring and visibility. n Diagnostics and recommendations. n Closed-loop optimisation. n Supervised autonomous operations. Autonomous operations will emerge from AI operating on top of a process twin and a well-contextualised knowledge layer.
Building the operational foundation The most successful deployments typically follow a phased approach focused on measurable outcomes rather than full enterprise transformation. n Start with a high-value operational asset or network segment: focus on high-value refinery units, networks, or processes where improvements in reliability, energy efficiency, yield, planning alignment, or maintenance performance generate measurable value. n Establish the twin with live-data connectivity: a process twin becomes valuable only when synchronised with live plant data, operational systems, and engineering workflows. This synchronisation supports monitoring, drift detection, and scenario analysis using updated plant data. n Add contextualisation through an asset model, ontology, or knowledge graph: many refineries begin with a minimum viable contextualisation layer connecting plant data, engineering models, workflows, and asset structures before expanding into broader enterprise integration. Digital-thread architectures connect simulation models, operational data, and enterprise applications into a unified refinery environment. n Embed outputs into operations, maintenance, and planning workflows: long-term value emerges when process twin insights become integrated into day-to-day refinery workflows. These workflows increasingly incorporate dashboarding, optimisation support, and automated model execution. n Introduce AI incrementally: AI is most effective as an enhancement layer built on process twin infrastructure. The most effective implementations treat industrial AI as a gradual transformation built on trusted data, validated engineering models, and connected refinery systems. September 2026 26 HYDROCARBON ENGINEERING
These implementation steps also establish the foundation required for more advanced AI-enabled coordination and progressively autonomous refinery systems.
Scaling industrial AI What does industrial AI actually look like inside a continuously operating refinery environment? Industrial AI in hydrocarbons is evolving from isolated analytics toward connected industrial systems built on simulation, plant data, and AI-assisted workflows. Industry strategies point toward hybrid modelling, automated optimisation, and more autonomous operations. One internal study demonstrated how digitalisation initiatives increased data utilisation from approximately 10% to more than 50% through automated ingestion, cloud analytics, and connected AI-enabled workflows. Deloitte’s 2026 oil and gas outlook projects AI and GenAI spending to grow from less than 20% of IT spending today to more than 50% by 2029, with major applications focused on process optimisation, integrated operations, asset performance, and environmental management.1 Hybrid refinery environments increasingly combine first-principles simulation with AI-driven calibration and prediction to maintain model accuracy under changing operating conditions. The long-term direction is a continuously integrated refinery environment where simulation, plant data, workflow orchestration, and AI operate together within a shared digital architecture. The future of industrial AI will depend less on algorithms alone and more on operational twins capable of connecting live plant data, first-principles engineering models, and enterprise context into industrial decision support.
Conclusion In complex refining and petrochemical operations, AI requires operational context, engineering constraints, and continuously validated plant understanding to support trusted decision-making. Process twins provide that operational foundation. They represent the practical bridge between engineering-grade models, live operations, enterprise data, and AI-enabled decisions. By combining first-principles engineering models with live data, contextualised enterprise information, and industrial workflows, process twins enable refiners to move beyond monitoring towards optimisation, coordinated decision support, and progressively more autonomous operations. The strategic opportunity is not simply deploying more AI, but creating refineries where engineering knowledge, simulation, plant data, and enterprise systems talk together within an integrated refinery environment. Refineries already possess large amounts of data. The competitive advantage will belong to operators capable of transforming this information into coordinated, trusted industrial decision support through connected process twins.
Reference 1.
https://www.deloitte.com/us/en/insights/industry/oil-and-gas/oil-andgas-industry-outlook.html
A Yokogawa Company
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Joseph Doerfler, FS-Elliott, explores how AI infrastructure and renewable energy are reshaping air and gas compression requirements.
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rtificial intelligence (AI) is driving one of the largest increases in industrial power demand in modern history. Data centres are consuming more electricity than ever before, and the pace of expansion is accelerating across North America, Europe, and Asia. AI-focused facilities are expected to more than triple their energy consumption by 2030, placing increasing pressure on electrical grids, utility providers, and industrial power systems. For the compression industry, AI growth is driving real changes in how power is produced and how industrial facilities are designed and operated. While centrifugal compressors may not be the first technology associated with AI, they play a critical role behind the scenes in many of the processes supporting large scale computing demand. From natural gas turbines and semiconductor fabrication to industrial gas production and cleanroom operations, reliable compressed air and
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gas compression have become increasingly important as AI-related investment continues to accelerate worldwide. As this demand grows, compressors are being pushed to operate with greater efficiency, operational flexibility, visibility, and performance consistency than ever before. These changing requirements are influencing how manufacturers engineer, monitor, and support centrifugal compressors throughout their operating life.
On-site generation and fuel gas compression Due to pressure on electrical grids and utility providers, developers in many regions face multi-year delays in electrical grid interconnections, creating significant challenges for facilities that require immediate, reliable power. To reduce these deployment delays and improve
energy resiliency, many operators are investing in dedicated on-site power generation. Across the US, large natural gas turbine installations are being developed to meet growing AI computing demand and the expanding power requirements of these facilities. These operations depend on fuel gas booster compressors to increase incoming pipeline gas pressure to levels suitable for turbine operation. Modern gas turbines often require fuel gas pressures between 400 and 650 psi, significantly above standard distribution pipeline pressures. When the available supply pressure is insufficient, fuel gas compression becomes essential to maintaining stable turbine operation and overall power reliability. This shift is increasing demand for compressor technologies capable of supporting continuous operation under changing load conditions while maintaining high efficiency and dependable
performance. In these environments, operators are prioritising equipment that offers: n Long-term operational reliability. n Reduced maintenance requirements. n Smooth, pulse-free gas delivery. n Stable performance under variable demand conditions. n Oil-free compression capability. FS-Elliott’s centrifugal compressors are engineered-to-order machines purpose-built for each customer’s gas service and operating conditions. Process gas applications demand careful alignment of aerodynamic design, metallurgy, and sealing systems to the specific properties of the gas being compressed, which makes a fully engineered approach essential rather than optional. As additional on-site power generation projects move forward through 2026 and HYDROCARBON 29
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beyond, demand for fuel gas compression solutions designed for reliability, operational flexibility, and long-term performance is expected to continue growing alongside expanding AI computing capacity.
Semiconductor manufacturing and industrial gas demand Growth in computing capacity is fuelling parallel investment in semiconductor production and industrial gas manufacturing. Every advanced AI processing chip begins its life inside a semiconductor fabrication facility, where compressed air and industrial gases support highly controlled manufacturing processes. These facilities rely heavily on gases such as nitrogen, oxygen, and argon for inerting, oxidation, plasma processes, and cleanroom operations, which require large scale air separation systems powered by centrifugal compressors. Main air and booster compressors play a critical role in maintaining stable operation throughout the process. Plant and instrument air systems supporting these highly controlled environments also require reliable oil-free compressed air, where contamination control is essential to maintaining product quality and process stability. Global investments in semiconductor manufacturing continue to accelerate through government initiatives and private-sector expansion projects. In the US alone, new fabrication facilities are being developed at a pace not seen in decades, increasing demand for main and booster air compressors, plant air and instrument systems, and industrial gas compression. These applications demand extremely high levels of uptime, process stability, and air purity. Semiconductor manufacturing environments operate continuously, and unplanned downtime can result in substantial production losses. FS-Elliott has manufactured centrifugal compressors delivering ISO 8573-1 Class 0 oil-free air for decades in industries where air purity, contamination control, and dependable operation are critical to production. The company’s experience supporting industrial gas production, air separation, and process air applications positions it well for continued growth tied to semiconductor manufacturing and the expansion of digital infrastructure.
Figure 1. FS-Elliott PAP Plus compressor supporting API 617/672 process applications.
September 2026 30 HYDROCARBON ENGINEERING
Renewable integration and dynamic operating conditions The growth of AI demand is occurring alongside a broader transformation in global power generation. Wind and solar generation continue to expand rapidly across electrical grids. Although renewable integration supports long-term sustainability goals, it also introduces greater variability into industrial operating environments. Processes that once operated under relatively stable base-load conditions now experience more frequent cycling, changing load profiles, and fluctuating operating demands. As a result, compressors supporting industrial gas production, air separation, utilities, and process applications must accommodate wider turndown ranges, faster ramp rates, thermal cycling, and more transient operating conditions, while maintaining efficiency, stability, and dependable performance across a much broader operating range. These changing operating conditions are increasing the importance of advanced surge-control strategies, high-speed rotor dynamic stability, anti-surge response, and compressor designs capable of operating efficiently across wider load ranges.
Efficiency, monitoring, and operational visibility As electricity demand continues to increase, energy efficiency has become both an operational and financial priority. Even relatively small improvements in compressor efficiency can create meaningful reductions in operating cost over the life of the equipment, particularly in continuously operating applications. At the same time, industrial facilities increasingly expect compressors to deliver more than just compressed air or gas. Operators require greater visibility into equipment condition, system performance, energy consumption, and overall asset reliability to support more informed operational and maintenance decisions. Condition monitoring and Industrial Internet of Things (IIoT) enabled systems are helping operators: n Detect developing issues earlier. n Improve maintenance planning. n Reduce unplanned downtime. n Monitor energy performance. n Optimise operation across varying load conditions. These evolving requirements are also increasing the importance of advanced compressor control systems integrated with broader plant automation and monitoring platforms. Solutions such as FS-Elliott’s Regulus® Control System help operators maintain stable compressor performance while supporting energy-efficiency objectives, coordinated system control, operational redundancy, and improved responsiveness under changing process conditions. Increasingly, operational data is becoming as valuable as the machine itself. Facilities operating with lean maintenance teams and high uptime expectations rely heavily on remote diagnostics, predictive analytics, and
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Emerging energy applications and the path forward Beyond immediate growth in digital infrastructure, the broader energy transition is creating additional opportunities for industrial air and gas compression. Hydrogen infrastructure development, carbon capture systems, and next-generation energy projects are all expanding as global power demand increases. Many of these applications require higher-pressure process compression, nitrogen handling, advanced controls, continuous-duty operation, and sophisticated monitoring systems. These evolving process conditions are driving demand for compressor systems engineered for both operational flexibility and long-term performance. Integrally geared centrifugal compressor architectures offer meaningful advantages in applications where efficiency, oil-free delivery, operational stability, and variable-duty performance are important considerations. AI may be powered by software, but the industries supporting it depend on reliable compression. As demand for power generation, semiconductor manufacturing, and industrial gas production continues growing, centrifugal compressors will remain critical to keeping these operations running efficiently and reliably.
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Markus Schürmann and Carl Leonhards, Everllence, Germany, consider how developments in syngas compression can impact green ammonia production.
T
echnological transitions rarely fail because new technologies do not work. More often, they fail because new technologies are forced into old system architectures. A well known historical example is the early transition from steam to diesel locomotives. In the first phase, diesel engines were integrated into existing steam locomotive designs. From a purely technical perspective, this approach was feasible and represented a clear step forward. However, the surrounding architecture systems and maintenance philosophy remained optimised for steam operation. The result was a compromise: higher complexity, limited efficiency gains, and reduced competitiveness. The real breakthrough came only when diesel locomotives were fundamentally redesigned around the characteristics of the diesel engine, rather than treating it as a drop in replacement for steam. The ammonia industry faces a similar situation today. Responsible for approximately 1.5% of global greenhouse gas emissions, fertilizer production must undergo rapid decarbonisation. At the same time, ammonia is expected to play a key role as a future marine fuel and hydrogen carrier – applications that require its production from renewable energy sources in order to qualify as green. Electrification, water electrolysis, variable renewable power supply, and new heat integration schemes are fundamentally changing ammonia production. Yet many plant concepts still remain rooted in a ‘steam era’ mindset, where individual components are replaced while the overall architecture remains unchanged.
Instead of optimising individual machines in isolation, Everllence evaluates all mass, energy, and heat flows across the entire process as one integrated system: from hydrogen and nitrogen generation, through syngas compression, to power recovery, refrigeration, and final ammonia condensation. This article focuses on one of the most critical subsystems within that value chain: syngas compression. It explains how the PARSYN® (PARallel SYNgas compressor train) concept enables higher efficiency, lower total cost, and superior availability using proven machinery and well established technologies.
From component optimisation to system engineering In green ammonia plants, the syngas compressor is located at the intersection of several demanding subsystems. The hydrogen produced from renewable electricity via different electrolysis systems enters the syngas compressor at varying pressure levels, depending on the type of electrolyser used. At the same time, nitrogen supplied by the air separation unit is fed into the process – ideally at the same pressure level. On the discharge side of the syngas compressor lies the high-pressure ammonia synthesis loop, the heart of the ammonia plant’s process technology, where heat is generated and should ideally be recovered and reintegrated into the process drivers. As a result, syngas compression is not only the most power intensive compressor in the plant, but also one of the most sensitive to dynamic effects and system interactions. HYDROCARBON 33
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Syngas compression In ammonia synthesis, the compression of syngas – a mixture of H2 and N2 – represents a critical step. Turbocompressors generally achieve higher efficiencies when handling gases with higher molecular weights. Therefore, it is more efficient to compress the mixed syngas than to compress H2 and N2 separately. From this perspective, the mixing pressure of H2 and N2 should be at a very low level. However, lower pressures result in substantially higher volumetric flow rates, increasing equipment size and influencing the overall system design.
Compressor design parameters in syngas applications Barrel-type compressors are typically used for syngas compression. These machines often feature multiple stage groups and integrated recycle stages. Alternatively, integrally geared compressors may be employed, depending on specific process requirements. The number of impeller stages and the associated power consumption depend on several thermodynamic and technological parameters. Thermodynamic conditions include inlet temperature and volume flow, as well as the pressure ratio between inlet and discharge pressure. The technological aspects can be divided into compressor technology characteristics such as circumferential speed of the impeller tips and
Figure 1. Syngas train arrangement derived from the traditional syngas train (Variant A1).
Figure 2. Optimised syngas train of PARSYN design (Variant A5). Table 1. Dimension comparison of different train arrangements Footprint length (m)
Footprint width (m)
Foundation area (m2)
Traditional derived (2 gearboxes)
24.00
7.00
168.00
PARSYN (1 gearbox)
16.00
8.00
128.00
Difference
-8.00
+1.00
-40.00
Difference (relative)
-33%
+14%
-24%
September 2026 34 HYDROCARBON ENGINEERING
impeller material and process-related technology parameters, including the intercooling efficiency and temperature.
Syngas train arrangements In conventional grey ammonia plants, the heat generated during steam methane reforming of natural gas to produce hydrogen – together with the heat released in the ammonia synthesis reactor – is used to produce a large amount of steam, with approximately 90% originating from the steam methane reforming process. To utilise this steam, syngas trains in conventional grey ammonia plants usually employ a double-end drive modular steam turbine (MST) positioned between two barrel-type syngas compressors. In green ammonia production, however, only around 10% of the process steam remains, primarily generated from the ammonia reactor. This is insufficient to drive the compressor trains directly. As a result, the steam turbines are replaced by electric motor-driven gearboxes, while the steam is fed to a separate steam turbine generator train to produce electricity. This configuration is referred to as Variant A1 (see Figure 1). Closer inspection reveals other optimisation opportunities. Variant A2 relocates both barrel compressors in line on one side of the motor, reducing the number of required gearboxes to one. The disadvantage is that both compressor casings now operate at the same, lower rotational speed. This leads to a lower achievable pressure ratio and may require a third compressor casing for higher pressure ratios. Variant A3 also places both compressors on one side of the train, but uses a three-shaft gearbox to drive the two casings at different speeds, ensuring maximum efficiency. To reduce cost and space, the steam turbine can also be integrated into the syngas train, eliminating the need for a separate generator train. One solution is Variant A4, which uses a 4-shaft gearbox, with the barrel compressors mounted on the outer shafts and the motor and steam turbine driving the two middle shafts. Another solution is Variant A5: in this arrangement, the motor is designed with two shaft ends; one being driven by the steam turbine and the other one driving the gearbox with the attached compressors (see Figure 2). Arranging the barrel-type compressors in parallel and connecting them to one gearbox with two pinions, as in Variant A3, offers several advantages. Both compressors continue to run at their optimum speed, while one gearbox can be eliminated. At the same time, the train length is shortened significantly, decreasing the footprint length by approximately one-third. Although the train width – and therefore the footprint width – increases slightly by around one-seventh, the overall footprint is still reduced by around one quarter (see Table 1). With both compressors positioned next to each other, the required maintenance area is reduced and serviceability improved. Another important advantage is the free shaft end of the electric motor, which creates the possibility of connecting a steam turbine for power recovery. For very low hydrogen and nitrogen mixing pressures, other solutions must be considered. One option is to add additional compressor casings. However, this would generally require two or more barrel compressors to be connected in line, leading to significantly increased effort for maintenance. Alternative solutions include technological improvements that allow higher
impeller tip speeds, or the use of other compressor technologies such as stacked rotors or integrally geared compressors.
Cost-effective two-casing solution Considering the well-proven machinery available for hydrogen compression and air separation units, there is no need to mix nitrogen and hydrogen at the lowest possible pressure if mixing can instead take place at a more effective pressure level. The optimal blending pressure should be determined based on the goal of using a cost-effective two-casing solution with conventional or slightly optimised technology. Modern syngas compressors achieve pressure ratios of up to 10 - 11. If the target syngas pressure is, for example, 150 - 160 bar, hydrogen and nitrogen mixing can therefore take place at a lower pressure of 12 - 16 bar. Under this condition, no additional hydrogen booster is required for PEM electrolysis or pressurised alkaline electrolysis. For solid oxide electrolyser cell (SOEC) and atmospheric alkaline electrolysis, a two-stage screw compressor can deliver hydrogen at the required pressure, eliminating the need for reciprocating compressors. The nitrogen compression stages can also be integrated directly into the air separation machinery, removing the need for a separate nitrogen compressor. By selecting the mixing pressures carefully, the number of machines can be reduced while maintaining the security of well-proven designs. This approach can also enhance the bankability of projects, since the technology readiness level of the equipment is very high and only the system arrangement itself changes.
Using steam to lower costs
engineering hours and high voltage cables needed to connect the generator to the grid can also be avoided. Furthermore, no permitting for feeding electricity into the grid is required. Altogether, this results in simpler and faster project execution for all parties involved. During operation of the ammonia plant, further savings can be achieved because the direct mechanical coupling of the steam turbine and compressors avoids conversion losses and reduces overall power consumption.
Synchronous clutch – flexibility, safety, and availability To realise the PARSYN train, one component plays a crucial role: the synchronous clutch between the steam turbine gearbox and the motor. The configuration enables a highly flexible and robust operational concept for the plant drive system. During plant start-up, the compressor is driven exclusively by the electric motor, allowing operation even in the absence of available steam. As the process ramps up, steam generation is gradually established using thermal energy recovered from the reactor. The steam turbine can be independently warmed up and brought to operational readiness. Once the plant reaches approximately 10% of its nominal load, synchronisation and coupling of the steam turbine to the drive train can be performed. In the event of a turbine trip, immediate decoupling is possible without adversely affecting compressor operation, thereby ensuring process continuity. A key design principle is that the electric motor is rated for 100% of the compressor power demand. As a result, the steam turbine does not constitute a capacity-limiting component; but instead functions solely as an energy recovery unit. From an operational perspective, this design provides several advantages: it maximises compressor availability, ensures fail-safe performance across all load conditions, and eliminates any negative impact on production in the event of steam turbine downtime.
The exothermic reaction of nitrogen and hydrogen to form ammonia produces heat, which is typically recovered as process steam. This steam can be used to drive a steam-turbine generator that supplies power to the grid. A more efficient approach is to integrate the power of the steam turbine back into the syngas compressor train, where it can support the electric motor – or, in the case of SOEC electrolyser, use the Evaluation of possible syngas and heat directly within the process. steam turbine train arrangements A parallel arrangement of the syngas compressors creates a To measure the economical effectiveness of the different free shaft end on the motor, allowing direct coupling of the arrangement solutions, four different metrics are considered: turbine. During operation, the steam turbine supports the direct power consumption, electrical operating costs over motor drive while the electric motor remains the dominant five years of operation (OPEX), capital investment costs for power source. Since the turbine output is always lower than the major machinery (CAPEX), and the combination of both as total compressor power consumption, the motor never switches expenditure (TOTEX). Not included in this calculation are into generator mode. Table 2. Detailed comparison of OPEX for Arrangement 3 and Arrangement 5 This solution Power consumption Motor Variable frequency Terminal Power to be offers multiple (kW) – normal case efficiency drive efficiency power (kW) purchased (kW) benefits. Initial Separate syngas 22 000 98% 97% 23 143 11 383 investment costs are compressor train reduced because no Steam turbine -12 000 98% N/A -11 760 generator is required, generator no additional space PARSYN 10 000 98% 97% 10 520 10 520 must be allocated Power savings Operating days per Operating Yearly savings Cost per kWh OPEX savings (€) for the generator (kW) year hours per day (kWh) (€/kWh) train, and no 864 355 24 735 7924 0.06 441 475 foundations need to OPEX savings €2 207 377 be built. The over five years additional HYDROCARBON 35
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relying on a single electric motor and an optional steam turbine for power recovery.
Looking beyond the ammonia horizon
Figure 3. Visualisation of all researched train arrangements with corresponding savings potential. maintenance costs, as well as additional expenses for civil work, permitting, or other engineering services. Arrangement A1 serves as the reference case and therefore represents the baseline with no identified savings potential. See Table 2 and Figure 3. Arrangement A2 increases the number of required casings. As a result, CAPEX rises by a quarter, leading to negative savings effects for both CAPEX and TOTEX. Arrangement A3 improves efficiency while reducing the number of needed gearboxes by half. Although investment costs increase marginally, the configuration achieves overall savings across all categories in the low single-digit percentage range. In Arrangement A4, the steam turbine is directly coupled to the syngas train, circumventing the conversion losses associated with a separate generator train while also removing the need for the generator itself, leading to lower CAPEX and OPEX. However, the very large single gear box is expensive and introduces comparatively high losses, limiting the overall savings potential. Arrangement A5 also integrates the steam turbine directly into the train, thereby benefiting from higher efficiency and lower CAPEX. In this case, the two smaller gearboxes are less expensive and more efficient, leading to the highest overall savings potential for both CAPEX and OPEX.
Long-term field experience Concerns regarding system complexity are best addressed by looking at operational history. A notable example is the El Tablazo ammonia plant in Venezuela, commissioned in 1968. The plant incorporates a highly complex syngas compression system characterised by a parallelised and multi-driver configuration. These compressors are driven by a combination of a gas turbine and a steam turbine, enabling efficient utilisation of different energy sources. Two identical trains accumulated nearly 100 years of combined operating experience. Compared to this configuration, the PARSYN concept is structurally simpler, September 2026 36 HYDROCARBON ENGINEERING
Everllence also brings experience from Purified Terephtalic Acid (PTA) plants, where large multi driver turbomachinery trains are standard practice. In such applications, the installed power levels are considerably higher than those typically encountered in conventional ammonia plants, reflecting the greater process demands and scale of operation. The typical PTA train integrates multiple rotating machines in a single machine train, namely electric motors, expanders, integrally geared compressors, and steam turbines. Furthermore, the use of synchronous clutches and double-pinion gearbox designs represents established and proven standard technologies, ensuring reliable coupling, load sharing, and operational stability. For screw compressors, double pinion gearboxes are already standard, with more than 60 industrial references.
Managing risk through train competence Integrated systems are only low risk when the complete system is fully understood and engineered accordingly. The PARSYN concept therefore shifts the focus from individual machines to true train engineering, encompassing rotordynamic analysis, torsional vibration calculation, interaction between the electrical grid and the mechanical system, transient analysis for start-up and trip scenarios, as well as clutch engagement and disengagement behaviour. This is why train competence becomes decisive – not just machine competence. When supported by this level of system expertise, integrated train designs do not increase risk. On the contrary, they reduce the number of interfaces, simplify potential failure modes, and improve overall system robustness.
Conclusion: choosing the right concept for a new era A diesel engine in a steam locomotive was not competitive. Likewise, green ammonia plants designed with steam era layouts will struggle to compete – regardless of how low their carbon footprint may be. Future competitiveness will be determined by total installed cost, specific power consumption, operational flexibility under variable renewable power supply, availability and maintainability, as well as the bankability of proven technology. Compared with conventional syngas train concepts, PARSYN demonstrates competitive advantages, because its design is aligned with the dynamic operating conditions typical of green ammonia production rather than conventional steady-state design approaches. Green ammonia does not require new machines – it requires new system thinking. The PARSYN syngas compressor train demonstrates how established machinery, intelligently arranged, can unlock higher efficiency, improved reliability, and strong economic performance. Just as diesel locomotives only became successful once they were designed as true diesel locomotives, green ammonia plants will only reach full competitiveness once they are conceived and designed as fully integrated, electrified systems.
Klaus Brun and Karl Wygant, Ebara Elliott Energy, alongside Rainer Kurz, RKSBenergy, discuss technical advancements in control and application for integrally geared compressors.
F
rom the large throughput of air separation units (ASUs) to the precision required for carbon capture and LNG, the integrally geared compressor (IGC) is the engine driving some of today’s most critical energy processes. Unlike standard designs, the IGC utilises a central bullgear to drive multiple pinions (Figure 1), allowing each stage to operate at its own speed and efficiency. This mechanical flexibility, coupled with the ability to intercool between every stage, makes it a powerhouse for handling complex volumetric changes. Yet, the versatility of the IGC demands an equally
reliable control system designed to ensure safe and stable operation across its entire performance envelope (Figure 2). The control of any compressor combines systems that protect the compressor, as well as systems for process control. The protection systems defend against overspeed, over pressure, exceeding certain temperatures, insufficient lube oil or seal gas flow, excessive leakage, operation at high shaft vibrations, etc. They also include the protection of the compressor from operating in surge and, if necessary, in choke. For process control, the capability to equip the IGC with variable HYDROCARBON 37
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inlet vanes and variable geometry diffusers, if necessary for every stage, gives a wide and efficient operating range. Additionally, recycling and throttling can be employed. Combining these control methods allows for the effective use of the compressor in applications where the operation requires near constant head (such as in boil-off gas, carbon capture, and plant air applications), as well as in applications where flow and head are closely related. It often eliminates the need for variable speed drives.
Control methodologies for flow and head For effective process control with IGCs, several primary control methods are utilised, each with distinct effects on the compressor’s performance map. These methods must be coordinated.
Throttle valves are the most simple and cost-effective means of flow control, primarily used where the required operating range is relatively limited. A suction throttle valve reduces the density and pressure of the incoming gas, thereby forcing the compressor to generate a higher head than the process physically requires, achieving a lower actual flow at constant discharge pressure. Conversely, a discharge throttle simply increases back pressure. Simple throttling incurs significant efficiency penalties, usually leading to increased power consumption. Variable inlet guide vanes (VIGVs) are a highly effective and common control method, particularly when the system characteristic dictates that a reduction in flow coincides with a reduction in head requirements. VIGVs regulate flow by introducing pre-swirl (cu1 <0) into the inlet flow of each stage with a VIGV. This swirl reduces the work input to the gas, as defined by the Euler turbomachinery equation (Equation 1): ∆h = (u2cu2-u1cu1)
Figure 1. Components of an IGC.
Figure 2. Control system and various process controls (Wygant et al. 2016).1
September 2026 38 HYDROCARBON ENGINEERING
As the VIGVs close, head is lowered, and for applications where discharge pressure is kept constant, the flow is reduced. VIGVs can be optimised by incorporating a centre body to prevent flow from entering through the mid-section hole. The entire VIGV system relies on aerodynamically shaped vanes, a robust actuation mechanism (including linkages and motors), bushings for smooth movement, and seals to prevent leakage. For multi-stage compressors, especially with heavy gases such as CO2 with a drastic volume flow change from stage to stage, multiple VIGVs may be needed to control the individual stages and avoid surge in later stages. CO2 compressors in carbon capture applications are a good example, where volumetric flow can be reduced by a factor of over 300 from inlet to outlet. Variable geometry diffusers (VGDs) are advantageous for applications requiring turndown at a more or less constant head (a weak head-flow relationship), such as in refrigeration or plant air compressors. VGDs do not impact the energy input of the impeller but extend the low-flow operational range by stabilising the flow within the diffuser. They achieve this by aligning the diffuser vanes with the impeller exit flow angle at various operating points, minimising pressure loss and delaying the onset of diffuser stall. By avoiding incidence losses, VGDs offer a wider operating range at a constant head compared to VIGVs. However, the integration of VGDs involves greater mechanical complexity and cost due to the necessary linkages, actuators, and tight clearance control. A comparison of VIGVs and VGDs can be seen in Figure 3. For applications requiring both wide range and efficiency, VGDs and VIGVs may be used concurrently on several stages of the compressor. This can be achieved through a mechanical linkage, which offers simplicity and reduced components but limits independent control, or through independent actuation, which provides greater flexibility and precision in tuning but increases system complexity, cost, and maintenance requirements. Variable speed control, where feasible, is an excellent match for systems with a strong head-flow relationship, offering high efficiency over a wide flow range by maintaining the similarity of the velocity triangles. However, variable speed
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Figure 3. Comparison of VIGV and VGD impact on head and flow (Kurz et al., 2024).2
system-dependent, dictated by the geometry and volume of the upstream and downstream piping.3 Therefore, surge control is a systems issue. The system in question comprises the compressor, a controller, one or more recycle loops with valves, process instrumentation, and the pipes and coolers. The anti-surge control system must be designed to cover three distinct scenarios: process control, surge avoidance during fast transients (like an emergency shutdown), and surge avoidance during start-up. During an emergency shutdown, for example, power to the compressor is instantaneously cut, and the anti-surge system must rapidly open the recycle valves to prevent reverse flow through the compressor. This requires a system designed for fast action. Process control, on the other hand, requires slower, but very precise responses of the system. Start-up typically involves setting the recycle valve to a fixed, open position and closing it once the unit is operational. Most IGC applications outside of air compression require recycle systems, as the compressed gas is often flammable, poisonous, valuable, or a greenhouse gas. Air compression systems may use a simpler blow-off valve. While a single recycle system from the discharge to the inlet is common, the large gas volumes between stages in a multi-stage machine can cause significant storage effects, potentially necessitating recycle systems designed for individual stages. For compressors handling multiple services, such as in ASUs, each service typically requires its own dedicated recycle system.
IGC design and thermodynamic principles
Figure 4. Efficiency vs flow coefficient. operation significantly increases engineering complexity to reduce pinion critical speeds and impeller blade resonances in machines with multiple shafts spinning at different speeds. The cost of variable frequency drives (VFDs) for the main motor must also be considered. Recycle control systems allow the gas to be routed from the compressor discharge back to the suction, with the flow managed by a control valve (often part of an anti-surge system). This allows the compressor to operate at a plant flow rate below its surge limit and can accommodate constant head requirements. The trade-off is a large efficiency penalty due to the energy expended on recycling the gas.
Surge avoidance and anti-surge systems Surge is a system instability caused by situations where the compressor is no longer able to overcome the system discharge pressure. It is characterised by a sudden, intermittent reversal of gas flow that can lead to significant forces capable of damaging bearings, seals, and rotating elements. The severity and frequency of surge are September 2026 40 HYDROCARBON ENGINEERING
The IGC’s physical design, with overhung centrifugal stages, is instrumental in its versatility. This overhung design allows for axial flow into the stage and the convenient use of a volute after every stage. The gas has to be conveniently intercooled between stages when required. Intercooling removes entropy from the compression process, which can result in significant power savings, provided the pressure loss within the intercooler is minimal. An IGC consists of a centrally-arranged bull gear driving one or multiple pinions. These pinions are connected on one or both ends to overhung impellers. Since the gearbox ratio between the bullgear and each of the pinions can be different, impellers can (unlike in a single shaft machine) operate at different speeds. The volume reduction of the compressed gas from stage to stage leads to smaller flow coefficients for the rear stages if all stages run at the same speed (Equation 2):
The IGC’s ability to use a different gear ratio for each pinion allows impellers to run at speeds to match the constantly decreasing flow volume in subsequent stages, keeping the flow coefficient near the best efficiency point for each stage (Figure 4). This is essential for maintaining high overall efficiency across the compression train, especially for high pressure ratio applications with heavy gases.
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The overhung stages (volute and impeller) easily accommodate intercooling between stages. The ability to intercool removes entropy from the gas stream.
Versatile IGC applications The design and control advantages of IGCs have secured their role in various demanding applications. In ASUs, IGCs have been a standard since the 1970s. The multi-speed aero layouts and the ease of installing intercoolers between each stage allow for highly-efficient designs that reduce both capital (CAPEX) and operating (OPEX) expenditures. An ASU process may incorporate several IGCs, including a main air compressor (MAC), a booster air compressor (BAC), and various nitrogen and oxygen compressors, all engineered to meet specific cycle requirements. Flow control is typically managed with VIGVs. Plant air compressors are typically simpler, robust designs delivering shop air at a fixed head (8 - 11 bar) due to the fixed atmospheric inlet pressure and plant-dictated discharge pressure. They often use VIGVs for flow control and a blow-off valve for anti-surge. In LNG and cryogenic applications, IGCs are essential, particularly for boil-off gas (BOG) compression (Figure 5). BOG compressors handle evaporated gas in LNG storage, maintaining safe tank pressures. These applications involve extremely low gas temperatures (down to -140°C) requiring special materials and heat barrier walls to insulate the bearings and gearbox from the cold flow path. For LNG tanker transport, the BOG compressor requires a wide operating range, sometimes down to 30% of design flow, often achieved with a combination of VIGVs and VGDs to maintain head stability. In LNG liquefaction plants, IGCs are used for small scale production, often employing a reversed Brayton Cycle with nitrogen refrigerant. The compressors and expander can be integrated into a single IGC unit (compander). Carbon capture and sequestration (CCS) is a rapidly growing application where IGCs play a key role in compressing CO2 from low-pressure capture conditions to high-pressure transport or sequestration levels. For sequestration, pressures can range from 100 to 500 bar, depending on reservoir depth and structure. This high overall pressure ratio and massive volume reduction necessitates multiple intercooled stages to
reduce power consumption and manage temperatures. Due to the high-volume reduction between stages, multiple VIGVs are often required to control the process flow effectively. The process requires the removal of water during compression to prevent the formation of corrosive carbonic acid. For pipeline transportation, CO2 efficiently moves in a dense phase (supercritical), which has a high density but a gas-like viscosity, requiring pipeline pressures typically between 85 - 150 bar. In fuel gas compressors (FGCs), IGCs pressurise low-pressure fuel gas to meet the high-pressure requirements of modern, efficient gas turbines (up to 70 barg or 1000 psig). These applications require dry gas seals and often explosion-proof motors due to the flammable nature of the gas. For offshore platform applications, IGCs are valued for their small footprint, high efficiency, and low dynamic forces. They are used in applications such as instrument air compressors (IAC) and vapour recovery compressors (VRC). VRCs utilise the IGC’s capability for high suction and high head capacity via multiple stages to compress residue gases, sometimes from partial vacuum levels, for injection into other processes or flare reduction, thus improving environmental compliance. The ability to integrate water-spray coolers between stages makes IGCs suitable for vapour/steam compression near the saturation line. Finally, in sCO2 Brayton power cycle applications and heat pumps, IGCs can combine the compressor and turbine into a single machine, or compander, which is an efficient arrangement for closed-loop systems. The reverse Brayton cycle heat pump, for example, utilises the compressor to increase the temperature of the working fluid for heating, achieving a high coefficient of performance (COP). These advanced applications often necessitate a high power-density design, demanding advanced gear and bearing systems capable of handling high pitch line velocities and bearing loads.
Summary The successful and efficient operation of integrally geared compressors relies on the precise management of flow and stability through coordinated control elements. The core design principles of the IGC, which favour multi-speed aero-layouts and intercooling, allow it to remain a strong and adaptable technology in the energy transition and in industrial processes that demand both high efficiency and operational flexibility.
References
Figure 5. IGC and reciprocating compressor in the same BOG application.1
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1. WYGANT, K., et al., ‘Tutorial on the Application and Design of Integrally Geared Compressors,’ Asia Turbomachinery and Pump Symposium, (2016). 2. KURZ, R., et al., ‘Process Control for Integrally Geared Compressors,’ Turbomachinery & Pump Symposia (TPS), Houston, Texas, US, (2024). 3. MOORE, J.J., et al., ‘Tutorial on Centrifugal Compressor Surge Control’, Proc. 47th TPS, Houston, Texas, US, (2019).
I
Attilio Brighenti, Christian Casonato, and Alessandro Mafolino, S.A.T.E. (Systems and Advanced Technologies Engineering S.r.l.u.), Italy, consider the side-effects of early design decisions.
n the first part of this two-part article,1 the authors introduced the importance of a multidisciplinary approach in the design of surge control and protection systems for centrifugal and axial flow compressors, which are dealt with by the API 617 standard.2 In particular, they highlighted the necessity of analysing in detail the effects of piping routing, sizing, and connections geometry of the recycle lines on potential flow induced pulsations (FIP) and flow induced vibrations (FIV). These could indeed develop under certain operating conditions, above all when the recycle lines are shut-off. Should this occur, the operator might need, at least temporarily, to keep recirculation valves even partially open (i.e. wasting energy and reducing net capacity) but, at worst, it may be necessary to redesign the lines and physically modify the piping to fix the problem indefinitely. This second part shows an example of real evidence of this problem for an antisurge system, in a practical case addressed by the
main author, in which severe vibrations of the recycle lines of a centrifugal compression station proved to originate from FIP in the antisurge line, to the extent that the compressor had to be tripped repeatedly and its pipework needed costly modifications to prevent almost certain fatigue breakout in the relatively short-term.
Vortexes induced at pipe branches This category of phenomena is exemplified in Figure 1c. It applies to all fluid path branches created by isolation valves, by-pass lines or spare lines, or by any enclosures able to trap the fluid, in continuity with the flowing zones. In this case, acoustic lock-on can occur also with vortex sources different from those at the Tee of the branch of concern, i.e. at upstream or downstream obstructions or Tees, should the respective frequencies match. The acoustic response to be considered against the vortex matching is that of a
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relatively broad system, extending beyond the immediate surroundings of the vortex source. This applies, above all, if the vortex source is prone to excite low frequency acoustic modes associated to large standing wave lengths extending over parts of the system or combinations of pipe elements that, by themselves, would not resonate at the frequency of the disturbance, e.g. because they are too short. The worst conditions for side branches or cavities occur when they do not convey any flow (dead branches, such as inactive antisurge lines) and, even worse, when they can couple with similar nearby branches, such as in cross junctions or tandem junctions (Figure 2). Indeed, the fluid flow produces a significant yet low damping of the acoustic response that disappears or is negligible at low flow conditions. Nevertheless, significant and disturbing side branch resonances may occur even in flowing conditions along the branches affected, which, in this case, share a net flow rate with the main line and not only an oscillating fluid. The phenomenon depends on and is studied experimentally as a function of the dimensionless Strouhal number (St) at the flowing conditions occurring in the Tee junction, for example (Equation 1):
Where: n fs: frequency of the excited vortex turbulence [Hz]. n D: diameter of the main pipe of the Tee [m].
Figure 1. FIP and FIV sources onset: abrupt expansion (a), obstructions (b), and Tees (c). Blue arrows: flow direction; green arrows: acoustic waves; red arrows: shaking forces.
Figure 2. Base acoustic resonance modes of single and twin dead branches.
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n v: average flow velocity at the main pipe of the source Tee junction, i.e. that of the flowing line [m/s]. n St: Strouhal number at the tee junction [--]. The maximum pressure pulsation amplitude occurs at specific values of the Strouhal number that correspond to the acoustic modes that can couple and be excited by the vortex source. The frequency at which this acoustic lock-on occurs changes according to the geometry,3,4 showing a very case-specific dependence of the critical excitation condition. The commonly accepted criterion to avoid FIPs at side branches (thus FIVs if the other conditions are met)1 is to ensure that no acoustic modes of the piping, at the actual operating conditions, have frequencies corresponding to a Strouhal number St in the range between 0.27 and 0.55.5 These boundaries represent the envelope interval in which the maxima of the response fall for most experimental setup. It is important to underline that while acoustic frequency calculations and mismatch assurance have a reliable physical-mathematical basis, the same does not apply, or at least is not general, for the prediction of the acoustic response amplitude and consequent maximum shaking forces on the piping and equipment, particularly in resonance conditions. Therefore, asset integrity should be pursued by searching for solutions that allow operating outside the critical St interval over the widest, if not the whole, operating envelope of the concerned potential FIV sources.
Real antisurge lines case The authors’ engineering company was called for the root-cause analysis and identification of remedies of a severe vibration situation in a gas compression facility that was undergoing commissioning and early operation test phases. After a short pre-analysis, it was evident that critical FIP and FIV conditions could be occurring in the low pressure sides of two recycle lines, one of the antisurge system and the other for process control by an independent recycle line. These were tied-in close to each other and could resonate at nearly the same frequencies (9 and 10.4 Hz), due to the nearly identical lengths of the piping between the respective valves and Tee (Figure 3a and 3b). Based on analyses made by the proprietary software ACUSYS© and post-processing tools for FIV check and separate structural modal analyses, it was possible to study the problem in detail and remedial solutions. In the as-built piping situation, the acoustic resonance is particularly amplified by the coupling between the two branches as per analogous findings by laboratory experiments reported in the literature cited above. Figure 4 shows the lower (green) and upper (blue) range boundaries of the vortexes frequency that could be generated at the right tie-in Tee, under the considered (test) mass flow rate through the main lone. They vary with pressure and temperature (this latter kept constant in this example), from which the gas density and velocity depend. In the same figure the red line represents the frequency of the mode at 9 Hz, which in this case is negligibly variable with the gas pressure and is clearly within the range of FIP excitation. Both this and the other mode at 10.4 Hz were then falling in the critical range
determined by the flowing conditions at the Tees and also very close to the frequency of structural modes well coupled with the shaking forces generated by the acoustic modes concerned. This latter condition was then determinant to yield also FIVs consistent with the high amplitude ones measured in the plant. Figure 5 shows that the vortex-acoustic lock-on for the same 9 Hz mode would occur over the whole pressure range of interest for mass flow rates in the main line falling within the varying boundaries zone, between the green (minimum) and blue (maximum) lines. These findings together proved that the test and most of the operative conditions of the facility were falling in the FIV onset zone. It is worth highlighting that, at fatigue stress cycle frequency of 10 Hz, 1 million cycles would be reached in about 28 hr, and 100 million cycles in about 2800 hr (3.8 months). Therefore countermeasures were needed to prevent breakout. Consequently, several alternative piping paths were analysed to find remedies, subject to the following goals: n Being compatible, as much as possible, with the already built plant. n Avoiding mirror-like geometries and consequent bouncing resonances. n Shifting the critical St range and vortex frequencies from the acoustic ones. n Decoupling the structural frequencies from the acoustic ones.
Figure 3. Acoustic resonance excited by FIPs, yielding FIVs, of the as built antisurge and recycle line tie-in (a and b) and of the modified piping (c, d, and e).
Figure 4. As built configuration: acoustic-vortex lock-on margins variation vs absolute pressure at test flow rate for the acoustic modes at 9 Hz (solid red line).
The best solution found was to join the two recycle lines before the tie-in to the main line, reducing the continuous vortex source to a single Tee mouth. This considered the infrequent and still compatible simultaneous opening of the respective valves. As subvariants, both 90° T and 45° Y junctions were considered, the latter proving best to ensuring FIV free operation at the compression facility capacity and pressure range. Of course, the FIV check was made considering acoustic models for all the relevant combinations Figure 5. As built configuration: flow rate limits of the lock-on zone, compared with of shut-off and flowing conditions the test flow rate (solid red line) for the acoustic mode at 9 Hz. of the two side branch lines and of the main line, including not only determined by the critical St interval (Figure 3c, 3d, and 3e): the recycle dead branches but also a significant portion of the sufficiently below and above the respective limits. main and other tied in pipes. Figure 6 shows that, at the test mass flow rate, the excitation The acoustic modes frequencies of the whole system that of the first acoustic mode, lowered to 7.5 Hz (Figure 3c), is could be excited by vortexes at the main Tee and at the avoided until the gas pressure is lower than 10 bar a. Y junction were thus brought outside the critical range HYDROCARBON 45
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the other parallel ones in the same compression station, solving the original problems.
Conclusions This article has described a problem area that is not addressed by current antisurge systems design standards but that could be conditioning the efficiency and integrity of centrifugal and axial flow compression plants. Indeed, in the case studied, before the piping modifications, the operator could partially limit the vibrations by keeping at least one recycle valve partially open by a trial and error tuning approach, Figure 6. Modified recycle lines: acoustic-vortex lock-on check at the test with obvious energy and throughput losses. flow rates for the 1st acoustic mode at 7.5 Hz (case of Figure 3c). In the case reported, the possible modification alternatives were limited by the constraining factors of an already built plant. In general, therefore, it is recommended to conceive the recycle lines paths and lengths of the respective high and low-pressure sides to avoid similar critical situations, too costly to remedy after detailed design or, worse, after construction. Considering the concurrent requirement of minimising the volume of the discharge side of the compressor stages piping, it could be argued that it is better for the recycle valve to be closer to the take-off point. This holds true for the discharge depressurisation goal, but, on the other hand, this would increase the length Figure 7. Modified recycle lines: acoustic-vortex lock-on check at the nd acoustic mode at 28 Hz excited by vortexes at of the low-pressure side, for a given test flow rate for the 2 distance between the take-off and tie-in the recycle lines junction (setup of Figure 3 ‘d’: dashed lines with 45° Y connection, solid lines with 90° T connection). zones. In a long, normally shut-off line, several acoustic resonances might be possible in the range of possible vortex excitation frequencies Figure 7 shows, on the other hand, that, at the same test mass at the tees or obstructions. Should any of these be matched, flow rate, the excitation of the second acoustic mode, at 28 Hz FIPs would be excited and, upon certain conditions vibrations (Figure 3d), by vortexes developing at the junction between the too (FIVs). These would quickly accumulate stress cycles antisurge valve (open) and the recycle valve (closed) is avoided beyond pipe weld joints fatigue limits. at all the gas pressures explored, with 45° Y junction, or at It is therefore essential, given the much higher exposure of pressure higher than 8.4 bar a, for 90° T junction. the piping to normal flow conditions, to verify and ensure that The above-mentioned pressure limits vary with the flow no FIP and FIV conditions could arise in the compression rate, which implies performing a multiparametric analysis system operating envelope and lifetime, considering the range approach and synthesis, considering the sensitivity of the FIV and changes of the gas composition, temperature, and check to the gas flow rate, molar weight, pressure, and pressures, all determining the speed of sound and density of temperature, all affecting the quantities in Equation 1 and the the fluid, i.e. FIP conditions throughout the plant lifetime. acoustic mode frequencies that depend on the speed of sound. To this regard, it must be underlined that the speed of sound through natural gas mixtures depends on both References 1. BRIGHENTI, A., CASONATO, C., and MAFOLINO, A., 'Systems engineering temperature and pressures, the latter having even more for surge control – part 1', Hydrocarbon Engineering, (May 2026), pp. 33 - 36. influence in some operating envelopes. It also varies with the 2. API standard 617, 'Axial and centrifugal compressors and gas molar weight and compressibility, i.e. with the gas mixture expander-compressors for petroleum, chemical and gas industry services,' 9th ed., (April 2022). composition, which shall then be considered in defining the 3. ZIADA S., and SHINE, S., 'Strouhal numbers of flow-excited acoustic extent of the FIV check studies. resonance of closed side branches', Journal of Fluids and Structures (1999), 13, pp. 127 - 142. In the history case considered, after thorough analysis was 4. ZIADA, S., SCOTT, S., and ARTHURS, D., 'Acoustic excitation by flow in performed, the modifications proposed were implemented in T-junctions', Transactions of the ASME (2007), 129, pp. 14 - 20. 5. ZIADA, S. and BUHLMAN, E. T. 'Self-Excited Resonances of Two Side one compressor unit, showing full success in vibrations Branches in Close Proximity,' Journal of Fluids and Structures, (1992), suppression, thus the client extended the piping changes to all 6, pp. 583 - 601. September 2026 46 HYDROCARBON ENGINEERING
Hani Taan, NanoTech Materials, explores how operators can address corrosion under insulation through preventative measures in downstream facilities.
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orrosion under insulation (CUI) remains one of the most persistent asset integrity challenges facing refineries, petrochemical facilities, and gas processing plants. But the economics of managing corrosion are becoming increasingly difficult. Many facilities are operating with ageing infrastructure, tighter maintenance budgets, and fewer inspection resources than they had a decade ago, even as pressure mounts to extend asset life and maintain reliability. Part of what makes CUI so difficult to manage is that it develops largely out of sight. Thermal cycling from daily temperature swings, startup and shutdown events, and changing weather conditions can cause continual expansion and contraction, wetting and drying, that accelerates coating degradation and creates conditions that promote corrosion. Because this degradation often occurs beneath otherwise intact insulation systems, wall loss can progress unnoticed until insulation is removed during a scheduled inspection. This reality is driving a shift in how operators approach CUI mitigation. While inspection remains a cornerstone of asset integrity programmes, many facilities are increasingly focused on reducing the conditions that allow corrosion to develop in the first place. As a result, reducing CUI risk is no longer simply a maintenance concern – it is a critical asset
of integrity and operational reliability priority. Long-term CUI management requires a combination of risk-based inspection, moisture management, and preventative protection technologies that help limit moisture intrusion, reduce temperature fluctuations, and improve system durability between inspection intervals.
Pairing inspection with preventative asset protection Inspection remains a cornerstone of any CUI management programme. Technologies such as pulse eddy current testing, guided-wave ultrasonics, and digital radiography have improved operators’ ability to identify corrosion before it leads to failure, while periodic strip-and-inspect programmes remain common across downstream facilities. The challenge is scale. A single facility may manage thousands of feet of insulated piping and critical process equipment, making inspection programmes labour-intensive, disruptive, and expensive due to scaffolding requirements, insulation removal, and reinstallation. In many cases, inspection findings reveal that moisture intrusion – not the insulation itself – is the root cause of corrosion. Damaged jacketing, deteriorated sealants, and improperly protected penetrations can allow water to reach the substrate, where it may remain trapped for extended
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periods before becoming visible. The challenge is often greatest at valves, flanges, supports, instrumentation, and other complex geometries, where numerous seams, joints, and transition points create additional opportunities for moisture ingress. This reality is driving a broader shift in how operators approach CUI mitigation. Inspection remains essential for assessing asset condition and prioritising maintenance, but long-term CUI management also requires strategies that reduce the conditions that allow corrosion to develop between inspection intervals. Increasingly, operators are looking for approaches that improve asset visibility, simplify inspection procedures, reduce moisture-ingress pathways, and improve long-term maintainability.
What a proactive approach to corrosion prevention looks like
While inspection remains essential, many downstream operators are increasingly looking beyond detection-focused strategies and evaluating ways to reduce CUI risk before it develops. This shift reflects a broader recognition that preventing moisture from reaching the substrate is often more effective than repeatedly uncovering and repairing corrosion after it has already formed. As a result, operators are placing greater emphasis on moisture management, vapour-barrier performance, condensation control, and protective systems designed to withstand long-term thermal cycling. This focus on prevention reflects a growing understanding that corrosion is rarely driven by a single factor. Moisture intrusion remains a primary concern, but thermal cycling can further accelerate degradation. Repeated expansion and contraction driven by weather conditions, process fluctuations, startup and shutdown events, and daily temperature swings can create recurring condensation and evaporation cycles that increase the likelihood of corrosion developing beneath insulation. To address these challenges, operators are increasingly evaluating solutions that not only keep moisture out, but also simplify maintenance and reduce the number of pathways through which moisture can reach the substrate. One approach gaining attention is the use of coating-based systems. Unlike conventional insulation assemblies, which rely on multiple components to keep moisture out, insulative coatings are applied directly to an asset’s surface, eliminating many of the seams, joints, and external elements Figure 1. Coated control valve, valve body, and associated that can become pathways for moisture ingress over time. small-bore piping at the Michigan natural gas processing This distinction can be particularly valuable on assets facility, US, photographed after three winters of field exposed to condensation, washdowns, weather, or complex service. The coating was applied directly to the valves, meters, and piping, while adjacent vessels, instrument operating conditions. While coating-based systems are not enclosures, and structural steel remain uncoated. intended to replace every traditional insulation application, they can provide an alternative for assets where moisture management, inspection accessibility, and protection of complex geometries are primary considerations. Because coatings are applied directly to the substrate, they can also improve asset visibility and reduce the need for insulation removal during routine inspections. The operational value of controlling moisture and condensation can be seen in real-world applications. At a natural gas processing facility in Michigan, US, operators faced recurring icing, condensation, and moisture accumulation on outdoor valves, flow meters, and associated piping during winter conditions. Traditional Figure 2. Cold-side surface temperature, coated vs bare pipe, over a 20 minute outdoor exposure at 85°F ambient and 60 - 70% RH. The coated section prevention measures, including (120 mil / 3 mm ceramic-particle insulative coating) ran an average 9.5°F protective covers and electric heat warmer than the adjacent bare section. The bare-pipe surface remained below tracing, had not prevented ice dew point for the full test window, while the coated surface tracked into the formation and operational interruptions condensation-margin band between the 60 - 70% RH dew point lines. Recorded during severe weather events. After 12 May 2026 at NanoTech Materials’ bench-test facility, Katy, Texas, US. applying an insulative ceramic-particle September 2026 48 HYDROCARBON ENGINEERING
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Figure 3. Insulative ceramic-particle coating applied to a pump discharge assembly, strainer body, and flanged piping on an unrelated installation. Because the coating follows the substrate, flanges, bolting, and body contours are covered without the fitted sections and sealed terminations a bulk insulation assembly requires at each geometry change.
Figure 4. Coating applied to overhead process piping, valves, and grooved couplings on an unrelated installation, showing continuous coverage across elbows, tees, and fittings. coating directly to the affected equipment, the site reported three consecutive winters without major ice accumulation events. The approach eliminated the need for a bulk insulation system that would have been difficult to install on irregular equipment geometries while helping stabilise operating temperatures and reduce moisture-related operational challenges.
How to specify coating systems for long-term integrity The importance of moisture management becomes even more apparent in cold-service applications. While hot-service CUI often receives the most attention, chilled-water systems, refrigeration lines, LNG infrastructure, glycol systems, and gas processing equipment frequently operate below ambient dew point, creating conditions where condensation can form continuously during normal operation. September 2026 50 HYDROCARBON ENGINEERING
Unlike hot-service assets, which may experience intermittent wetting, cold-service systems can remain exposed to moisture for extended periods. In these environments, the challenge is often less about preventing occasional water intrusion and more about managing continuous condensation over long operating periods. That reality is driving increased focus on vapour-barrier integrity, condensation prevention, and protective systems capable of maintaining performance over time. As operators look for ways to manage these risks, coating-based systems are increasingly being evaluated alongside traditional insulation approaches. Regardless of the technology selected, several specification considerations can have a significant impact on long-term performance: n Test-standard alignment: CUI performance should be validated against a corrosion-specific test standard such as AMPP TM21442 or ISO 19277, not inferred from thermal-conductivity data. Personnel-burn performance is a separate question, validated under AMPP/NACE TM21423, and should be evaluated across the asset’s operating temperature range rather than at a single steady-state point. n Substrate preparation: long-term performance begins with proper surface preparation. Adhesion under thermal cycling is critical to maintaining both corrosion resistance and system durability. n Inspection accessibility: visibility remains one of the most persistent challenges in CUI management. Inspection requirements should be clearly defined, including visual assessments and any non-destructive testing methods used to monitor asset conditions. Because inspections can be labour-intensive, disruptive, and expensive, operators increasingly prioritise approaches that simplify condition assessments and reduce the need for extensive insulation removal. n Lifecycle economics: these considerations also extend beyond initial installation costs. In many facilities, the largest expenses associated with CUI are tied to inspection programmes, scaffolding, insulation removal and replacement, maintenance labour, production interruptions, and asset downtime. As a result, operators are increasingly evaluating solutions based on total lifecycle cost, ease of inspection, maintenance requirements, and long-term reliability rather than material cost alone. Taken together, these trends point to a broader evolution in how the industry approaches corrosion management. As facilities continue to age and maintenance of resources remain constrained, operators will increasingly look for solutions that improve visibility, simplify inspection, reduce lifecycle costs, and strengthen long-term asset reliability. The most effective strategies will balance detection and prevention, recognising that long-term asset integrity depends on both. The future of CUI management is not simply finding corrosion sooner; it is reducing the conditions that allow it to develop in the first place.
Todd Gerstenberger, ITT Goulds Pumps, explores how early investment in pump design and specification decisions can outweigh upfront savings through reduced maintenance challenges and improved component life.
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umps are a significant capital investment in hydrocarbon operations, and the focus during the purchasing phase is often on reducing upfront cost. While this approach is understandable, it can overlook the reality that pump lifecycle cost is driven far more by reliability, maintenance frequency, and repair scope than by initial price alone. In abrasive and corrosive hydrocarbon services especially, spending more modestly during specification and design can result in longer service life, extended mean time between repairs (MTBR), and lower total cost of ownership. This article explores several pump design and specification decisions that exemplify a ‘pay now, save later’ philosophy. These considerations are based on common failure modes and maintenance challenges seen in harsh hydrocarbon applications, where premature wear and frequent repairs can quickly erode any perceived upfront savings.
Material selection: the first line of defence The material of construction for a pump is one of the most critical and most impactful specification decisions. Higher alloy materials typically offer significantly better resistance to corrosion and erosion than standard materials in all but the most benign services. While higher alloy materials carry a higher initial cost, they often last much longer in service and require less intervention during repair cycles. Standard materials frequently need to be sandblasted and recoated during repairs to restore protective surfaces, adding both cost and downtime. In contrast, higher alloy materials can often be reused without recoating, reducing pump repairs and inactivity. In services where corrosion, solids, or aggressive process fluids are present, material upgrades are often not a luxury, but a practical necessity for achieving acceptable reliability and lifecycle cost performance.
Wear rings: designing for repairability Wear rings are another common example of an upfront design choice that pays dividends over the life of a pump. Wear surfaces run closely together to break down the pressure differential between the discharge of the impeller and lower-pressure areas of the impeller or casing. It is possible to purchase a pump without wear rings, relying instead on close clearances between the impeller
and casing. While this may reduce initial cost, it can significantly increase repair effort later. Without wear rings, restoring clearances during a repair requires machining the impeller and casing themselves. When casing and impeller wear rings are specified from the outset, material is initially removed from each component to accommodate the rings. While this may seem counterintuitive, it simplifies future repairs. Worn wear rings can be replaced with new original-equipment rings that can be kept on the shelf as spares, eliminating the need for repeated machining and reducing repair downtime. In abrasive hydrocarbon services, wear rings act as sacrificial components, absorbing damage that would otherwise affect major pump components.
Shaft sleeves and lineshaft protection A similar philosophy applies to shaft sleeves. Replacing a sleeve is far less expensive and less disruptive than replacing an entire shaft. Shaft sleeves protect the shaft itself from damage, allowing wear to be managed through relatively inexpensive replacement parts. In vertical pumps, this same concept extends to lineshafts. Sleeves can be added at each column bearing location to protect the lineshaft from wear. Lineshaft sleeves absorb damage that would otherwise compromise the shaft. There are tradeoffs to consider. Sleeves require additional space, and the shaft cannot be reduced in diameter at the sleeve location because it must still transmit the required torque. As a result, associated components (such as sleeve bearings, bearing retainers, and in some cases the column) may need to be enlarged. These changes can increase upfront cost and complexity, but they often result in significantly lower repair costs and reduced risk of catastrophic shaft damage.
Hardfacing: extending component life Hardfacing is another tool commonly used to improve wear resistance in demanding services. Hardfacing involves applying a coating of very hard material, either by welding or spraying, onto a base material. These coatings can reach hardness levels in the 70s on the Rockwell C scale, compared to base materials that may be in the 30s. Wear rings and sleeves are particularly good candidates for hardfacing, as these components are subject to continuous wear. Properly selected hardfacing materials can dramatically extend component life and reduce replacement frequency. HYDROCARBON 51
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However, compatibility is critical. Incorrect hardfacing selection can lead to corrosion beneath the coating or flaking of the hardfaced layer, potentially accelerating damage rather than preventing it. For hydrocarbon applications, hardfacing materials must be chosen with full consideration of the pumped fluid, operating temperature, and corrosion mechanisms.
Pump speed: balancing size, cost, and wear
Figure 1. Chrome oxide coating applied to a vertical pump shaft bearing journal.
Figure 2. Chrome oxide coating on a vertical pump bearing journal at pump disassembly.
Running speed is another area where short-term savings can lead to long-term cost. Higher-speed pumps can deliver required flow and head from a smaller package, often reducing initial capital cost. However, increased speed typically results in higher wear rates, shorter MTBR, and more frequent repairs. In abrasive and corrosive hydrocarbon services, slower-running pumps often provide better long-term value. Reduced speed lowers wear on internal components, seals, and bearings, improving reliability and extending service intervals. Selecting a motor with embedded variable speed intelligence can add an additional layer of flexibility by eliminating inefficient, failure-prone systems that rely on throttled valves and dampers. By allowing operators to adjust the speed to match process conditions, this type of motor can reduce unnecessary wear while maintaining performance. Variable speed control can also help mitigate transient conditions, such as start-up or process fluctuations, that contribute to accelerated wear. This type of motor can play a significant role in reducing lifecycle cost by improving reliability, reducing maintenance frequency, and utilising existing floor space. For example, a major processing facility was operating a fixed-speed pump controlled by a throttled discharge valve that remained significantly closed during normal operation. The restriction created unnecessary energy consumption, elevated noise levels, and added mechanical stress to pump components. To address these issues, the facility implemented a motor with integrated variable speed intelligence, allowing the discharge valve to be opened fully while reducing pump speed to match actual process demand. After the change, the facility reported a substantial reduction in annual energy consumption along with significantly lower operating noise. By eliminating continuous throttling and lowering operating speed, the system reduced wasted energy and minimised unnecessary mechanical loading on the pump. The result was improved operating efficiency and a configuration that was better aligned with long-term reliability and lifecycle cost objectives.
Sump design: identifying easy-to-fix issues
Figure 3. Chrome oxide coating on a vertical pump bearing journal running against a chrome oxide coated bushing at pump assembly.
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Unlike the other topics covered in this article, this section is not about the pump design, but making sure that adverse conditions are not allowed to keep the pump from operating at its design conditions. This topic is also most important for vertical pumps in an open sump, because there is no piping leading into them to help provide smooth laminar flow. Hydraulic Institute provides very good guidance on sump design (HI 9.8-2024) but it also cautions that a physical model study should be performed on structures if certain conditions cannot be met, or if the flow rates of the pump station are high (HI 9.8.7.1).
A physical model study is a scale model of the pump station built and tested to identify unfavourable flow conditions that will adversely affect the pump performance or life. While performing this upfront does carry a cost, performing it after a sump has been completed and issues are identified carries a much greater cost. This is because the model study will need to be completed, then the modification identified will need to be put in place, extending the project and incurring additional costs. For example, a mid-western US customer had a sump inlet off of a river housing five pumps. The pumps in the station performed poorly and had high vibration. A physical model study was performed and large amounts of flow separation, pre-swirl, and subsurface vortexes were identified at all pumps in the pump station. After testing multiple solutions in the physical model, including fillets, splitters, and floor cones, a flow conditioning basket was found to provide smooth laminar flow into the pump. Flow conditioning baskets were made for all the pumps to correct the issues. This was a simple modification, but that is not always the case.
Designing for lifecycle cost There are situations where a low-cost pump must be purchased due to budget or project constraints. However, in abrasive and corrosive hydrocarbon services, it is important to consider how much more a bare-bones pump may ultimately cost over its operating life. Short MTBR, frequent repairs, extended downtime, and increased maintenance exposure can quickly outweigh
Figure 4. Packing wear on a pump shaft (left) and packing wear on a pump shaft sleeve (right). initial savings. Design decisions made during specification – materials, wear components, hardfacing, and operating speed – often determine whether a pump delivers long-term reliability or becomes a recurring maintenance challenge. By adopting a lifecycle-focused approach during pump selection, owner-operators can improve reliability, reduce downtime, and achieve lower total cost of ownership in demanding hydrocarbon applications.
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Luc Vernhes, Mike Jacobs, and Duke Tran, Velan Inc., explain how innovations in steam purge optimisation and digital integration are helping to advance the reliability and profitability of delayed coker units.
P
ersistent challenges in delayed coker unit (DCU) valves include fouling, abrasive coke fines, extreme thermal cycling, and the severe mechanical demands of switching and isolation. Significant research has been dedicated to solving these challenges. This article presents recent innovations in steam purge optimisation and digitalisation, and examines market drivers such as needle coke production that are influencing the next generation of coker valve designs.
The role of valves in the delayed coking process Delayed coking is a thermal cracking process that was first introduced in 1929 to convert heavy residual oil from atmospheric or vacuum distillation units into lighter, higher-value products such as naphtha, diesel, gas oils, and solid petroleum coke. The process runs in a semi-batch cycle where one coke drum is filled with hot resid at temperatures up to 1000°F (538°C) while another is offline for decoking. A switch valve directs feed between drums, while isolation valves control heaters, overhead vapour,
blowdown lines, quench lines, bypasses, and drain lines. DCU valves face low to moderate pressures (15 to 50 psi), extreme thermal swings, high coke solids loading, frequent cycling (≈12-hour drum cycles), and stringent uptime demands, where failures can cost millions of dollars in unplanned shutdowns. Table 1 presents a range of DCU valves and their use.
Innovating for the future The first electrically operated metal-seated ball valves from Velan entered the DCU market in 1984. Prior to that, the sector was dominated by plug valves, which are still being regularly replaced by ball valves to enhance reliability and reduce turnaround time. Ball valves include a number of features that are engineered for long-term reliability and simple maintenance: n One-piece ball-and-stem to prevent separation between ball and stem, avoid solids ingress, and ensure precise operation with reduced hysteresis. n Replaceable scraper-type seats, hardfaced for extended life, to remove coke deposits each cycle. HYDROCARBON 55
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n High strength and corrosion resistant Inconel bellows to maintain seat-to-ball contact across thermal cycles. n Steam purge system with multiple purge points to keep coke fines from fouling seats and bellows. n Stem coupling protection with sacrificial coupling that yields under overload, protecting the main assembly. In 1995, Velan launched the patented backpressure control ring valve, initiating a series of subsequent milestones including the introduction of the first programmable logic controller (PLC)-driven, fully interlocked switch valve systems in 2001, and IIoT-enabled online valve monitoring in 2020. The coker market is now mature, with customers increasingly focused on enhancing reliability and reducing operational costs, including steam consumption. At the same time, the industry is placing greater emphasis on lowering its carbon footprint. For valves, most emissions arise during operation, not manufacturing, primarily due to the risk of leakage from seats, packing, or gaskets, which leads to both financial losses and environmental impact. It is increasingly important for valve manufacturers to work closely with key partners and customers to produce environmentally friendly valves that are robust, reliable, and which can be refurbished after decades of service.
Table 1. Delayed coker unit (DCU) valves and
uses Valve
Use
Four-way diverter (switch) valves
Route hot resid to the active drum or bypass lines
Steam-purged isolation valves
Isolate heaters, drums, and process lines while preventing coke build-up
Ring-type backpressure control valves
Regulate drum vapour overhead pressure
Hydrodrill ball valves
Handle high-pressure water used for decoking
Piston valves
Provide on-demand, reliable draining capability
Integrated monitoring system
Monitor individual valve performance in real time
PLC and control panels
Orchestrate operations, ensuring safety and reliability
Purge upgrade for isolation valves In demanding applications like delayed coking, steam purging plays a critical role in ensuring valve performance (Figure 1). However, it comes at a cost – namely, steam consumption. Operators often face a trade-off between maintaining a high purge flow rate to keep valves clean, and reducing flow to minimise energy usage and operational expenses. Steam purge upgrades are designed to optimise this balance through both improved purge flow and enhanced hardware. Velan’s new purging strategy increases purging efficiency, enhancing valve reliability and longevity while significantly reducing overall steam consumption. In addition, integrated design features such as integral purge flanges can simplify maintenance and refurbishment activities.
Unique purge flow logics
Velan’s purging system offers intermittent flow behaviour. The steam purge remains pressurised at all times yet the flow is typically dormant, trapped between the bellows-loaded seats. Only Bellows ID purge flows when the valve is open. Purge flow activates only during valve cycling and ceases once the valve reaches a fully open or fully closed position. This results in a concentrated steam burst during cycling, effectively cleaning critical areas while minimising overall steam consumption.
Integral flange integration
A key innovation in Velan’s purge system is the transition from socket-welded connections to integral flanges. This upgrade reduces production time and improves field repairability by eliminating several critical manufacturing steps, including welding and post-weld heat treatment. Integral flanges also offer excellent mechanical integrity and a gap-free arrangement that mitigates the risk of crevice corrosion.
Three keys of purging strategy Velan is also introducing a new purging strategy built on three core principles: directional, intermittent, and intentional purging.
Directional purging
Typically, purge flows are directed at a 90° angle, perpendicular to the components being flushed, e.g. ball purge to ball,
Figure 1. An example of fouling from coke fines due to improper purging.
September 2026 56 HYDROCARBON ENGINEERING
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Optional drain valve
(A)
The company’s design philosophy prioritises evacuating debris through the waterway during normal valve cycling. However, in the most severe applications, such as throttling, drains can provide additional flushing capability. Conventional drains typically require continuous steam to prevent plugging, which can be costly and operationally challenging. To address this, an optional drain valve can be positioned at the bottom of the body, opposite the new purge port. This drain incorporates a piston valve with a seat located at the extreme end of the body cavity. When closed, it eliminates any cavity for coke buildup, ensuring a clean internal profile. Operators can open the drain for approximately 30 minutes after cycling the main valve to flush the cavity and remove residual coke deposits. Once flushing is complete, the drain can be closed, restoring dormant purging in the ball cavity. The drain valve can also be automated via the control panel and PLC for systematic flushing operations.
Design for easy maintenance (B)
Figure 2. Comparison of purge flow configurations: (a) purge flow with the original top-body purge port, (b) purge flow with the new second tangential bottom-body purge port.
bellows purge to bellows. Based on field experience, the company has shifted to tangential purging to direct purge flows downward, targeting areas where coke tends to accumulate particularly at the bottom of the ball and bellows. The company has also introduced an optional second body purge port at the bottom of the valve (Figure 2). Previously, purge was applied only from the top. This new configuration enables a looping flow of steam around the ball, enhancing cleaning during valve cycling. The lower body purge is specifically located above debris accumulation, preventing plugging traditionally witnessed with bottom 6 o’clock positions. To ensure full interchangeability, the upgraded valves maintain a single connection point via a manifold.
Intermittent purging
While continuous purge under pressure has been the standard, Velan now recommends selective purge shutoff for valves in medium coking service. Specifically, the purge at the bellows ID, active only when the valve is open, can be shut off to reduce steam consumption. This offers a practical solution for customers aiming to optimise energy usage without compromising valve reliability.
Intentional purging
It is also possible to offer more customisability of purge configurations based on valve location and service severity. For example, valves located high in the coking system or on the top deck may not require purge at all, yet these were purged by default previously. There is now the option to install a blind flange on the purge ports on such valves to further economise steam usage. September 2026 58 HYDROCARBON ENGINEERING
In order to ensure that products are easier to maintain in the field, Velan valves feature specially designed studs with the bottom threads removed in line with ASME PCC-2 guidelines. This prevents interference with damaged threads at the bottom of tapped holes. Applicable to centre body and integral flanges, these studs are typically 0.5 in. longer than standard, requiring new studs for installation. When combined with the use of an anti-seize lubricant, the improvement ensures easy removal during future maintenance, simplifying refurbishment and reducing downtime. In addition, the valve is designed with field-replaceable seats, further improving maintainability and eliminating the complex repairs often associated with integral-seat designs.
Digitalisation and control integration The latest digital integration links information such as valve position, torque, steam purge flow, and maintenance schedules onto a unified platform. Key functions include: n Steam purge monitoring with alarms. n Valve position and torque trending to detect emerging mechanical issues. n Steam consumption tracking for utility optimisation. n Maintenance scheduling based on operating data. n Electronic documentation database for parts, drawings, and service records. These systems improve reliability and can help refiners plan turnarounds more effectively, reducing downtime and associated costs (Figure 3).
Real-time monitoring for reliability An integrated monitoring system offers a reliability enhancement. If purge flow is lost, operators receive real-time alerts, allowing them to take corrective action before coke buildup compromises valve operation. This helps prevent costly unplanned shutdowns and ensures consistent performance in demanding environments. This system also enhances position monitoring accuracy for critical switching and isolation valves in the DCU. For switching valves, it provides full 360° position feedback, compared to typical systems that only track six discrete positions.
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converting DCUs to produce needle coke, a premium product worth up to 10 times more than conventional petroleum coke. Conversion impacts valve design. For example, drum pressures increase substantially, requiring stronger actuators, larger stems, and new high-pressure-drop ring valves to protect downstream fractionators. Velan is developing and testing advanced ring valve designs validated by computational fluid dynamics (CFD), and full-scale flow loop testing in Montreal, Canada, to meet these new service demands.
Figure 3. Factory Acceptance Test preparation for a complete automated control system supplied for a DCU. The centralised PLC system (shown in the back), equipped with touch-screen interfaces and connected to multiple field control panels (shown in the front), is engineered to ensure a consistent sequence of operations, improving both safety and reliability during operations. This continuous monitoring enables DCU operators to accurately measure valve cycle speed, allowing better process control of heat transfer during valve switching.
Market drivers for innovation – needle coke production Growing demand for electric vehicle batteries and graphite electrodes for electric arc furnaces is driving interest in
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Conclusion Delayed coker valves operate at the intersection of mechanical endurance, process efficiency, and operational risk. The consequences of a valve failure, such as lost production, unplanned shutdown, and safety hazards, are measured in millions of dollars per incident. Innovations in steam purge optimisation, digital integration, and application-specific designs for emerging markets such as needle coke represent not just incremental improvements, but significant advances in DCU reliability and profitability. As refiners confront evolving market demands and operational constraints, the valve manufacturer’s role is shifting from that of an equipment supplier to a process reliability partner. It is essential that valve manufacturers remain committed to developing the technologies, services, and global support needed to keep the world’s cokers running at peak performance.
I
Seema Gangatirkar, Greene Tweed, discusses how metal spring-energised seals deliver improved reliability and performance in extreme environments.
n industries where failure is not an option, seal selection is a critical design decision. For decades, sectors such as refining, gas processing, and petrochemical plants have relied on elastomeric seals due to their flexibility, low cost, and ease of installation. In many applications, they perform reliably. However, as industrial applications push toward more extreme operating envelopes, they need seals that can operate beyond the practical limits of elastomers. Fluid handling or processing applications demand reliable sealing under conditions that could include one or more severe conditions, such as cryogenic temperatures, high pressures, aggressive or mixed chemistries, or rapid pressure cycling. In these environments, elastomers may harden or become brittle at low temperatures, degrade chemically, suffer compression set, or fail due to rapid gas decompression (RGD). These failure modes can lead to leakage, unplanned downtime, and costly maintenance.
To address these challenges, metal spring energised seals (MSEs) offer a proven alternative. By combining a thermoplastic jacket with an internal metal spring, MSEs are engineered to deliver consistent sealing force across wide temperature and pressure ranges, where traditional elastomeric solutions fall short. First developed in the 1950s, MSEs have a long track record in critical service applications where reliability, longevity, and resistance to tough conditions are essential. Today, MSEs are widely used in demanding applications, from Formula 1 race cars to deepwater oil and gas wells to cryogenic processing equipment, where sealing performance must be maintained for years with limited system access. Their ability to be customised through material selection, spring configuration, and jacket geometry allows sealing experts, such as Greene Tweed, to design application-specific sealing solutions for some of the most challenging environments encountered in modern industry. HYDROCARBON 61
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When to use MSEs MSEs are commonly selected after elastomeric seals reach their performance limits, for conditions including: n Cryogenic temperatures: MSEs maintain reliable sealing performance at temperatures well below -60°F (-52°C), where elastomers often harden and become brittle. n High pressure environments: depending on design and backup ring support, MSEs can withstand pressures up to 19 000 psi (1310 bar) and, in some cases, as high as 30 000 psi (2068 bar), making them ideal for demanding oil and gas applications. n Rapid gas decompression (RGD) environments: thermoplastic jackets are usually much less vulnerable to gas absorption and RGD, which reduces the risk of this failure mode during pressure release. n Compression set challenges: the internal springs maintain sealing force through pressure cycling, minimising compression set issues. n Mixed or aggressive chemistries: the combination of thermoplastic jackets and metal springs offers near universal chemical compatibility. n Dynamic applications: low-friction, wear-resistant jacket materials support reciprocating or rotary motion while limiting heat generation. Plastics, including formulas for optimised friction and wear performance, have a much lower coefficient of friction and wear resistance than most elastomers. n Hard to access installations: extended service life reduces maintenance needs in downhole, subsea, or enclosed systems.
Beyond performance advantages, MSEs offer a manufacturing edge. They can be machined from a blank shape vs requiring a specific mould like elastomeric seals need. This is a cost and flexibility advantage for low volume applications where tooling would be financially impractical or requires development of a new tool with associated long lead times.
MSE design fundamentals An MSE consists of a thermoplastic or polymer jacket that contains an internal metal spring. The spring provides a continuous energising force, while the jacket material provides the primary sealing interface with the hardware. For the seal to function properly, MSEs rely on two complementary sealing mechanisms: spring deflection and system pressure. The internal metal spring is installed with an initial compression, or squeeze, which provides immediate sealing force even at low or zero system pressure. This spring force ensures reliable sealing during startup, shutdown, and pressure transients. As system pressure increases, it enters the seal cavity and acts on the jacket lips, forcing them outward against the sealing surfaces. This pressure-energised action increases the contact force and expands the effective sealing footprint. As pressure rises, system pressure becomes the dominant contributor to sealing force, while the spring continues to provide a consistent baseline load. The combination of spring energisation and pressure assistance makes MSEs particularly effective in applications with pressure cycling, rapid depressurisation, or low-pressure gas sealing, conditions where elastomeric seals often struggle to maintain contact. MSEs can be designed for both static and dynamic applications and configured in a wide range of sizes and profiles. Spring and jacket materials can be customised to match specific operational conditions. Additionally, the range of spring configurations and jacket profiles can enable engineers to optimise performance for specific pressure, temperature, motion, and chemical exposure requirements.
Materials and design options Figure 1. Sealed pressure (∆P = P1 – P2).
MSE performance can be tailored by selecting appropriate materials and configurations. When end-users provide complete application details, such as temperature range, pressure profile, fluid chemistry, duty cycle (static or dynamic), surface finishes, and geometry, they enable sealing engineers to optimise MSE selection and design. This article will explore the key components of an MSE that can be customised:
Jacket materials Figure 2. Examples of geometries that can be configured depending on application.
September 2026 62 HYDROCARBON ENGINEERING
Material selection for jacket materials should account for wear, pressure, and
extrusion risk, particularly in dynamic or high load applications. Engineered plastics, both filled and unfilled, are often leading contenders for jacket materials. A few options are discussed below, but material determination will depend on final application operating parameters. This is where engineering consultation is critical to choose the right material and design for the specific application. Polytetrafluoroethylene (PTFE), a fluoropolymer, is one of the most popular choices for MSE jackets due to its chemical inertness, low friction, and broad temperature range spanning -450°F (-268°C) to 500°F (260°C). An unfilled PTFE jacket could be the default option for a static, low-pressure application. However, PTFE materials can often be enhanced with fillers for specific operational conditions such as wear or creep resistance, dry-run, or high-pressure situations. For example, glass-filled PTFE offers improved wear resistance and compressive strength, as well as low creep relaxation, and can be a good choice for high pressure and high temperature applications. Adding graphite to PTFE offers improved wear resistance and lubricity. Another thermoplastic fluoropolymer, polychlorotrifluoroethylene (PCTFE), provides improved performance in cryogenic applications, with a bottom operating temperature of -400°F (-240°C). PCTFE has excellent chemical resistance and low moisture absorption. It offers high tensile strength and good performance in applications exposed to radiation, such as those found in the nuclear industry. Polyether ether ketone (PEEK), a high strength thermoplastic with nearly universal chemical compatibility, is another option to consider for an MSE jacket. PEEK can generally be considered for applications where high mechanical loads or high temperatures are required. For example, in a high temperature static application, a jacket manufactured from a cross-linked PEEK such as Arlon 3000XT®, can offer a Tg improvement of 35°F (20°C) higher than PEEK and provides excellent mechanical property retention from 350°F (177°C) to 600°F (315°C). Fillers such as carbon or glass can also provide additional properties that may be applicable depending on operational conditions.
Spring materials
The spring provides the necessary energising force to the jacket once installed within the gland. Many spring materials are available. Options include stainless steel, Hastelloy®, Elgiloy®, and Inconel®, with selection based on corrosion resistance, temperature range, and fatigue life. Stainless steel is selected frequently as a well-rounded performer but more exotic options such as Eligloy can be chosen when corrosion from H2S, chlorides, or strong acids is a concern or in high temperature applications. Inconel is another option to consider for high temperature applications, while Hastelloy may offer good protection in aggressive fluids.
Spring configurations
In addition to material selection, multiple spring configurations are available to optimise performance for specific applications. For example, coil, finger, and canted coil springs offer different energisation characteristics for
Figure 3. Typical spring configurations used in MSE seals. static sealing, dynamic motion, and low-pressure gas service. However, metal choice may also dictate which configuration of spring is available. A coil spring, which offers some stretch, may be used for a static application, while a finger spring might be a good choice in a dynamic application. Canted coil springs can provide a more consistent sealing force even in low pressure applications.
Jacket geometries
Designs may include scraper lips, extended heels, or face seal profiles to address abrasive media, high pressure, or static applications. MSEs can also be incorporated into multi-element seal stacks, providing protection against compression set. It is also possible to consider MSEs in retrofit applications, as they can be customised to fit within existing O-ring glands; however, open or two-piece glands are generally recommended to simplify installation and protect the internal spring during assembly. Hardware surface finish may also be a key consideration when evaluating an MSE for a retrofit situation. The above information offers general guidelines for material and configuration selection. Consulting with a seal engineer would provide the best recommendation for a specific application.
MSEs prevent rapid gas decompression in a hydrogen compressor Rapid gas decompression is a common failure mode for elastomeric seals in high pressure gas service, particularly in hydrogen applications where small gas molecules readily permeate elastomers and expand rapidly during pressure drops. A refinery in the Middle East required a sealing solution for the outer casing of a centrifugal compressor used in a hydrocracking unit. The compressor operated at temperatures up to 392°F (200°C), differential pressures of approximately 215 bar (3100 psi), and a gas composition of approximately 94% hydrogen with hydrogen sulfide (H2S). Under these conditions, the compressor was experiencing downtime due to rapid gas decompression (RGD)-related failures. Both an elastomeric solution and an MSE were evaluated. After testing, Greene Tweed’s MSE was selected, HYDROCARBON 63
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as its PTFE jacket resists gas absorption, unlike elastomers, essentially eliminating the failure risk due to RGD. After installation, the compressor has operated for more than 10 years without reporting an RGD failure. The OEM compressor has continued to install MSEs in its new build compressors for high pressure situations. This example demonstrates why PTFE jacketed metal spring energised seals are an effective alternative to elastomeric seals in a high-pressure hydrogen service, because they do not absorb gas and can ensure reliable sealing even when pressure changes quickly.
the trial. The seal was subjected to a 500-hour endurance test (approximately 21 days of continuous operation). At the first-stage seal location, at a temperature of -424°F (-253°C), zero leakage was observed, and the second-stage seal also met the zero leakage requirements at -452°F (-269°C). Dynamic friction decreased from 5 kg to 2.6 kg following the test. This case demonstrates that PTFE-jacketed MSEs can deliver both a zero leakage and low-friction seal in a challenging cryogenic and dynamic application, conditions where elastomers would not perform as well.
Zero leakage in a cryogenic helium pump at -452°F (-269°C)
Key takeaways
Cryogenic temperatures pose a significant challenge for elastomeric seals, which can become brittle and stiff, leading to a loss of seal functionality and decreased ability to handle dynamic movement as temperatures drop. Thermoplastic materials, such as PTFE, when combined with spring energisation, maintain stable sealing performance across cryogenic temperature ranges. A global chemical company required a piston type seal for a cryogenic helium pump operating at temperatures as low as -423°F (-253°C), with pressures ranging from 71 - 327 psi (5 - 22 bar). The application required more than 1.5 years of service life, minimal friction, and zero leakage in a dynamic environment. An MSE, designed by Greene Tweed with an Elgiloy® spring and a carbon-filled PTFE jacket, was selected for
MSEs serve as an enabling technology by delivering reliable, long-lasting performance in environments that exceed the limits of elastomeric seals. By providing reliable, long-lasting performance under extreme temperatures, high pressures, aggressive chemistries, dynamic motion, and pressure cycling, MSEs offer a strong solution for applications operating at the edge of performance. Engineers can minimise leakage, extend service life, and improve equipment uptime by selecting the right combination of jacket material, spring material and configuration, and seal geometry. Real-world examples shared here confirm that MSEs provide a robust sealing solution designed to maintain reliability under the most demanding conditions.
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