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CONTENTS January 2026 Volume 31 Number 1 ISSN 1468-9340
03 Comment
39 Improving delayed coker unit margin
05 News 08 The rollercoaster ride of ‘25 Alan Gelder, Wood Mackenzie, UK, reflects on the turbulence the downstream sector faced throughout 2025, with a particular focus on dynamics of markets in surplus for the year ahead.
16 China’s sustainable methanol surge As China scales up renewable power at a record pace, Sean Xiong, Johnson Matthey, China, considers the development of sustainable methanol production that is emerging as a central pillar of its energy transformation and a potential blueprint for global decarbonisation.
21 Readying renewable diesel Jim Aiello, Merichem Technologies, examines the role that renewable diesel could play in the shift to cleaner transportation fuels, alongside an exploration of desulfurisation technology.
27 Simplifying sulfiding Traditional sulfiding agents pose operational challenges as well as health and safety risks for operators in the sulfiding process. Jennifer Jackson, Lubrizol, USA, considers how alternative agents may provide a better solution for refiners.
31 Modern water management C. Senthilkumar, VA Tech WABAG Ltd, India, explores principles, best practices, and opportunities for recycling and reuse within water management for refineries and petrochemical plants.
35 Bridging the skills gap Heiko Petersen, ABB Energy Industries, explores how AI and automation are reshaping the energy industry through addressing workforce challenges, while creating opportunities to attract new talent into energy operations.
Jitendra Chellani and Secil Uzun, KBC (A Yokogawa Company), alongside Mohammad Al-Johar and Saravanakumar Chidambaram, SATORP, explore solutions to optimise delayed coker units by increasing throughput and higher-value yields.
43 From diagnostics to decision-making Fabio Pires and Andy Phillips, Tracerco, consider how advances in digital platforms and the rise of remote expert teams are enabling refiners to reduce downtime, improve safety, and unlock new efficiencies.
47 Pathways to net zero Pascal Gaillot, Yokogawa Europe, explores how process automation, advanced instrumentation, and digital tools can aid the downstream sector on its journey toward net zero.
50 The end of the efficiency plateau Dave Denison, Emerson, considers how hydrocarbon organisations can utilise centralised, cloud-enabled engineering tools to replicate best practices across sites, simplify troubleshooting and configuration maintenance workflows, while capturing enterprise-level performance gains.
55 Next-generation emissions control José Miguel González, TECAM, Spain, explores how emissions control systems can align with emerging trends across the hydrocarbon processing sector, to ensure optimised and sustainable operations.
59 Proactive planning Ed Everett, Castlet, UK, explores how planned maintenance on electrostatic precipitators and their power control systems can minimise disruption across oil refining and petrochemical operations, ensuring efficiency and cost optimisation.
63 Fine-tuning flaring Lenny Shaver, Advanced Energy, and Mike Schoneman, Speed Valve & Specialty, offer a technical analysis of long-wave infrared imaging (LWIR) systems for flare pilot verification and assist gas reduction.
67 Catalyst review
Hydrocarbon Engineering showcases a selection of the most advanced catalyst services and technologies that are available to the downstream sector today.
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T
he US’ recent military action against Venezuela suggests that 2026 is unlikely to be any calmer than the year just passed. The intervention creates further geopolitical uncertainty following a tumultuous 2025, and has exposed risks in the energy sector. In a press note from 6 January, Wood Mackenzie said that the removal of Nicolás Maduro from Venezuela’s presidency creates near-term downside risk for oil prices while presenting longer-term uncertainties for upstream investment. Any easing of US sanctions could add barrels to an already oversupplied market, potentially driving Brent below the mid-to-high US$50/bbl levels predicted for 1Q26.1 President Trump has said that the US “will run” Venezuela until a “safe, proper and judicious transition” can be ensured, and has vowed to tap into the country’s vast oil reserves, indicating that US oil companies would fix Venezuela’s “broken infrastructure” and “start making money for the country.” However, there are significant doubts surrounding how quickly production could ramp up, with experts warning of huge challenges and enormous costs. Alan Gelder, SVP Refining, Chemicals and Oil Markets at Wood Mackenzie, recently commented: “Venezuela offers the scale major producers need, but the fundamentals work against rapid deployment. Heavy crude economics at current prices, unresolved legal claims, and political uncertainty create a risk profile that extends well beyond typical above-ground challenges. Companies will watch, but commitments require more than sanctions relief.” Refiners on the US Gulf Coast could be the early winners. Their facilities – originally built to handle heavy crude from the likes of Venezuela and Mexico, before the US shale revolution – are well positioned to welcome shipments once sanctions are lifted and import permits are granted. On Monday 5 January, two days after the US strikes on Venezuela, shares in America’s top refining groups jumped. Valero Energy – the biggest importer of Venezuelan crude – closed 9% higher, while Phillips 66 added 7% and Marathon Petroleum 6%.2 However, Wood Mackenzie warns that a return to historical refinery throughput and product export levels poses risk to Atlantic Basin refiners – particularly in Europe – given the competitive positioning that Venezuelan refineries once held. Developments in Latin America are just one of the many factors shaping the year ahead. In this month’s keynote article, Wood Mackenzie’s Alan Gelder shares his outlook for the downstream sector in 2026 and highlights several key issues likely to influence the market. Although his article was prepared prior to the US’ recent actions in Venezuela, Alan accurately identifies the brewing conflict as a critical consideration to keep an eye on, alongside the country’s policies towards Iran. Global economic growth, OPEC+ behaviour, and the Russia/Ukraine conflict also feature prominently among the many things to watch out for in the year ahead. Turn to page 8 to read Alan’s thoughts in full. 1. 2.
‘What the Venezuela regime change means for oil production, crude and product markets’, Wood Mackenzie, (6 January 2026). MCCORMICK, M., ‘US oil refiners gear up for comeback of Venezuelan crude’, Financial Times, (5 January 2026).
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WORLD NEWS UK | Phillips 66 Ltd agrees to acquire
Lindsey Oil Refinery assets
P
hillips 66 Ltd has agreed to acquire Lindsey Oil Refinery assets and associated infrastructure pending completion subject to satisfaction of closing conditions, including customary regulatory clearances. The announcement follows a bidding process handled by FTI Consulting, who began serving as special managers of the Lindsey Oil Refinery assets after the Official Receiver was appointed liquidator in June 2025. The company also announced that it plans to integrate key assets into its
Humber Refinery operations. Following a thorough assessment undertaken during the bid process, the company has decided to not restart standalone refinery operations at the Lindsey Oil Refinery. Due to the limitations of its scale, facilities, and capabilities, evaluations have shown that the refinery is not viable in its current form. Phillips 66 Ltd is also investing in a multi-year project at its Humber site that will enable production of higher-quality gasoline.
Saudi Arabia | Samref refinery set for upgrade
E
xxonMobil, Aramco, and Samref have signed a venture framework agreement (VFA) to evaluate a significant upgrade of the Samref refinery, in Yanbu, Saudi Arabia, and an expansion of the facility into an integrated petrochemical complex. The companies will explore capital investments to upgrade and diversify production, including high-quality distillates that result in lower emissions and high-performance chemicals, as well as opportunities to improve the refinery and reduce emissions from operations through an
integrated emissions-reduction strategy. The companies will commence a preliminary front-end engineering and design (FEED) phase for the proposed project, which would aim to maximise operational advantages, enhance Samref’s competitiveness, and help to meet growing demand for high-quality petrochemical products in the Kingdom. Plans are subject to market conditions, regulatory approvals, and final investment decisions by Aramco and ExxonMobil.
Global | Crude oil prices
fell in 2025 amid oversupply
T
he US Energy Information Administration (EIA) has reported that crude oil prices generally declined in 2025 with supplies in the global crude oil market exceeding demand. Crude oil inventory builds in China muted some of the price decline. Events such as Israel’s 13 June strikes on Iran and attacks between Russia and Ukraine that targeted oil infrastructure periodically supported prices. On a monthly average basis, the price of Brent crude oil declined from a high of US$79/bbl in January to a low of US$63/bbl in December, which was the lowest monthly average price since early 2021. The annual average price was US$69/bbl, the lowest since 2020, even when adjusting for inflation. In 1H25, crude oil prices declined in response to slowing economic activity, which can affect global oil demand. Prices decreased in 1Q25 with a contraction in US GDP, and prices fell nearly US$15/bbl further in April amid expectations that escalating tariffs among large economies could continue to slow economic growth.
Croatia | INA completes construction of systems for new refinery unit
T
he Rijeka refinery upgrade project has entered its final phase of implementation. Construction works on the key systems of the new processing units (including the delayed coker unit and the new port) have been completed, and comprehensive inspections and testing activities are currently underway as a prerequisite for hot commissioning and full operational readiness. The entire complex will be ready for commissioning in 1Q26.
The project includes the construction of a delayed coker unit, modernisation of existing units, as well as the development of a new port, storage siloes, an enclosed coke handling and transportation system, and a new high-capacity substation – the largest in Croatia – ensuring a reliable and secure power supply for the new facility. This extensive scope of technological, logistical, and
safety solutions represent a comprehensive transformation of the refinery complex into one of the most technologically advanced refining facilities in the region. The present final phase of pre-commissioning testing phase involves thorough technical and safety checks, system testing, and all procedures are required to obtain the operating permit and commence regular commercial production at full capacity.
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January 2026
WORLD NEWS DIARY DATES 02 - 05 February 2026 21st International Conference & Exhibition on Liquefied Natural Gas (LNG2026) Doha, Qatar www.lng2026.com
10 - 12 February 2026 NARTC Houston, Texas, USA worldrefiningassociation.com/event-events/nartc
17 - 20 February 2026 Laurance Reid Gas Conditioning Conference Norman, Oklahoma, USA www.ou.edu/pacs/lrgcc
24 - 27 February 2026 ESF Europe: Energy & Sustainability Forum Antwerp, Belgium https://europetro.com/esfeurope
15 - 17 March 2026 AFPM Annual Meeting New Orleans, Louisiana, USA www.afpm.org/events
15 - 19 March 2026 AMPP Annual Conference + Expo Houston Texas, USA ace.ampp.org
29 - 31 March 2026 AFPM International Petrochemical Conference San Antonio, Texas, USA www.afpm.org/events
28 - 30 April 2026 Sulphur World Symposium Vancouver, British Columbia, Canada www.sulphurinstitute.org/symposium-2026
19 - 21 May 2026 Asia Turbomachinery & Pump Symposium Kuala Lumpur, Malaysia atps.tamu.edu
09 - 11 June 2026 Global Energy Show Canada Calgary, Alberta, Canada www.globalenergyshow.com
14 - 17 September 2026 Gastech Bangkok, Thailand www.gastechevent.com
January 2026
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India | HPCL commissions upgrades to Visakh
Refinery
H
industan Petroleum Corp. Ltd (HPCL) has commissioned the Residue Upgradation Facility (RUF) at its Visakh Refinery, India, marking a major milestone in India’s deep-conversion refining capability and contributing to national energy security. Aligning fully with the Prime Minister’s vision of Aatmanirbhar Bharat, several critical project equipment were indigenously manufactured, thereby
strengthening India’s refining self-reliance. This facility showcases engineering scale, housing among the world’s heaviest three LC-Max reactors of approximately 2200 t each. With a capacity of 3.55 million tpy, the RUF employs advanced LC-Max based residue hydrocracking technology to achieve approximately 93% conversion of bottom oils into high-value products.
Global | BP to sell 65% shareholding in Castrol
B
P has reached an agreement to sell a 65% shareholding in Castrol to Stonepeak, at an enterprise value of US$10.1 billion. This represents an implied EV/LTM EBITDA of approximately 8.6 times, reflecting the strength of the business and future growth potential. The transaction represents a significant milestone in BP’s commitment to accelerate its strategy, including simplifying the portfolio, strengthening the balance sheet, and focusing the downstream on its leading integrated businesses.
The transaction is expected to result in total net proceeds to BP of approximately US$6 billion, which includes around US$0.8 billion for the pre-payment of future dividend income over the short to medium-term on BP’s retained 35% stake and other adjustments. The implied total equity value of Castrol is US$8 billion after deducting JV minority interests totalling US$1.8 billion, and other debt-like obligations of around US$0.3 billion, and subject to customary adjustments.
India | Technip Energies awarded two large
contracts by BPCL
T
echnip Energies has been awarded two large contracts by Bharat Petroleum Corp. Ltd (BPCL) for key projects at its Bina refinery in Madhya Pradesh and Mumbai refinery in Maharashtra, India. The first contract covers engineering, procurement, construction, and commissioning (EPCC) for new polypropylene and Butene-1 units at the Bina refinery in Madhya Pradesh. The units will produce 550 000 tpy of polypropylene and 50 000 tpy of Butene-1. This contract is part of BPCL’s Bina Petchem and Refinery Expansion
Project, encompassing refinery capacity increase as well as the construction of a new cracker and downstream petrochemical units. The second contract covers engineering, procurement and construction management (EPsCm) services for a 3 million tpy petro resid fluidised catalytic cracker unit (PRFCC) at the Mumbai Refinery in Maharashtra. This will be India’s first PRFCC unit, converting heavy refinery residues into lighter, higher-value products. The scope also includes auxiliary units along with associated offsites and utilities.
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Alan Gelder, Wood Mackenzie, UK, reflects on the turbulence the downstream sector faced throughout 2025, with a particular focus on dynamics of markets in surplus for the year ahead.
2
025 was a tumultuous year. The Russia and Ukraine conflict ground on, the Israel and Hamas conflict risked a regional conflagration in the summer, and the global economic order risked disruption from a tariff trade war. 2 April 2025 was ‘liberation day’ when the US announced sweeping tariffs on all of its trading partners. China retaliated swiftly, effectively decoupling the world’s two largest economies. Within a week, tariffs were paused but then re-introduced at lower levels late in the summer,
January 2026
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HYDROCARBON
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with trade tensions eased through bi-lateral negotiations. The global economy did not stall, with 2025 GDP growth matching 2024 levels, industrial production remaining resilient as trade was front-loaded to avoid sanctions. Despite this, global oil demand growth proved weak at only 800 000 bpd, a marked decline from the post-COVID recovery. This combination of weak oil demand and strong non-OPEC supply growth lead to oil price weakness.
The seasonality of global crude runs and China’s build in crude inventories enabled OPEC+ to fully unwind its tranche of 2.2 million bpd voluntary cuts across the summer and start on the 1.65 million bpd tranche in the autumn, with oil prices only declining from almost US$80/bbl to a low of US$60/bbl as shown in Figure 1. The oil price trajectory looks smooth, as OPEC had ample spare capacity to address any threat to supply loss. Unprecedented is a term used too often this year, but the industry witnessed the oil price falling as
Iranian missiles and drones were on route to strike US military sites in Qatar – a truly unprecedented event. Late in the year, US sanctions on Rosneft and Lukoil, along with threats of higher tariffs on countries processing Russian crude, provided support to the oil price, particularly for Dubai, as Indian refiners evaluated alternative sources of crude supply. Global refining will look back on 2025 with fondness as the margins surprised to the upside. 1Q25 performed as expected. 2Q25 margins crept up from
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January 2026
high maintenance, with global margins surging in 3Q and 4Q. This surge reflected low European diesel inventories, supply loss, and regulatory tightening, as Ukrainian drone strikes took over 1 million bpd of Russian refining capacity offline for September, October, and November, reducing diesel exports. Sanctions on Rosneft and Lukoil required exemptions for their European refining assets to be granted and the EU requirement that any product imports after mid-January are not sourced from Russian crude added a further dislocation to diesel prices, as trade flows reshuffled. Gasoline cracks were also stronger than expected due to the Dangote refinery’s continued struggle to stabilise the RFCC and operate the refinery at high rates. Petrochemical demand growth continued during 2025, representing about half of annual global oil demand growth. Despite that, steam cracker margins weakened in 2025 relative to 2024 as China’s capacity additions became operational. Petrochemical margins have worsened, prompting the closure of several sites across Europe and Japan, with Korea announcing a collaborative effort to reduce its installed steam cracking by 15% during 2026. This weak performance is across all petrochemical commodity value chains, reflecting weak demand growth and a surge of capacity additions, primarily in China.
2026: demand growth to disappoint
Wood Mackenzie’s economists are traditionalists in that tariffs are paid by the consumer and are grit in the wheels of trade, slowing global economic growth. 2025 global GDP growth matched 2024 levels, with this stronger-than-expected performance driven by businesses frontloading trade ahead of US tariff increases, China’s economic stimulus measures, temporary easing of tariffs between the US and China, and a capital expenditure boom in AI technology. However, Wood Mackenzie forecasts that growth will slow in 2026 as the impact of tariffs are felt by US consumers and China faces internal and external headwinds. It also posits that the US effective tariff rate peaked at around 25% during 2025 and will fall through 2026 and 2027 from new bilateral trade deals with the US, and trade flow optimisation will drive the easing in the effective tariff rate. The impact of weak global GDP growth is to keep 2026 global oil demand growth below 2025 levels at under 700 000 bpd, as shown in Figure 2. The key growth regions are ‘other Asia Pacific’ and India, both of which are forecast to grow less than 200 000 bpd annually. China’s oil demand growth is forecast to be weak as road transport fuels (gasoline and diesel) are in decline due to vehicle electrification (as EV’s represent almost 60% of new vehicle sales for passenger cars and LNG/EVs account for almost 40% of new commercial vehicle sales), with jet fuel and petrochemical feedstocks countering this decline. Jet is the transportation fuel with the highest forecast growth rate for 2026, as diesel/gasoil and fuel oil demand are forecast to Figure 1. Oil price, refining, and chemical margin 2024 to 2025 comparison. Source: remain broadly unchanged. Wood Mackenzie Macro Oils Service, Product Markets Service Short Term and Global Gasoline’s modest demand Ethylene Short Term Service. growth reflects slow economic growth in the US. Petrochemical feedstocks are the strongest drivers of oil demand growth, accounting for almost 80% of total oil demand growth in 2026, with LPG dominating naphtha given its forecast supply growth from upstream oil and Figure 2. Global oil demand growth, 2026. Source: Wood Mackenzie Macro Oils Service, natural gas Product Markets Service Short Term. production. January 2026 10 HYDROCARBON ENGINEERING
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Oil inventories to rise, weakening prices further Non-OPEC supply growth, as shown in Figure 3, is set to outpace global oil demand again in 2026. The growth is primarily from conventional projects in Latin America, led by Brazil and Guyana. The supply from conventional projects is independent of oil price, as production starts when the project completes. US tight oil production is the most flexible resource, but US tight oil supply is yet to show production decline in 2025, despite the rig count falling through the year. There is typically a six-to-nine-month time lag between changes in rig count and US tight oil production, so Wood Mackenzie is projecting US tight oil production to decline modestly in 2026. New project start-ups in the US Gulf of Mexico and
increases in Canada sustain overall production growth in North America. The implication of this supply overhang is that oil prices are to weaken further in 2026, with estimates that the 2025 annual average dated Brent oil price is to be US$69/bbl (an US$11/bbl drop from the 2024 annual average). For 2026, an annual average dated Brent price of just under US$60/bbl is projected, with 1Q26 to be the low point, with crude prices recovering as refinery runs increase to satisfy northern hemisphere seasonal demand growth. OPEC+’s recent decision to pause the unwinding of its production cuts is pragmatic, as the oil market does not require these additional volumes. In 2027, non-OPEC supply growth is outpaced by global oil demand growth, with US Lower 48 production in decline, which supports a modest price recovery.
2026 is the floor for refining margins
Figure 3. Annual regional non-OPEC supply growth. Source: Wood Mackenzie Macro Oils Service.
Figure 4. Net global CDU capacity additions
(thousands of bpd). Source: Wood Mackenzie Product Markets Service Short Term.
January 2026 12 HYDROCARBON ENGINEERING
Diesel crack spreads have already passed their peak and were starting to decline during December 2025, as European diesel inventories rebuild from greater imports from the Middle East and the US. The commercial performance of the refining sector is complex, given the different demand dynamics, supply/demand balances, and trade flows for gasoline, jet, diesel/gasoil, and fuel oil. However, at the highest level, global refinery utilisation trends provide an indication as to the aggregate performance of the refining sector. As shown in Figure 4, net global crude distillation unit (CDU) capacity additions for 2026 are forecast at almost 1 million bpd, largely due to projects in Asia and the Middle East achieving commercial production, which counter the modest closures in Europe and the US. This indicates that capacity additions modestly outpace global demand growth, so the refinery system utilisation should ease. Given that 2026 demand growth is dominated by petrochemical feedstocks, the tightness around satisfying transport fuel demand will certainly ease. There are, however, complicating factors, given that global inventories of transport fuels are relatively low, particularly for diesel/gas oil. With oil prices projected to weaken further during 1Q26, Wood Mackenzie is projecting the refining sector to run at higher than seasonally normal during that period to build product inventories, with low inventories supporting strong refining margins through 1Q. With the ramp up of the new projects in the Middle East and India during 1Q along with the return of the Dangote facility to normal operations after maintenance, refining margins are expected to normalise through the summer, as shown in Figure 5. The limited growth in demand for transport fuels and capacity additions result in margins moving to below the five-year average for 2H26. 2026 is projected to be the low point for the global refining industry, as there are limited capacity additions in 2027, whilst oil demand continues to rise.
Chemicals remain in the doldrums The chemicals sector is typically cyclical in terms of business results, with periods of high margins prompting too much capacity addition, thus weakening margins.
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Margins then recover as capacity additions slow, with the cycle then repeating every seven years or so. This time is profoundly different as China continues its wave of capacity additions, which far outpace demand growth. These investments come from the transition away from oil products to chemicals as China’s transport fuel declines. Ethylene capacity additions will continue to outpace demand growth for the next three years, preventing the typical cycle of margin trough and recovery. Any recovery is ‘L shaped’, so not quick, resulting in less competitive steam crackers being under threat of closure before 2030. Wood Mackenzie used several metrics to assess the closure risk of a site, such as its margin forecast, regional and national policy guidance, and its ownership/strategic importance, with the results shown in Figure 6. Globally, 27% of steam cracker capacity is at risk of closure, with Europe and Asia being the worst hit regions. In Asia, 11 million t of capacity is at risk of closure, with China to phase out small crackers that are over 20 years old. Northeast Asia ex-China remains the region that is most exposed to China’s growing self-sufficiency and decreasing ethylene monomer imports. Standalone assets and crackers without access to advantaged feedstocks face the greatest
Figure 5. Global composite refining margin, monthly (US$/bbl). Source: Wood Mackenzie Product Markets Service Short Term.
closure threat in South and Southeast Asia. In Europe, announced closures will shrink capacity by 12% in 2028 compared to 2024, with a further 13% of total capacity up for sale. A further 4 million t is categorised as high risk. The Americas region is relatively immune to rationalisation risk. For commodity chemical companies, 2026 is a year to survive, with the hope that rationalisation is something that happens to others.
What to watch The world is increasingly interconnected, so uncertainties around economic growth and geopolitical tensions ripple through the oil value chain. There are many things to consider, notably: n Global economic growth: could it be weaker than expected due to stalling investment in view of policy uncertainty, or does the US Supreme Court limit the potency of tariffs as a geopolitical weapon? Tariff escalation and a full-blown trade war is probably a tail risk, but cannot be entirely dismissed. n OPEC+ behaviour: does the group continue with its pragmatism, or does it decide to go for market share, or alternatively end production easing and return to deeper cuts to lift prices? n US policies with respect to Iran and Venezuela as does it: § Return to ‘maximum pressure’ on Iran to ensure it ends its nuclear programme? § Slip into conflict with Venezuela over US naval deployment in the Caribbean to counter maritime narcotics trafficking? n Russia and Ukraine conflict and Russian infrastructure outages: § Does Ukraine escalate attacks on Russian refineries and export terminals? § Could the US impose and enforce more stringent tariffs on buyers of Russian crude oil (China, India, and Turkey), which prompts India and/or China to reconsider their imports of Russian oil, so reducing global supply?
Figure 6. Global ethylene capacity at risk of closure. Source: Wood Mackenzie Global Ethylene Strategic Planning Outlook.
January 2026 14 HYDROCARBON ENGINEERING
The dynamics of surplus suggest lower oil prices in combination with weak refining and petrochemical margins. However, if the global economy can ‘keep calm and carry on’, the risk to prices and margins is to the upside from unanticipated losses of supply due to various events. Hope, however, is not a strategy, so market participants are advised to plan cautiously.
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As China scales up renewable power at a record pace, Sean Xiong, Johnson Matthey, China, considers the development of sustainable methanol production that is emerging as a central pillar of its energy transformation and a potential blueprint for global decarbonisation.
January 2026 16 HYDROCARBON ENGINEERING
I
n 2024, China added more than 430 GW of new power generation capacity, over 360 GW of which came from wind and solar sources. This extraordinary deployment confirms China’s position as one of the leading builders of renewable infrastructure. Yet the speed and scale of this transition have created new systemic challenges. Local grids, particularly in interior provinces such as Inner Mongolia, Gansu, and Qinghai, lack the interconnection and storage capacity to absorb surplus renewable output. To address this imbalance between generation and grid absorption, China is turning to Power-to-X technologies. The conversion of excess electricity into green hydrogen and subsequently into sustainable methanol is gaining momentum. This represents more than a technical fix. It reflects a strategic realignment that connects renewable power generation with industrial decarbonisation, grid flexibility, and international trade in fuel. Methanol is already a major part of China’s industrial landscape. The country is the
world’s largest producer and consumer of methanol, primarily derived from coal. The shift now underway involves substituting coal-based processes with low-carbon alternatives: bio-methanol made from biomass or waste, and e-methanol synthesised from green hydrogen and captured carbon dioxide. These routes can turn intermittent clean electricity into a stable, storable, and tradeable chemical fuel. Beyond its role as an energy carrier, methanol also plays a vital part in many downstream chemical value chains. In China’s petrochemical sector, it serves as a key feedstock for producing formaldehyde, acetic acid, and olefins through the methanol-to-olefins (MTO) process. These derivatives support the manufacture of plastics, synthetic fibres, and solvents. The logic of using methanol as an energy carrier is grounded in practical advantages. It can be stored easily as a liquid and transported using conventional methanol infrastructure. Methanol-capable ships are already in operation and, moreover, methanol
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serves not just as a fuel but also as a feedstock for producing other low-carbon chemicals. For regions with high renewable potential but limited transmission capacity, methanol offers a way to monetise surplus electrons and convert them into physical value.
Figure 1. CO2 to methanol process.
Policy acceleration and market formation China’s push toward sustainable methanol is supported by an increasingly sophisticated policy framework. National directives now explicitly promote the development of green methanol production and its integration with renewable power. The National Energy Administration’s guidance documents support the co-location of green hydrogen and methanol facilities at renewable energy bases. The Ministry of Industry and Information Technology continues to back methanol-powered vehicles and has revised regulations to promote supporting infrastructure and vehicle deployment. These policies are not isolated. They form part of a coordinated industrial strategy aimed at reaching peak carbon emissions by 2030 and carbon neutrality by 2060. Within this framework, sustainable methanol plays a dual role: it helps balance the power system while simultaneously decarbonising sectors such as shipping, transport, and downstream industries including petrochemicals and refining. In many cases, local governments are linking land access or clean power quotas to industrial offtake requirements, further encouraging the development of integrated methanol projects. China is already putting this strategy into practice. Several renewable energy hubs in interior regions are now hosting projects that combine wind and solar generation with water electrolysis and methanol synthesis. These vertically integrated sites allow producers to capture full value from renewable generation that would otherwise be curtailed. The model reduces reliance on long-distance electricity transmission and aligns with local economic development goals. The industrial appetite for green methanol is growing. In the maritime sector, methanol is becoming the fuel of choice for decarbonisation. By October 2025, there were 444 methanol dual fuelled vessels either in operation or on order, with demand being shaped by major operators including COSCO, Maersk, and CMA CGM. China’s position as a major port operator makes it a natural hub for clean marine fuel supply. On land, commercial deployment of methanol-powered trucks is accelerating, led by firms such as Geely, and supported by regional pilot zones and policy incentives.
Certification, export, and global linkages
Figure 2. Sustainable methanol offers solutions to many areas, from fuels to chemicals and plastics.
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Beyond domestic consumption, sustainable methanol also presents a major opportunity for cross-border trade. A notable recent example is the initiative by Hong Kong-based Towngas, which in 2025 signed a memorandum of understanding (MoU) with Golden Island Diesel Oil Trading Co. to supply green methanol for Singapore’s marine bunkering operations. The methanol will be sourced from Inner Mongolia, where Towngas is developing a renewable methanol facility integrated with local wind and solar power. This agreement marks a significant milestone as it positions China not only as a producer but also as a strategic exporter of green methanol in the Asia-Pacific region.
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The Towngas project is aligned with international climate frameworks, as Singapore seeks to decarbonise its maritime sector and establish itself as a hub for alternative marine fuels. Methanol’s compatibility with current bunkering infrastructure and shipping engines gives it a distinct advantage over other alternatives. The emergence of such export-oriented green methanol projects reflects a broader ambition. As energy systems globalise, the ability to convert local renewable surpluses into internationally tradeable energy carriers becomes a key strategic asset. Methanol sits at the intersection of energy and trade, enabling countries with high renewable potential to connect with fuel-importing regions such as Singapore, Japan, South Korea, and the EU. However, realising this potential will depend on resolving several open questions. Certification of
green methanol relies on clear, transparent, and verifiable data across multiple process steps. Projects must ensure that the CO2 used in methanol synthesis comes from renewable or biogenic sources rather than fossil point emissions to qualify as fully renewable. As the EU expands its mandates for clean fuel use across aviation, shipping, and industrial sectors, China’s ability to export certified green methanol could reshape international supply chains. Methanol’s compatibility with existing fuel logistics and storage infrastructure makes it a particularly attractive option for regions seeking to decarbonise without waiting for full electrification. For refineries and petrochemical complexes, blended methanol can complement renewable naphtha and hydrogen-based pathways, supporting low-carbon refinery operations and circular chemistry initiatives. China’s emerging position as a supplier of certified methanol also reflects a larger trend. Moreover, biomass feedstocks are limited in supply and increasingly in demand across other sectors. Allocating these resources efficiently will be essential to avoid unintended consequences or competing claims over sustainability.
A global systems perspective
Figure 3. The differences between eMethanol and bio-methanol.
Figure 4. Sustainable methanol plant.
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China’s approach to sustainable methanol offers useful insights for other countries navigating their own energy transitions. What stands out is the emphasis on systemic integration. Rather than treating renewable generation, hydrogen production, and fuel synthesis as discrete stages, China is building projects that span the entire value chain from power to molecule to market. This approach is not without challenges. It requires coordination across energy, industrial, and environmental agencies. It depends on local governments to implement and infrastructure rules. It demands investor confidence in long-term policy stability and offtake markets. But where the pieces align, the model delivers results at scale and speed. Importantly, China’s methanol initiatives are not solely focused on domestic goals. They reflect a broader ambition to shape global markets, standards, and supply chains for green fuels. This may accelerate the emergence of international fuel corridors, governed not just by energy resources but by the capacity to produce, certify, and export low-carbon molecules. For other countries with high renewable potential but limited grid flexibility, the Chinese example also demonstrates how low-carbon methanol production can be combined with refinery upgrading and petrochemical integration. This approach creates exportable value from renewable energy while reducing carbon intensity across the downstream chain. As energy transitions deepen, the importance of converting renewable power into stable, tradeable energy will only grow. Sustainable methanol is unlikely to be a universal solution, but it may become a foundational element of a new global energy system built not just on electrons, but on molecules that carry clean energy where it is needed most.
Jim Aiello, Merichem Technologies, examines the role that renewable diesel could play in the shift to cleaner transportation fuels, alongside an exploration of desulfurisation technology.
O
il and gas companies are increasing investments in renewable diesel, the drop-in fuel that can be used with no engine modifications. Although there is no single, easily accessible total number for renewable diesel refineries worldwide, as data is not centrally compiled, it is well-known that the US, Canada, and Europe are major centres for renewable diesel production, along with smaller operations in other countries.1 Some examples of production facilities include: n Chevron started production at a renewable diesel plant in Louisiana, US, to expand plant capacity from 7000 to 22 000 bpd.2 n CountryMark announced a US$100 million refinery upgrade to produce renewable diesel.3 n Renewable diesel production began at Strathcona Refinery near Edmonton, Canada.4 n Petroleo Brasileiro S.A. has kicked off the contracting process for the construction of its first BioQAV and renewable diesel production plant. n Neste operates the world’s largest renewable diesel refinery in Singapore, with other large plants in the US and Canada. Renewable diesel, also sometimes known as hydrotreated vegetable oil (HVO), differs from petroleum diesel by its lower aromatics content, branched hydrocarbons, metals, and other impurities, but is similar enough to be considered a drop-in replacement for use in modern diesel engines without modifications. HVO is produced primarily through two paths: co-processing or direct treating. Co-processing blends renewables, such as animal fat or used vegetable and cooking oils, with traditional petroleum as the feedstock. Direct treatment uses 100% renewables as the feedstock. However, in all cases, the feedstock is treated to remove contaminants before being directed to a hydroprocessing unit. HVO is produced by the processes of hydrodeoxygenation carried out using catalysts that require HYDROCARBON 21
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high temperatures, high pressure, and the presence of hydrogen followed by isomerisation to meet the required cold flow properties. These processes convert feedstock that contains oxygenated double bonds such as triglycerides into straight hydrocarbon chains (alkanes) by saturating the double bonds and removing the oxygen. Petroleum refineries across the globe are being retrofitted for renewable diesel to accommodate the co-processing pathway. Because renewable diesel contains no aromatics, it produces less particulate matter, making it significantly better for the environment than petroleum diesel in terms of tailpipe emissions. In fact, renewable diesel reduces greenhouse gas (GHG) emissions by up to 90% over the fuel’s life cycle when compared to fossil-based diesel. Bio-based feedstocks can naturally contain sulfur, nitrogen, and oxygen compounds, requiring some hydrodesulfurisation, or the process to create renewable diesel could require a sulfur activated catalyst – Ni-Mo sulfide or Co-Mo sulfide, both of which cause hydrogen sulfide (H2S) to be formed. To meet environmental standards, the H2S must be removed from both gas and liquid phases before the product can be released to market. When co-processing, the sulfur output from the
hydrotreater can be significantly reduced, changing demands on downstream sulfur plants. This can necessitate evaluating how the facility will handle sulfur in a new way.
Regulations In the US, federal and state regulations such as the Renewable Fuel Standard (RFS) and California’s Low Carbon Fuel Standard (LCFS) are pivotal in incentivising the production and consumption of renewable fuels, including renewable diesel. Increased blending mandates are making the markets for renewable diesel even stronger, which encourages higher investments in production infrastructure and increases overall production volumes. In Europe, ‘Fit for 55’ was adopted in 2022 to reduce net GHG emissions by at least 55% by 2030. Two key pillars were adopted in October 2023: the revised Renewable Energy Directive (REDIII) and the ReFuelEU Aviation regulation, both of which emphasise use of waste-based and low-carbon biofuels in the transportation sector. Canada adopted the Clean Fuel Regulation in 2023, a nationwide initiative requiring fuel producers and importers to lower the carbon intensity of transportation fuels by approximately 15% below 2016 levels by 2030. Government mandates and incentives are driving biodiesel adoption in the Asia-Pacific region, which is expected to more than double by 2035. The adoption of renewable diesel in the region is a significant trend, particularly in hard-to-electrify sectors like heavy transport.
Readying renewable diesel for market
Figure 1. Diagram of the FIBER FILM Contactor used in THIOLEX.
Regardless of location, companies must determine the most effective treatment process for removing H2S before it can go to market. Choices are dependent on the hydrocarbon stream being treated as well as the sulfur impurities present in the feed stream. One choice is the LO-CAT® desulfurisation technology, which is useful for removing large quantities of H2S. This is a patented liquid redox process converting H2S to solid elemental sulfur using a chelated iron catalyst. The overall system oxidation reaction is as follows: H2S (gas) + ½ O2 (gas) → H2O + S0 This is a well-known oxidation reaction. This overall reaction is sub-divided into two parts: n (i) H2S gas absorption, ionisation, and reaction to make solid sulfur in the liquid solution. n (ii) The liquid solution is then oxidised using air and regenerated for re-use.
Figure 2. LO-CAT autocirculation process by removing H2S from gas streams.
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In chemistry, step (i) is called reduction, and step (ii) is called oxidisation. Therefore, the LO-CAT process is called a redox (reduction-oxidation) reaction process. It does not use any toxic chemicals or produce any hazardous waste byproducts. The environmentally safe catalyst is continuously regenerated in the process.
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A highly flexible sulfur recovery process was needed to account for the range of feed gas conditions. The selected process needed to achieve high recovery percentages over a wide range of operating flow rates and H2S concentrations. The refiner’s requirements were: n Maintain sulfur removal efficiency at turndown conditions. n Handle minimum H2S concentration in the feed acid gas stream. n Guarantee to meet customer requirements.
Figure 3. The hydrodeoxygenation (HDO) pathway of triglycerides in the renewable diesel process. A further option for H2S removal from gas streams when there is less than 1 tpd of sulfur that requires removal is to use an adsorbent. SULFURTRAP® EX adsorbent differentiates itself for its ability to easily decrease the H2S content to <1 ppm with continuous low-pressure drop (SOR to EOR), loading 2 - 3 times more sulfur. Low OPEX costs are achievable with SULFURTRAP EX due to fewer and easier changeouts. Operations and maintenance personnel find the adsorbent’s free-flowing end-of-run state represents a significant improvement over earlier-generation adsorbents, supporting safer, lower-risk changeouts without the complications of caking or bridging. Another technology is THIOLEXTM. It removes H2S and/or mercaptans from gas and liquid streams using an alkaline solution in an acid-base reaction that may also be used depending on the feed and product specifications. These units use the non-dispersive FIBER FILM® Contactor as a mass transfer device, with caustic and/or amine as the treating reagent in gas and liquid hydrocarbon streams. This device is a vertical vessel packed with proprietary fibre that achieves non-dispersive-phase contact without problems such as aqueous phase carryover, hydrocarbon losses, lack of turndown ability, long settling times, plugging, and flooding. Because the aqueous phase adheres to the fibres rather than being dispersed into the hydrocarbon phase, carryover and uncontrollable emulsions are virtually eliminated. These technologies can remove H2S and mercaptans and ensure that the renewable diesel product meets its required specifications. The decision of which technology to choose depends on the inlet contaminant levels and types, and the required product specifications.
A case for desulfurisation technology A case study that highlights the success of desulfurisation technologies is the sulfur removal unit (SRU) at a multinational oil and gas company based in Europe. In August 2019, the operators of a biofuel refinery with renewable diesel production commissioned a LO-CAT unit to serve as the SRU to treat the amine unit offgas. The existing higher capacity Claus SRU had been shut down when petroleum oil processing ceased. A Claus unit typically requires a minimum feed gas containing 35 mole% H2S, a threshold that cannot typically be met when operating an HVO process with lower H2S concentrations. In addition, turndown conditions can further reduce sulfur recovery efficiency. Modified Claus units can operate with limited reduction of H2S in the feed stream, but to achieve >99.9% sulfur recovery, a tail gas treating unit (TGTU) is required downstream of any Claus SRU which increases cost. January 2026 24 HYDROCARBON ENGINEERING
The LO-CAT process operating at this location employs a rectangular-shaped autocirculation vessel. During the first unit turnaround after the initial year of operation, the LO-CAT solution was drained from the autocirculation vessel and stored for use after the turnaround. The vessel was opened, cleaned, and inspected. There was a small amount of sulfur build-up on the vessel’s floor. The unit was cleaned with a warm water wash, and no corrosion was noted. The shutdown for maintenance took one week, which is the equivalent of 98% availability in the first year of operation. The biofuel refinery operator was pleased with this outcome and the operation and operability of the unit. In 2020, the biorefinery reached full operation with a five-fold increase in biofuel productions compared to 2019. The unit has been running continuously since that time, highlighting the capabilities of a biofuel plant when a suitable technology solution is chosen.
The validity of clean fleets With long-term government policies driving production, treatment, and consumption, renewable diesel plays a significant role in key market segments. Fleets are transitioning to renewable diesel as part of a low-cost strategy to meet sustainability goals and are substantially reducing carbon emissions and petroleum use while improving air quality without sacrificing power, performance, or driving range. Once deemed ‘too good to be true’, renewable diesel is a cost-neutral way to convert an entire diesel-powered fleet to alternative fuel overnight.
Marathon Petroleum
Marathon Petroleum has transitioned its Vinvale and East Hynes fleets in California’s Los Angeles Basin, US, to entirely renewable diesel. The company also switched two of its transport and rail (T&R) fleets and two locomotives from traditional diesel to renewable diesel. The transitions have made significant steps toward reducing the company’s carbon footprint and contributing to a cleaner future.5
San Joaquin Regional Rail Commission (ACE)
In 2022, San Joaquin Regional Rail Commission (SJRRC), based in California, announced a move to the sole use of renewable diesel on its locomotive fleet for the ACE train service. The transition has reduced GHG emissions by 99%.6
Titan Freight Systems
Titan Freight Systems has been providing overnight services across the Pacific Northwest for more than 50 years. Titan switched to renewable diesel, which led to a 36% reduction in emissions over the entire three-state fleet and lowered its overall maintenance costs.7
New York, USA
In 2024, New York City announced that 100% of the city’s 12 500 heavy-duty and off-road vehicles have completed the transition to renewable diesel, making New York City the first major East Coast city to implement this green technology at such a large scale. The transition will prevent 162 million lbs/yr of global carbon dioxide emissions, and it will serve as an important bridge fuel as viable electric versions of these vehicles are developed and placed into the market.11
Conclusion Figure 4. City of Oakland, California, US, an early adopter of renewable diesel.
United Parcel Service (UPS)
In partnership with industry, the National Renewable Energy Laboratory (NREL) has evaluated alternative fuels’ in-use performance in delivery, transit, and freight vehicles. In 2015, in cooperation with UPS and Clean Cities’ National Clean Fleets Partnership, NREL compared the fuel economy and emissions impact of renewable diesel vs petroleum diesel in fleet vehicles. To gather real-world operational field data, NREL instrumented 12 vehicles, which included six regional tractors and six package-delivery vans with data recorders. Representative drive cycles were selected for chassis dynamometer evaluation to determine the fuel economy and emissions impact of renewable vs petroleum diesel in a controlled setting. Fuel properties of the renewable diesel and petroleum diesel were also analysed, which revealed that the renewable diesel was less dense than petroleum diesel and exhibited a higher mass-based heating value, yet lower volume-based heating value. The NREL tests concluded that renewable diesel reduces carbon dioxide emissions by 4.2% on average compared to petroleum diesel, which is attributable to the higher mass-based heating value and lower carbon-to-hydrogen ratio of renewable diesel. Fuel consumption and economy trended strongly with mass and volume-based heating values, respectively, leaving the engine thermal efficiency unchanged for a given cycle. UPS is now one of the world’s largest users of renewable diesel.8
Clean cities Oakland, California, USA
The city of Oakland became an early adopter of renewable diesel beginning in 2015. The city transitioned its fleets from petroleum diesel as part of its low-cost strategy to meet sustainability goals.9 The cities of San Diego and Long Beach have followed suit.
Paris, France
In 2022, Neste, Altens, and TRAPIL collaborated on the first-ever transport of renewable diesel by pipeline from Le Havre in northwestern France to Gennevilliers just outside of Paris. By transporting fuel via pipeline vs tanker trucks, GHG emissions were reduced by 92% compared to conventional logistics. Altogether, they transported 3.5 million l of renewable diesel, which helped make large volumes of renewable diesel available widely in the region, especially to cities such as Paris.10 January 2026 26 HYDROCARBON ENGINEERING
The transition to renewable fuels is not a passing trend. It is a rapidly expanding sector marked by dramatic growth in production and consumption. Many countries have adopted mandates or targets to reduce emissions, policies that are driving global renewable diesel production. The push has already resulted in an increase from less than 4 million t in 2014 to an estimated 23 million t in 2024. Looking ahead, the International Energy Agency (IEA) forecasts that biofuel demand, including renewable diesel, will rise significantly through 2028, led by the US, Europe, Brazil, Indonesia, and India.12 Renewable diesel is the cleaner fuel of choice for fleets relying on diesel engines and a crucial and practical step towards decarbonising the transportation sector. To fully deliver on its environmental promise, careful attention to treating H2S remains essential to ensure renewable diesel is a fully sustainable energy solution.
References 1.
‘Renewable Diesel Market Size / Forecast 2025-2032’, Data Intelligence, (August 2025), https://www.datamintelligence.com/research-report/ renewable-diesel-market 2. ‘Chevron Second Quarter 2025 Results News Release’, Chevron Newsroom, (1 August 2025), https://www.chevron.com/-/media/ chevron/stories/documents/2Q-2025-earnings-press-release.pdf 3. ‘CountryMark Celebrates Completion of Diesel Expansion Project’, CountryMark News Releases, (July 2025), https://www.countrymark. com/about-us/news-releases/countrymark-celebrates-completion-ofdiesel-expansion-project/ 4. ‘Fueling the future: Renewable diesel production begins at Strathcona Refinery’, ExxonMobil News Release, (5 August 2025), https://corporate. exxonmobil.com/locations/canada/renewable-diesel-production-atstrathcona-refinery 5. ‘Marathon Petroleum trucks and trains transition to using renewable diesel in LA Basin’, Marathon Company News, (28 February 2024), https://www.marathonpetroleum.com/Newsroom/Company-News/ Marathon-Petroleum-trucks-and-train-transition-to-using-renewablediesel-in-LA-Basin/ 6. ‘ACE Moves to Sole Use of Renewable Diesel for Locomotive Fleet’, San Joaquin Regional Rail Commission News Release, (November 2022), https://www.sjrrc.com/ace-moves-to-sole-use-of-renewable-diesel-forlocomotive-fleet/ 7. ‘Titan Frieght Systems Goes Renewable and Saves’, Oregon Department of Energy News Release, (March 2021), https://energyinfo.oregon.gov/ blog/2021/3/8/titan-freight-systems-goes-renewable-and-saves 8. ‘A Fuel Switch for Today Continues to Evolve’, Clean Fleet Report, (June 2024), https://cleanfleetreport.com/tech-renewable-diesel-asustainable-substitute/ 9. ‘Although at first renewable diesel seemed too good to be true, it truly has proven to be a miracle fuel’, Neste, (October 2015), https://www. neste.com/en-us/products-and-innovation/neste-my-renewable-diesel/ customer-stories/municipality/city-of-oakland 10. ‘Neste enabled the first-ever transport of renewable diesel by pipeline in Europe to help reduce emissions from fuel transports by 92%’, Neste, (April 2022), https://www.neste.com/news/neste-enabled-the-firstever-transport-of-renewable-diesel-by-pipeline-in-europe-to-helpreduce-emissions-from-fuel-transports-by-92 11. ‘Mayor Adams Announces Full City Fleet has Completed Transition to Renewable Diesel’, NYC.gov, (October 2024), https://www.nyc. gov/mayors-office/news/2024/10/mayor-adams-full-city-fleet-hascompleted-transition-renewable-diesel 12. ‘Renewables 2023 – Transport biofuels’, International Energy Agency (IEA), https://www.iea.org/reports/renewables-2023/transport-biofuels
Traditional sulfiding agents pose operational challenges as well as health and safety risks for operators in the sulfiding process. Jennifer Jackson, Lubrizol, USA, considers how alternative agents may provide a better solution for refiners.
R
efineries everywhere have deployed hydroprocessing, specifically hydrotreating techniques, for decades. These techniques remove sulfur and nitrogen from finished gasoline and diesel fuels, and typically involve combining the hydrocarbon feedstock with hydrogen
inside a reactor. The reactor is filled with a catalyst (most commonly based on cobalt molybdenum or nickel molybdenum) and must then be continuously sulfided while the reactor is in operation. To complete this process, a sulfiding agent is commonly required –
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but traditional options pose significant challenges and limitations and can compromise environmental health and safety. This is particularly true of renewable diesel refining operations, where traditional sulfiding agents are kept on site 24/7. The good news is that alternatives are available that can simplify this process, and they are worth refiners’ thorough investigation. This article will examine traditional agents’ and their complexities, reliable alternatives, and why such alternatives are ideal for the burgeoning renewable diesel industry.
A quick examination of the sulfiding process Within the hydroprocessing reactor, the catalyst starts in an inert form with active metals in their oxide form. The sulfiding process begins as a reaction between the active metals within the hydrogen sulfide and sulfur. Naturally occurring sulfur may be available within the feedstream, but is more commonly provided by a sulfiding agent that is added to the reactor. While it is possible to feed the catalyst with the feedstream’s hydrogen sulfide, this risks coke accumulation on the catalyst surface, reducing its potential lifespan. Meanwhile new feedstocks, including those used to produce renewable diesel (a promising and sustainable fuel source) contain no naturally occurring hydrogen sulfide at all. Thus, a sulfiding agent is typically introduced into the process as an essential part of modern refining and production, but it is not always simple for refiners.
DMDS and associated challenges for refiners Dimethyl disulfide (DMDS) has been the most common choice as a sulfiding agent for a number of reasons. It contains high sulfur content (68%) that is optimal for sulfiding and is typically available at a low cost. Most refinery operations view DMDS as the default choice, accepting some of its challenges as simply the cost of doing business.
But those challenges are significant. Most critically, DMDS maintains a very low flash point of 61°F (16°C), making it a fire hazard that must be handled with care. Usually, DMDS is stored under nitrogen pressure in closed containers, and personnel responsible for handling the material must wear specialised personal protective equipment (PPE) to mitigate safety hazards. And because of these risks, DMDS is heavily regulated by the US Department of Transportation (DOT). Drivers of DMDS transport vehicles are required to remain with the vehicle at all times, enabling the vendor to maintain a closed chain of custody. DMDS presents a few issues within the reactor system as well. DMDS’s hydrocarbon byproduct methane has the potential to accumulate within the hydrogen and hydrogen sulfide recycle gas stream in the reactor. This can cause the hydrogen within the recycle gas stream to become diluted during the sulfiding process, requiring purging of the methane during the process. The flaring of the purged gas, which contains hydrogen sulfide, can produce undesirable sulfur oxide emissions from the hydroprocessor. Further, this may require the addition of supplemental hydrogen to maintain the required hydrogen partial pressure within the reactor. Then there is perhaps the greatest challenge associated with DMDS: its odour. Sometimes likened to the smell of rotting cabbage, DMDS emits an extremely unpleasant odour that can create suboptimal working conditions, even in an open-air environment. Any potential spills on-site can even have ramifications throughout the surrounding community. Considering these challenges, the typical refinery will work to minimise the time that DMDS must remain on-site for the catalyst sulfiding process. Traditional applications involving crude oil typically require catalyst activation every three-to-five years, with DMDS required on-site during these intervals to activate a new catalyst when it is added to the reactor. However, most refineries have multiple processing streams and associated catalysts that require individual activation, meaning that DMDS may be required on-site more frequently. For mid-to-large-sized operations, DMDS may be required once or twice annually for a period of about a week, typically occurring in the spring or autumn.
TBPS: an alternative
Figure 1. TBPS sulfiding agents, including Lubrizol’s
SulfrZol 54 catalyst sulfiding agent, present several benefits when compared with conventional DMDS, including safer handling protocols and milder odours.
January 2026 28 HYDROCARBON ENGINEERING
For refiners seeking an optimal alternative, tert-butyl polysulfides (TBPS) may represent a solution. TBPS are a sulfur-rich material that exhibit a number of beneficial characteristics that can help eliminate the challenges associated with DMDS. And while TBPS maintains a lower sulfur content – 54% compared with DMDS’s 68%, requiring the dosage of TBPS to be slightly larger during the sulfiding process – the benefits are typically worthwhile for most refining operations. For example, Lubrizol’s SulfrZol® 54 catalyst sulfiding agent can reduce many of the challenges associated with DMDS.
SulfrZol 54 TM
A Sustainable Solution
SulfrZol™ 54: A Safer, More Environmentally Friendly Sulfiding Agent • Best-in-class health, safety, and environmental profile • High flash point for safer handling and storage; non-regulated for transport • Low odor and potential for reduced SOx emissions during use
Scan the QR code to discover more about SulfrZol™ 54
Product Highlights • SulfrZol™ 54 is a di-t-butyl polysulfide, expertly formulated for in situ catalyst sulfiding and anticoking applications • With a sulfur content of 54% w/w and an excellent viscosity profile, it delivers sulfur reliably across a wide temperature range—offering a safer, cleaner alternative to Dimethyl disulfide (DMDS) • Backed by a reliable global supply network across the Americas, Europe, India, the Middle East, and Asia Pacific Why Choose SulfrZol™ 54 as Your Advanced Performance Sulfiding Agent? • • • • • •
Widely used and approved worldwide High sulfur content for maximum sulfur delivery High flash point for lower fire hazard Cost-competitive with DMDS Technical advantages over DMDS Simplified storage requirements
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to the US Energy Information Administration, as major domestic logistics operations are beginning to take advantage. 1 In order to successfully capitalise on this demand, renewable refiners in particular require a sulfiding agent suited to the process – and it is here that TBPS presents significant advantages over DMDS. Why? In renewable diesel sulfiding applications, catalyst activation is required once every three years. Additionally, without a constant stream of sulfur, the catalyst may foul, deactivate, or coke. Thus, hydrogen sulfide is added to the renewable stream or co-stream – where co-stream Figure 2. SulfrZol 54 can be particularly advantageous for renewable refers to processing both renewable diesel refining applications, where sulfiding requires a continuous supply. feedstocks and crude oil together – to facilitate the processing of the feedstock. In situations where only catalyst activation is First, TBPS materials maintain a much higher flash needed, DMDS can be easily supplied. point than DMDS, typically about 212°F (100°C). This However, for a continuous supply that renewable helps to eliminate the significant fire risks that DMDS applications require, the operation runs 24/7, rendering materials bring to a facility. Because flammability is not DMDS virtually unusable for the sulfiding process. a major issue, TBPS can be stored in ordinary containers Given chain of custody demands, environmental health and may be handled without excessive PPE, creating and safety concerns, and other hurdles, keeping DMDS greater operational efficiency for refinery workers. on-site continuously is prohibitively disruptive, Further, TBPS is not regulated by the DOT in the same difficult, and costly. As such, renewables producers manner as DMDS – meaning the vendor does not need have sought alternatives, and TBPS has been identified to maintain closed chain of custody. as a potential agent. Without concerns around TBPS also provides some advantages with regard to handling, safety, and chain-of-custody, TBPS is a reliable reactor operation. The byproduct of TBPS is isobutane, way for renewable diesel refiners to enhance their and in most refineries, isobutane exits the high-pressure operations while capitalising on rising demand for this separator with the liquid hydrocarbons instead of more sustainable alternative fuel. diluting the hydrogen in the recycle gas stream, as DMDS does. This reduces sulfur oxide emissions from the hydroprocessing equipment. Additionally, TBPS Conclusion produces sulfur at lower temperatures than DMDS, Overall, refineries everywhere have the opportunity to permitting sulfiding to begin at lower catalyst-bed unlock significant safety and operational benefits by temperatures. This can help to lower the risk of eliminating their dependence on DMDS for the irreversible reduction of the catalyst by hydrogen. sulfiding process. It is especially advantageous for TBPS materials also have a much milder odour, renewable diesel applications, where DMDS is comparable to the smell of common diesel fuel, when extremely prohibitive. And though TBPS agents may compared to the extreme odours associated with come at a marginally higher cost due to higher dosing DMDS. TBPS odours dissipate easily and become requirements, the material helps refineries avoid costly virtually undetectable in open-air environments. and cumbersome handling and monitoring necessities – helping offset any potential cost increase. Combine these benefits with TBPS’ low odour A sulfiding agent for renewable diesel profile, reduced sulfur oxide emissions, and Renewable diesel is witnessing growing global demand contributions to extended catalyst life, refineries can from fleets, airlines, and governments seeking to seize significant operational benefits that can further decarbonise, with heavy-duty transport, contribute to safer, more efficient operations overall. shipping, and aviation representing key long-term It is worth consideration for any refinery. consumers. Because it is a drop-in fuel that can be used in place of traditional diesel without any hardware adjustments, it is an optimal means to lower carbon Reference 1. ‘U.S. Renewable Diesel Fuel and Other Biofuels Plant emissions. In the US alone, capacity has surged over the Production Capacity’, US Energy Information Administration, past five years, growing from approximately 1 billion gal. (26 September 2025), https://www.eia.gov/biofuels/ in 2019 to an estimated 5 billion gal. in 2024, according renewable/capacity/
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C. Senthilkumar, VA Tech WABAG Ltd, India, explores principles, best practices, and opportunities for recycling and reuse within water management for refineries and petrochemical plants.
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he hydrocarbon industry – encompassing refineries, petrochemical plants, and upstream operations – is one of the most water-intensive sectors globally. Water is a critical component in nearly every facet of its operations, from cooling and steam generation to processing and purification. However, growing water scarcity, stringent environmental regulations, and increasing operational costs are driving a paradigm shift. The industry is moving from a linear model of ‘take, use, and dispose’ to a circular, integrated approach focused on water management, recycling, and reuse. This evolution is not just an environmental imperative but a strategic business necessity for ensuring security, efficiency, and a licence to operate. This article explores key principles, best practices, and opportunities for recycling and reuse that are reshaping how the hydrocarbon industry approaches water.
The water-energy nexus: understanding demand To appreciate the scale of the challenge, one must first understand the water use pattern within a typical refinery.
Water consumption in hydrocarbon industries is dominated by two primary processes: n Cooling water: accounting for approximately 53% of total water use, cooling systems rely on massive volumes of water, with significant losses through evaporation and drift. n Steam generation: representing about 42% of use, steam is essential for process heating, stripping, and power generation, leading to consumptive losses. The remaining fraction is split between utility water (5%) and potable water (1%). Traditionally, the fate of this used water was disposal; approximately 41% was discharged as wastewater, with another 5% lost in sludge. This linear model is increasingly unsustainable. The concept of a ‘water balance’ is fundamental. It is a comprehensive accounting of all water inputs – including raw water (surface, purchased, in crude), and even rainfall – against all outputs: product water, steam losses, evaporation, and discharge. The goal of modern water management is to minimise the input of fresh water and the output of wastewater by maximising the internal recycling and reuse of water, effectively closing the loop.
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Principles of water management Water stewardship and value recognition
n Environmental risks of spills and improper disposal.
Midstream transport and processing
The first principle is recognising water as a finite and valuable resource. Unlike hydrocarbons, water has no substitute. This recognition must extend beyond cost to include environmental, social, and reputational value.
n Pipeline hydro-testing requires large water volumes. n Terminal operations may involve contaminated storm water management.
Source protection and diversification
n Refineries can require 1 - 2.5 bbl of water per bbl of crude processed. n Cooling towers and boilers dominate water use. n Wastewater often contains oil, grease, suspended solids, phenols, sulfides, ammonia, and heavy metals.
Ensuring sustainable withdrawal is crucial. Water sourcing should prioritise lower-stress basins and diversify across surface, groundwater, municipal, and alternative supplies (e.g. desalinated seawater or reclaimed wastewater).
Minimisation and efficiency
Downstream refining and petrochemicals
Regulatory and community pressure
Before exploring advanced technologies, companies should adopt process optimisation to minimise water use per unit of production. Water-efficient technologies in cooling, steam generation, and process integration can reduce demand by 20 - 50%.
n Operations in water-scarce regions face tighter scrutiny. n Zero liquid discharge (ZLD) mandates are increasingly common in Asia and the Middle East.
Circularity: recycle and reuse
An integrated water strategy in the hydrocarbon industry is built on three core pillars, each addressing a critical challenge:
A circular mind-set redefines wastewater not as waste but as a potential resource. Internal reuse (within the same process) and external recycling (between facilities or for community benefit) form the cornerstone of sustainable hydrocarbon water management.
Risk and resilience management
Water-related risks range from supply disruptions to regulatory penalties and community opposition. Resilience requires proactive monitoring, contingency planning, and adaptive water strategies aligned with climate projections.
Transparency and stakeholder engagement
Public trust hinges on transparency. Reporting water withdrawals, consumption, and discharge quality, along with engaging local communities, ensures accountability and social licence.
Key water management challenges Upstream exploration and production
n Water-intensive hydraulic fracturing operations. n Produced water (saline, hydrocarbon-laden) volumes often exceed hydrocarbon production in mature fields.
The pillars of modern water management
Ensuring water security and process reliability
Water is a lifeline for continuous operation. A shutdown due to water shortage or quality issues can result in monumental financial losses. Integrated water management mitigates this risk by diversifying water sources. Instead of relying solely on finite freshwater resources or unpredictable municipal supplies, facilities can treat and reuse their own wastewater, creating a reliable, on-site source. Due to a water shortage, Mangalore Refinery and Petrochemicals Ltd (MRPL) in India was forced to partially shut down its plant, resulting in lower production. To avoid such scenarios in the future, MRPL opted for sea water desalination to supply water and thereby improve the water availability. The plant was planned with a modular approach, so that the development can be done in a phased manner to meet the future expansion requirements.
Maximising cost efficiency and operational optimisation
Water procurement, treatment, and disposal represent significant operational expenditures. By recycling water, plants dramatically reduce their intake of expensive fresh water and simultaneously cut the volume of wastewater requiring costly treatment before discharge. Furthermore, advanced treatment processes can recover valuable resources. The Dahej PTA effluent recycling plant, India, is a prime example, where the anaerobic treatment process generates 34 000 m³/d of biogas, leading to savings in operational energy costs. This transforms a cost centre into a value-generating unit.
Meeting environmental standards and enabling sustainability Figure 1. Sea water desalination plant at MRPL, India.
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Regulatory pressures to reduce the environmental footprint are intensifying globally. Integrated systems
are designed to meet the highest environmental standards for direct or indirect discharge. More importantly, they enable companies to become better environmental stewards by significantly reducing their extraction from local water bodies and minimising their polluting discharge. This proactive approach protects local ecosystems and contributes positively to the socio-economic development of the region, bolstering the company’s social licence to operate. The Dangote Refinery Complex in Nigeria arranged for such an integrated approach at the planning stage, tapping raw water from a nearby lagoon with multiple stages of treatment including biological treatment for occasional contamination. The wastewater streams are segregated and treated in specific zones for specific contaminant removal using various treatment technologies, and then, finally, the treated effluent from each stream is combined and tertiary treated in the reverse osmosis based treatment plant for reuse of the water in various applications, including cooling water makeup. The reject from both the treatment plants are also treated meeting the stringent guidelines as specified by International Finance Corp. (IFC).
Best practices for water management Water audits and benchmarking
Conducting comprehensive water audits establishes a baseline of water use and losses. Benchmarking against industry peers or global standards can highlight opportunities for improvement.
Refinery wastewater treatment and reuse
For internal reuse, employing primary treatment, secondary biological treatment, and advance tertiary treatment methods wherein the treated effluent can supply cooling towers, boiler feedwater, or firewater systems, and even process water.
Digital water management
n Real-time monitoring: sensors for flow, quality, and temperature allow continuous tracking. n Data analytics and AI: predict water demand, optimise chemical dosing, and detect anomalies in water systems. n Digital twins: virtual replicas of water networks enable scenario modelling and proactive decision-making.
ZLD and brine management
n Evaporation and crystallisation: convert concentrated brine into solid salts for safe disposal or reuse. n Hybrid ZLD systems: combine membrane and thermal technologies for cost optimisation. n Resource recovery: extracting valuable by-products such as lithium, magnesium, or industrial salts from wastewater.
Stakeholder collaboration
Shared water challenges demand collective action. Examples include: n Industrial water reuse parks, where multiple companies share a central treatment and recycling facility.
Figure 2. Effluent recycle plant at Reliance Dahej PTA complex, India. n Partnerships with municipalities to co-invest in wastewater reclamation plants. n Community programmes to supply treated effluent for irrigation.
The technological arsenal for treatment and recycling Achieving a closed-loop water system requires a sophisticated combination of technologies, tailored to the specific quantity and quality requirements of each process stream. The following segment outlines a comprehensive suite of solutions:
Raw water treatment
The starting point is treating raw water from various sources (surface, ground, sea) to produce different quality streams: cooling water, boiler feed water, process water, and even ultrapure water. Key technologies include: n Clarification: clariflocculators, solids contact clarifiers, and lamella clarifiers remove suspended solids. n Filtration: gravity and pressure media filters and more advanced membrane filtration (microfiltration [MF], ultrafiltration [UF]) provide finer solids removal. n Desalination: for coastal plants or brackish sources, reverse osmosis and thermal desalination are critical for producing high-purity water. n Polishing: demineralisation via ion exchange (IX) and condensate polishing are essential for high-pressure boiler feed water. The Fajr Petrochemical project in Bandar Imam, Iran, stands as a testament to this capability, where a single integrated system provides five different water qualities – including boiler feed, cooling, service, drinking, and fire-fighting water – from one raw water source. Raw water undergoes different levels of treatment to meet the requirements of the different qualities of water ranging from clarification, filtrations, demineralisation, and reverse osmosis technologies.
Effluent and produced water treatment
Industrial wastewater and produced water from oilfields are complex streams containing hydrocarbons, chemicals, and HYDROCARBON 33
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dissolved solids. Treatment often involves a multi-stage approach: n Preliminary treatment: API/CPI separators and dissolved air flotation (DAF) units are used for free oil and grease removal. n Biological treatment: this is the core of organic pollutant removal. Technologies range from conventional activated sludge processes (ASP) and sequential batch reactors (SBRs) to more advanced systems like membrane bioreactors (MBR) and moving bed biofilm reactors (MBBR). Anaerobic processes like upflow anaerobic sludge blanket reactor (UASB) are employed for high-strength wastewaters, offering the benefit of biogas production. Often biological treatment is the combination of two or three processes to meet the desired quality of treated wastewater. n Advanced treatment: for stubborn pollutants, chemical, and physical processes like wet air oxidation, chemical oxidation, and biofiltration are deployed. The scale of this challenge is met by projects like the Petronas RAPID complex in Malaysia, one of Asia’s largest integrated refinery and petrochemical effluent treatment plants, which effectively treats over 102 000 m3/d of seven distinct effluent streams – from process wastewater to fire-fighting run-off – in a single, integrated facility. This integrated wastewater treatment segregates different streams of wastewater based on level of contamination and undergoes different levels of treatment ranging from oil treatment units, conventional ASP, biotowers, depth filtration with media, and final surface filtration.
Water recycling and reuse
This is the culmination of the integrated strategy, where treated effluent is further purified to a standard suitable for re-entry into industrial processes. This requires advanced tertiary treatment: n Tertiary filtration: dual media filters and self-cleaning filters remove residual suspended solids. n Advanced membranes: UF acts as a perfect pre-treatment barrier for reverse osmosis, which removes dissolved salts and organics, producing high-quality reusable water.
n Polishing: activated carbon filtration (GAC) and ozonation (BIOZONE®) remove trace organics and ensure disinfections. India has pioneered some of the largest refinery water reuse plants: n Panipat Refinery (Indian Oil Corp. Ltd): 21 600 m³/d, 90% recovery for boiler feed and process water. n Dahej (Reliance Industries): 36 000 m³/d PTA effluent recycling with combined aerobic-anaerobic treatment, producing biogas for heating. n Paradip Refinery (Indian Oil Corp. Ltd): 54 000 m³/d, 75% water recovery using multi-stream effluent treatment and reverse osmosis.
The road ahead The integration of the water-energy nexus is driving innovation across the sector, with energy-efficient treatment technologies such as forward osmosis, membrane distillation, and anaerobic MBRs being deployed to lower operational costs. In decentralised treatment units, modular and skid-mounted systems enable flexible water recycling at well pads, terminals, and satellite facilities. Nature-based solutions, including constructed wetlands and biofiltration, are being tested for effluent polishing, enhancing biodiversity while reducing treatment costs. Advances in material science – such as nanomaterials, graphene-based membranes, and biomimetic materials – offer higher selectivity and reduced fouling in desalination and water reuse systems. Extending the circular economy beyond water, the integration of waste heat recovery, carbon capture, and resource recovery from wastewater supports net zero and broader sustainability goals.
Conclusion
The evolution of water management in the hydrocarbon industry is clear. Water is no longer a utility to be managed in isolation but a strategic resource integral to the entire production lifecycle. The principles of integrated water management – understanding the water balance, implementing a multi-barrier technological approach, and focusing on recycle and reuse – are delivering tangible benefits. Companies that embrace this holistic approach are future-proofing their operations against water scarcity, realising significant cost savings through reduced consumption and resource recovery, and positioning themselves as leaders in corporate environmental responsibility. As the case studies from Reliance Dahej, Panipat Refinery, and Dangote Refinery show, investing in complete water solutions is not merely an operational expense; it is an investment in resilience, efficiency, and long-term sustainability, truly enabling sustainable solutions. The technology and expertise exist; the imperative now is for wider adoption Figure 3. Effluent recycle plant at Dangote Refinery complex, Nigeria. across the global hydrocarbon sector. January 2026 34 HYDROCARBON ENGINEERING
Heiko Petersen, ABB Energy Industries, explores how AI and automation are reshaping the energy industry through addressing workforce challenges, while creating opportunities to attract new talent into energy operations.
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he energy sector faces a workforce challenge unprecedented in its modern history. Operators with 40 years of expertise are retiring faster than their knowledge can be transferred, while facilities struggle to attract younger generations into an industry sometimes perceived as technologically outdated, and less attractive from an environmental perspective. This demographic reality coincides with the rapid adoption of AI-enabled systems that some fear will eliminate jobs. These technologies are fundamentally changing what it means to be an operator rather than eliminating the role. The transformation addresses both the knowledge preservation challenge and the perception problem that makes recruiting difficult.
The changing nature of operational work Traditional operator responsibilities centred heavily on routine monitoring, manual adjustments, and procedural compliance. An operator’s day involved constantly scanning multiple screens displaying dozens of process variables, watching for deviations, and making corrections based on established procedures and
accumulated experience. Occasionally interrupted by anomalies, turning an otherwise monotonous job into an overwhelmingly stressful situation, which required all accumulated experience to mitigate. The physical environment reflects this. Traditional industrial control rooms present operators with 10 or more crowded screens displaying hundreds of variables simultaneously. The human brain struggles to effectively process such a volume of information, creating a persistent state of either boredom during steady operations or overwhelming stress when abnormalities occur. Modern systems shift the balance. Start up procedures that once required thousands of manual operations by highly skilled personnel have been reduced to fewer than 10 automated steps. Rather than executing routine procedures, operators and process engineers can now focus on process optimisation, strategic planning, and complex problem-solving that requires human judgement and creativity. Advanced operator support systems enable this. Rather than presenting every data point, these platforms filter information to surface only what matters in the current operational context, reducing cognitive load while ensuring nothing critical gets missed.
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Figure 1. State of the plant at-a-glance with ABB Ability™ PlantInsight.
Knowledge preservation extends beyond optimal operations to include exception handling. When abnormal situations arise, pattern-matching capabilities can identify similar historical events and surface information about how operators previously resolved the issue. This transforms institutional knowledge from something locked in individual operators’ experiences into organisational capability accessible to anyone in the control room. Where operators and process engineers previously might spend hours researching solutions to complex problems – consulting documentation, calling more experienced colleagues, or reviewing historical data – these systems can surface proven recommendations in seconds by instantly accessing decades of operational history.
Building trust across generations
Practical knowledge transfer in action
The introduction of AI-enabled systems creates predictable resistance among experienced operators. Those typically 45 to 55 years old with decades of expertise sometimes approach these systems with scepticism. They have built careers on institutional knowledge and intuitive understanding of plant behaviour. The suggestion that software can guide their decisions may make them feel like their expertise is being diminished. What changes perspectives is consistent performance. When these systems repeatedly identify potential issues before they become problems, recommend actions that prove correct, and provide troubleshooting guidance that works, scepticism shifts to acceptance. What is often witnessed is that the same operators who initially resisted the technology ask why the system presents recommendations rather than automatically implementing them. Younger operators demonstrate different adoption patterns. Digital natives expect technology integration and sophisticated interfaces. They are less impressed by automation itself and disappointed when systems feel outdated or cumbersome. For this generation, working with advanced decision support systems is the baseline rather than impressive innovation.
The implementation approach matters significantly for success. The most effective deployments involve experienced operators working directly with system designers during development. Rather than having external experts codify operational knowledge, operators themselves help identify which situations warrant decision support and which recommendations prove most valuable. This collaborative approach benefits both parties. Operators see their expertise valued and preserved rather than replaced. They participate in creating systems that will support less experienced colleagues rather than watching their knowledge walk out the door at retirement. Meanwhile, systems gain access to authentic operational expertise rather than theoretical best practices that may not reflect plant-specific realities. A critical validation step involves process engineers reviewing system recommendations before deployment to operators. When the system identifies that ‘90% of operators took this action in similar situations,’ process engineers verify whether that represents genuine best practice or simply a typical response that may not be optimal. This human oversight ensures recommendations reflect validated expertise rather than simply reproducing historical patterns.
Capturing institutional knowledge
Redefining industry perceptions
The ‘grey wave’ phenomenon poses a fundamental challenge: how do you preserve operational expertise that exists primarily in operators’ heads, accumulated over decades of experience handling complex situations? Traditional training programmes transfer procedural knowledge effectively but struggle to develop the intuitive understanding that develops over years of operation. One approach involves identifying periods when facilities operated optimally, producing excellent quality with high throughput while remaining safely within operational limits. These ‘golden process’ periods typically occur when the most experienced operators run the plant. By training AI models on data from these optimal periods, systems establish benchmarks representing best-practice operation. These benchmarks serve dual purposes. First, they enable continuous monitoring that alerts operators when current conditions deviate from optimal patterns, often minutes or hours before traditional alarm limits would trigger. Second, they preserve the operational patterns of expert operators in software that remains available regardless of personnel changes.
The ‘dirty industry’ perception creates recruitment challenges that technology alone cannot solve. However, modern operational environments bear little resemblance to outdated stereotypes of working on assets or in the field. Today’s control rooms feature clean, climate-controlled environments with advanced visualisation systems, sophisticated data analytics, and remote operational capabilities. This shift towards remote operations particularly appeals to younger workers who expect workplace flexibility and advanced technology. Offshore platforms that previously required hundreds of on-site workers can now operate with a single-person laptop-based oversight. This transformation improves safety while also creating roles that emphasise technical sophistication over physical presence in hazardous environments. Sustainability also matters in attracting environmentally conscious younger workers. AI-enabled systems that optimise energy consumption and reduce emissions let operators contribute to environmental goals while working in traditional energy sectors. Real-time emissions monitoring and
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optimisation capabilities provide tangible evidence of environmental responsibility rather than abstract commitments. The technical sophistication of modern operations appeals to candidates who might otherwise pursue careers in pure technology companies. Working with systems that perform multivariate analysis across hundreds of variables, predict process behaviour minutes into the future, and learn from operational history presents intellectual challenges that rival those of consumer technology development.
Maintaining safety during transition Industrial operations cannot pause for workforce transformation. Safety and operational continuity must be maintained as skill sets evolve, and new technologies are deployed. This reality demands careful implementation approaches that augment rather than replace operators during transition periods. Phased deployment is a must. Rather than wholesale system replacement, modern architectures integrate advanced capabilities with existing distributed control systems. Facilities can implement individual capabilities – such as anomaly detection, pattern matching, and predictive simulation – as operators become comfortable with each, gradually building towards higher autonomy levels without disrupting operations. Fail-safe mechanisms and comprehensive override capabilities maintain human control throughout. Systems provide recommendations and decision support, but operators retain the authority to override suggestions based on plant-specific knowledge or situational factors the system may not capture. This preserved human authority proves critical for building operator trust and maintaining safety.
The skills portfolio of tomorrow’s operator The capabilities required for effective operation are shifting noticeably. Traditional emphasis on procedural execution and routine monitoring gives way to data interpretation, systems thinking, and strategic decision-making. Tomorrow’s operators must be comfortable with AI system recommendations, understanding when to accept guidance and when plant-specific knowledge suggests alternative approaches. The ability to conduct ‘what if’ analysis becomes increasingly valuable. Rather than making changes and observing results, operators can simulate different responses and predict outcomes before implementation. This capability requires understanding process interdependencies and developing intuition about how changes propagate through complex systems – it is higher-order thinking than traditional procedural execution demanded. Cybersecurity awareness also emerges as a new requirement as operational technology increasingly connects to broader networks. Operators need basic understanding of security implications when systems integrate with cloud platforms or enable remote access. This represents entirely new knowledge domains compared to traditional operational training. Critical thinking, situational awareness, and decision-making matter more than procedural compliance when handling exceptions the system cannot resolve. Collaboration across disciplines – operations, IT, engineering – becomes standard rather than occasional. Communication skills become more January 2026 38 HYDROCARBON ENGINEERING
important as operators increasingly interact through sophisticated interfaces rather than simply adjusting physical controls. The expectation of continuous learning represents perhaps the most significant cultural shift. Static skill sets acquired during initial training and supplemented occasionally no longer suffice. Technological evolution requires ongoing skill development, creating work environments that emphasise adaptation and learning. These are characteristics that appeal to younger workers who expect career development and growth opportunities.
Building the pipeline Addressing workforce challenges requires looking beyond current employees to future talent pipelines. Educational partnerships help universities update curriculums to reflect modern operational technology rather than preparing graduates for control rooms that no longer exist. Internship and apprenticeship programmes showcase real working environments rather than perpetuating outdated stereotypes. Career pathway clarity is essential for attracting ambitious candidates. Demonstrating progression from entry-level positions working with advanced technology to strategic roles managing complex operations helps candidates envision long-term careers rather than viewing energy operations as dead-end work. The transferability of skills matters for career-minded candidates. Experience with AI-enabled systems, data analytics, and advanced control technologies provides a foundation for diverse career paths within and beyond energy operations. This optionality appeals to workers who value flexibility and want skills that remain relevant across industries.
A workforce transformation, not replacement Workforce evolution in the energy sector is an opportunity rather than a threat. AI and automation systems address the knowledge transfer challenge while simultaneously making roles more attractive to younger generations. Success depends on thoughtful implementation that maintains safety and efficiency during transition, while actively reshaping how work gets done and who wants to do it. The most valuable operators will be those who leverage advanced systems effectively, combining traditional operational expertise with sophisticated decision-support tools. Companies that can attract, develop, and retain this hybrid skill set will maintain a competitive advantage as the industry continues to evolve. The question facing individual facilities is how proactively they will shape this transition. Those that wait for workforce crises to force change will struggle. Those that actively redefine operational roles, invest in modern technologies that make work more engaging, and build bridges to younger talent pools will position themselves for sustained operational excellence despite demographic headwinds. The energy sector’s future workforce will look substantially different from today’s. That transformation is already underway in facilities worldwide. The challenge and opportunity lie in managing it deliberately rather than letting it happen by default.
Jitendra Chellani and Secil Uzun, KBC (A Yokogawa Company), alongside Mohammad Al-Johar and Saravanakumar Chidambaram, SATORP, explore solutions to optimise delayed coker units by increasing throughput and higher-value yields.
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n refinery plant operations, ensuring consistent stability and operational efficiency poses a formidable challenge for distributed control system (DCS) operators. This challenge stems from fluctuations in unit feed properties and conditions, influenced by various uncontrollable factors such as changes in upstream operations, variations in ambient conditions, and shifts in unit performance. Although advanced process control (APC) systems have become commonplace within refinery units, their primary role is to maintain plant stability, rather than guarantee optimised operational outcomes for the entire facility. While APC systems adeptly handle fluctuations within the plant, they fall
short of delivering holistic optimisation. This limitation opens the door for Dynamic Real-Time Optimisation (RTO), a solution that calculates optimal setpoints dynamically in response to ever-changing plant conditions. Whether prompted by shifts in plant feed conditions or product price fluctuations, a Dynamic RTO solution can consistently guide and maintain plant setpoints at the optimised operating point. In essence, RTO represents a significant opportunity to enhance refinery operations by continually aligning these processes with optimal performance criteria. It extends beyond the APC system limitations, offering improved operational efficiency in refinery processes. HYDROCARBON 39
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Optimisation of delayed coker unit Refineries worldwide face sustained pressure from volatile crude markets, shifting product demand, and rising environmental and regulatory requirements. In this context, efficiency alone is no longer sufficient; optimisation is essential for competitiveness. One of the toughest assets to manage is the delayed coker unit (DCU). The DCU is massive in scale and serves as the refinery’s workhorse that converts heavy feedstocks into lighter, higher-value products such as naphtha and gas oils while producing petroleum coke as a by-product. Optimising a coker unit is complex because of its dual operating modes: semi-batch coke drum operation alongside continuous fractionation and downstream processing. This mismatch in process dynamics creates unstable conditions and inconsistent yields. Due to the significant price differences from the DCU products, optimising the yields from this unit can significantly improve refinery economics. The petroleum coke is a refinery’s low-value product. Reducing coke yield while increasing the liquid product yield improves gross margins. The DCU’s liquid product prices vary. Maximising light coker gas oil typically improves refinery profitability. There are often benefits associated with increasing the DCU’s throughput. Coker units are typically operated close to their maximum stretch capacity. Debottlenecking the coker unit may allow higher refinery throughput or enable the processing of heavier crudes.
and variable operating expenses. The results generated by the optimiser are used as external targets for the APC which ultimately controls unit and equipment operation through the DCS. Separating non-linear first principles models from the optimisation improves the solution’s robustness. Optimisation is performed regularly without solving rigorous first-principles models. This reduces model maintenance. The two-layer approach ensures that optimisation is performed at specific time intervals without waiting for steady state detection. Steady state detection updates the model matrix dynamically, whereas the optimiser estimates external targets regardless of steady state. A simplified representation of Dynamic RTO is shown in Figure 1.
Case study
KBC (A Yokogawa Company) and Saudi Aramco Total Refining and Petrochemical Co. (SATORP) collaborated to deploy an RTO in the DCU. SATORP operates a high conversion refinery in Jubail, Saudi Arabia, that includes a DCU for residue upgrading. The RTO is part of the advanced analytics programme, which includes a strategic approach for digitalisation. The RTO deployed at SATORP’s DCU uses an innovative approach where first-principles modelling estimates updated gains dynamically. These gains are used by the optimiser to estimate changes in the APC external targets. Figure 2 shows an overview of the first-principles Petro-SIM® process simulation model. The objective function for the DCU RTO includes gross Dynamic optimisation product worth, cost of feedstock, and unit utilities. The gross The Dynamic RTO combines the power of first-principles product worth is estimated based on product yields and models with an automated online optimiser. The prices. Estimating intermediate prices for the DCU was a non-linearity of process units is captured through the challenge during the project execution. The project team relationship between different variables. The matrix built agreed on a unified approach to estimate these prices and from this relationship is used for optimisation, which the price-set was regularly updated and used by the solution incorporates other inputs including price sets, APC limits, and for the optimisation. actual operating conditions. Optimisation reduces the yield of low-value products The optimiser is flexible and can be configured for a while increasing the yield of high-value products. Coke is one process unit, multiple process units, or the overall refinery of the low-value products from the overall refinery, and the complex. The objective function is based on economics, optimiser estimates changes in various manipulated variables which includes the cost of feedstock, gross product worth, (MVs) to reduce coke yield while increasing the yield of liquid products. In addition to yield shifts from low to high-value products, the solution performed yield-vs-energy optimisation. RTO is integrated within the existing infrastructure. Direct communication between RTO, APC, and DCS reduces manual efforts by the operator. The performance of the solution is monitored by various stakeholders through the dashboards Figure 1. Simplified representation of the Dynamic Real-Time Optimisation (RTO) solution. developed for the project. January 2026 40 HYDROCARBON ENGINEERING
RTO Without the Complexity Keeping your refinery optimized doesn’t have to mean new tools or specialist skills. KBC’s dynamic, real-time optimization makes it simple to sustain top performance across individual units and entire facilities using the existing skills of your engineers. The unique combination of Petro-SIM® and Advanced Control and Estimation gives you a tightly integrated, reliable system with robust model fidelity, empowering you to optimize your operations, increase uptime and push past profit limitations.
Learn more at www.kbc.global/rto
Figure 2. Petro-SIM model for DCU RTO.
Figure 3. Project benefit realisation. The solution deployed at SATORP follows the internal cybersecurity guidelines and regulatory standards. Communication between various systems has been established to operate the solution without any manual intervention. The closed-loop optimisation is performed using on-premises infrastructure. The DCU RTO was deployed as a solution rather than a tool. Different aspects through which benefits were realised in the project are shown in Figure 3. The solution deployed at SATORP was supported by KBC’s consulting practices. Some of the benefits were realised before deploying the solution. Round table discussions, data analysis, and model development identified multiple ideas for improvement. These ideas were screened, and specific opportunities were discussed with the stakeholders. The APC was also updated based on the functional design prepared for the RTO. The benefits were realised while updating the APC which was also supported by consulting practices. The benefits from the RTO deployment were estimated at a specific frequency. These benefits were aggregated and available on dashboards. The dashboards automatically prepared management reports, which documented monthly and cumulative benefits since the deployment. Various opportunities identified through consulting practices were discussed with project stakeholders. Some of these opportunities were implemented before deploying the solution. January 2026 42 HYDROCARBON ENGINEERING
The programme’s payback period was less than three months based on the benefits implemented through these opportunities. After deploying the tool, additional benefits were delivered. These benefits were tracked automatically through dashboards, which are accessible company-wide. They display both monthly and cumulative benefits. Sustaining the solution is as important as its development and deployment. End-user engagement and role clarity were achieved through multiple training sessions and workshops. Various work processes for RTO use and maintenance, along with RACI matrices, were discussed. With the solution framework in place, the next step was to assess its performance under real operating conditions. Post-implementation monitoring focused on whether the optimiser delivered measurable gains in yield, energy use, and profitability, while also improving day-to-day operations. Benefits were confirmed through the project’s post-implementation monitoring phase.
Conclusion Deploying an RTO in the DCU demonstrates that even highly complex, semi-batch refinery units can achieve reliable and sustained optimisation. Applying it in the DCU, one of the most challenging units in refining, demonstrates its potential for broader deployment across other fractionation and conversion units. The implications extend beyond near-term profitability. As refiners face the dual pressures of competitiveness and decarbonisation, digital optimisation offers a pathway to improve energy efficiency while sustaining economic performance. The programme also identified additional opportunities for future implementation, reinforcing that optimisation is a continuous process rather than a one-time project. In many ways, optimisation should be viewed as an ongoing journey, with each phase building on the last. In this sense, RTO is not only a tool for capturing incremental margin gains but also an enabler of long-term strategic goals.
Fabio Pires and Andy Phillips, Tracerco, consider how advances in digital platforms and the rise of remote expert teams are enabling refiners to reduce downtime, improve safety, and unlock new efficiencies.
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efineries and petrochemical plants are under relentless pressure. The drive for cleaner fuels, more specialised products, and greater efficiency, set against volatile feedstock supply and fluctuating market demand, means operators are constantly asked to do more with less. In such an environment, every shutdown, every delay in identifying a problem, and every inefficiency carries a tangible cost in lost throughput, added emissions, and heightened safety risk. Over the past two decades, scanning process towers while in operation has already improved maintenance planning and reduced unnecessary downtime. But recent advances in digitalisation have taken this further. Today, refiners can not only see what is happening inside their towers, they can also access and interpret diagnostic data
almost immediately, supported by remote experts who can guide decision-making in real-time. This article explores insights platforms, particularly the evolution of the TracercoTM Insights Platform since its introduction in 2022 and how the addition of a remote team has aided speed, consistency, and value in process diagnostics.
Adoption and uptake Digital platforms provide a secure way to access, interpret, track, and customise tower scanning project data. Tracerco’s Insights Platform has been harnessed by major refiners, international oil companies, national operators, and independents across North America, Europe, Asia, Latin America, and Australia. Whether in crude distillation, HYDROCARBON 43
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petrochemical processing, or gas plants, if a site has a tower, the digital platform can be used to manage its performance in real-time.
Platform improvements Refining operations demand timely information to support decisions. Historically, tower scan reports were delivered weeks after the inspection. The Insights Platform addressed this by enabling same-day access and further development has reduced the analysis result time to near-instantaneous delivery, with data visible in Tracerco’s platform as soon as scans are complete. Equally important has been accessibility. The platform provides dynamic, visualised profiles of tower performance. Engineers can zoom in on areas of interest, toggle between different scan lines, and overlay historic and current data sets to quickly identify changes. This has eliminated the process of comparing paper reports and has made trend analysis far simpler and more effective in identifying small changes over time. Central to these improvements has been direct customer involvement throughout the development lifecycle. From early design workshops and pilot testing to post-release feedback sessions, customers have actively influenced priorities and
Figure 1. Landing page dashboard.
Figure 2. Live scan landing dashboard.
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functionality. Continuous engagement has shaped many of the enhancements – for example, customers requested formal documentation, leading to the introduction of a one-click PDF export that saves engineers time when generating duplicate reports. Similarly, customer feedback on data integration needs drove the creation of export tools for system interoperability. The development approach remains deliberately iterative and customer-centric, with new features co-designed and validated through user feedback. Usage data, field input, and ongoing collaboration with customer teams ensure refinements focus on what delivers the greatest operational value. This feedback-driven process ensures the platform continues to evolve driven by customer needs and remains a practical, reliable tool in daily operations.
The role of the remote team Alongside digitalisation, Tracerco recognised another opportunity: to harness the knowledge of its diagnostic technicians without requiring them to travel. The remote expert team was established to complete this, creating a centralised pool of specialists dedicated to analysing scan data and supporting customers in real-time. This model addresses several long-standing issues, such as standardising reporting. Previously, the style and depth of analysis could vary depending on which engineer was on site. Now, a core team applies consistent methods and quality checks, while tailoring detail to individual customer preferences. The digital platform further strengthens this consistency by embedding validation rules and automated cross-checks, acting as an additional quality assurance step. Before any data is released for analysis, the platform verifies signal integrity, scan coverage, and calibration inputs to ensure the information captured is both complete and accurate. This set up accelerates reporting. Remote experts view the scan data live as it is acquired. If anomalies appear, they can request adjustments immediately, ensuring that the correct data is captured on every project. By the time field crews finish their work, initial analysis is often already complete, and reports can be finalised within hours. As a result, average report turnaround has improved from around four weeks to under two days, with urgent scans now delivered within a day – a transformation
that allows customers to make critical operational decisions far quicker than before. Also, it improves collaboration. Customers can join live discussions with the remote team while the scan is underway, allowing issues to be identified and acted upon in real-time. In complex refinery environments, decisions often need to be made under tight time constraints, with safety, production, and environmental factors all at stake. Having a shared, live view of the data ensures plant engineers and external experts are interpreting the same information together, reducing the risk of miscommunication or delay. This collaborative approach not only supports faster decision-making in the moment but also creates a record of shared learning that operators can draw upon for future troubleshooting and continuous improvement. The approach blends the assurance of expert human interpretation with the speed of digital delivery, creating a new model for tower diagnostics.
Case studies in practice At a large US refinery, 14 towers were scanned by Tracerco over the course of one week. Traditionally, this would have required several teams working in parallel, followed by weeks of report writing. Instead, with the Insights Platform and remote experts in place, all 14 reports were delivered to the customer by the end of that same week. The refinery’s engineers were able to begin planning interventions immediately, saving weeks of delay. In another case, an ethanol producer was experiencing operational difficulties in a column suspected of flooding. As the
scan was performed, the remote experts observed flooding patterns live and advised reducing feed rates and repeating the scan in targeted sections. In a single day, three adjusted scans were completed until the issue was pinpointed. With this live interaction, the root cause was identified within hours, eliminating the need for repeat scans days or weeks later and avoiding production losses caused by trial-and-error rate adjustments. Perhaps most striking are the financial implications of throughput optimisation. In one example, an atmospheric crude column was scanned at different feed rates to assess flooding risk. The results confirmed that throughput could be increased by 4000 bpd without compromising quality. Based on prevailing refining economics, this equated to an additional gross profit of US$79 000 - 99 000/d, or approximately US$29 - 36 million/yr, depending on crack spread assumptions. A simple diagnostic intervention enabled the plant to unlock significant additional value. These examples demonstrate how real-time data and expert support can transform diagnostics from a retrospective tool into a proactive driver of efficiency and profitability.
Efficiency, safety, and sustainability Beyond direct financial gains, faster and more reliable diagnostics carry wider implications for safety and sustainability. From a safety perspective, ensuring data accuracy in real-time reduces the need for repeat inspections and minimises the time engineers spend working at height or in hazardous environments. Standardised reports and rapid turnaround also
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enabling even more immediate discussion and action. Machine learning (ML) is also being integrated to assist with anomaly detection. Algorithms are being trained to recognise typical fault patterns in scan data – such as signs of tray damage or packing collapse – and flag these to the remote experts. While not intended to replace human interpretation, this provides an extra layer of support and accelerates identification of potential problems. Figure 3. Customer interactive report. Another innovation is a partial scan, developed in response to customer need. Some towers are physically inaccessible around their full circumference, making complete ThruVisionTM tomography impractical. By modifying software to reconstruct profiles from half the usual coverage, useful trend data can still be obtained. Early trials with a long-standing US customer have shown this to be a valuable tool for sites where scaffolding or full access would be prohibitively expensive. Finally, the remote expert Figure 4. Customer facing interactive report (historic comparison). team itself is expanding. Originally based in the US, the team will be extended to Europe, the Middle East, and mean operators can act on reliable information sooner, Asia-Pacific to provide true 24-hour global coverage. This will preventing small problems escalating into hazardous situations. ensure that when a scan takes place, an expert is available in the From an environmental perspective, operating towers in right time zone to participate live. Demand is such that the team suboptimal conditions can lead to excess energy consumption, expects to more than double its monthly workload, interpreting increased emissions, or the production of off-spec product that at least 150 scans per month. must be reprocessed or flared. Identifying and correcting such issues promptly reduces waste and energy use, directly supporting ESG goals. For example, preventing flooding or Conclusion maldistribution in a column not only maintains product quality Digital innovation and remote expertise are reshaping how the but also avoids unnecessary emissions associated hydrocarbon processing industry manages its critical assets. Such with inefficiency. developments have transformed tower scanning from a slow, In an industry increasingly measured against ESG retrospective exercise into a near-instantaneous, interactive performance and digital audit trails, the ability to provide process. The addition of a remote expert team has ensured that verifiable, time-stamped diagnostic data supports both internal data is not only delivered quickly but also interpreted compliance and external reporting requirements. consistently and accurately, blending the speed of digitalisation with the assurance of human judgement. For refiners, the benefits are tangible: reduced downtime, Future direction improved safety, greater efficiency, and measurable financial The journey is far from complete. Several developments are gains. For the industry, the implications extend to enhanced planned for the near future that will further enhance the value ESG performance and a more proactive approach to of the platform. asset management. One imminent addition is a customer-facing live scan The future of process diagnostics is one where data and interface. While the remote team already views data live, expertise converge in real-time to help operators make faster, customers currently see results once the scan is better-informed decisions, ensuring plants are safer, more complete. By the end of 2025, refiners will be able to watch efficient, and more profitable. their scans unfold in real-time via a clear, user-friendly display, January 2026 46 HYDROCARBON ENGINEERING
Pascal Gaillot, Yokogawa Europe, explores how process automation, advanced instrumentation, and digital tools can aid the downstream sector on its journey toward net zero.
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he downstream oil and gas industry is under intensifying scrutiny as it works to balance global demand for fuels and petrochemicals with the urgent need to reduce CO2 emissions. Refineries and petrochemical plants are inherently energy-intensive, and their carbon footprint
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has become a critical challenge in the era of net zero targets, stricter regulation, and investor expectations. To remain competitive, operators must look beyond incremental improvements and embrace transformative strategies. Among the most effective enablers are advanced process automation, reliable instrumentation, and digital solutions that deliver real-time insight into energy use and emissions. With advanced process automation, precise measurement, and digital integration, downstream operators can achieve significant energy savings and meaningful reductions in greenhouse gas (GHG) emissions. Automation and measurement have always been central to plant operations, ensuring safety, product quality, and efficiency. Today, however, their role extends into sustainability. By enabling continuous optimisation of complex processes and supporting transparent emissions monitoring, these technologies allow operators to reduce variability, minimise flaring, and cut unnecessary energy consumption. The result is not only lower CO2 output but also improved profitability in a market where every percentage point of efficiency counts.
The expanding role of automation in decarbonisation Downstream operations involve some of the most complex industrial processes in the world, from distillation and cracking to hydrogen production.
Figure 1. Visual MESA Emissions Management.
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Small inefficiencies – like fouled heat exchangers, suboptimal column performance, or degraded rotating equipment – quickly translate into high energy costs and significant carbon emissions. Advanced automation platforms now enable refiners to go beyond traditional control. With continuous optimisation and predictive capabilities, operators can dynamically adjust processes to changing feedstocks and market conditions, ensuring the plant runs at its most efficient point consistently. Reliable instrumentation is the foundation of this optimisation. Accurate measurement of flows, pressures, temperatures, and compositions ensures that decisions are based on trustworthy data. When combined with digital analytics, this creates a powerful feedback loop: precise data feeds smarter control, which in turn reduces energy waste and emissions.
Energy efficiency as a competitive lever Energy typically accounts for the majority of operating costs in refining and petrochemicals. Improvements in efficiency therefore deliver both economic and environmental benefits. Advanced automation tools can achieve 3 - 7% reductions in overall energy consumption, while targeted applications, such as distillation optimisation, can save up to 10 - 15% in specific units. Optimised distillation processes, smarter heat integration, and better control of hydrogen production are all examples where advanced automation can cut fuel consumption significantly. Here, plant-wide energy management has become an indispensable tool. Solutions such as the Visual MESA® Energy Management System (VM-EMS) suite of applications, developed by KBC (A Yokogawa Company), provide a consolidated view of steam, fuels, water, and electricity consumption, and recommend optimal operating strategies in real time. Within the suite is Visual MESA® Greenhouse Gas Emissions Management (VM-GEM), which features a TÜV Rheinland certification as a calculation method under ISO 14068. This assures operators and stakeholders alike that the system’s CO2 calculations are robust, transparent, and globally recognised. For downstream operators, this means not only saving energy but also having a credible, auditable basis for reporting carbon reductions.
This level of trust is increasingly critical. Transparent and accurate emissions reporting has become a licence to operate. As investors and regulators demand transparent ESG reporting, the ability to prove reductions in both energy use and CO2 emissions with certified methodologies provides a strategic edge.
Digitalisation, simulation, and predictive insights Digital transformation is accelerating decarbonisation across downstream facilities. Digital twins and simulation platforms allow operators to model entire plants, test new operational and control strategies, and train staff in virtual environments before deploying changes on-site. This reduces risk, shortens implementation timelines, and makes it easier to pursue ambitious energy-saving projects. Predictive maintenance and condition-based monitoring further support sustainability. By identifying equipment degradation early, plants can avoid inefficiencies that accumulate unnoticed over time. Extending asset life while keeping equipment in peak condition not only reduces costs but also prevents unnecessary energy consumption and emissions.
Emissions monitoring and transparency As regulations tighten and stakeholders demand accountability, continuous emissions monitoring has become essential. Accurate real-time data on CO2 and other pollutants provides both compliance assurance and operational insight. When integrated with process control, emissions monitoring does more than report, it enables proactive reduction by linking emissions trends directly to operating conditions. The integration of solutions like VM-GEM adds another layer of credibility, as operators can demonstrate that the emissions data they report is derived from a calculation method certified against international standards. This transparency transforms decarbonisation from a compliance burden into a performance driver.
From compliance to competitive edge The downstream sector is shifting from viewing decarbonisation as an obligation to seeing it as an opportunity. By leveraging automation, instrumentation, and certified energy management solutions, operators can achieve meaningful reductions in CO2 intensity while strengthening their financial performance. The combination of cost savings, improved asset reliability, and stronger ESG credentials creates a competitive advantage that goes beyond regulatory compliance. Case studies already show the impact: double-digit reductions in unit energy use, hundreds of thousands of tons of CO2 emissions avoided annually, and rapid returns on investment. With certification under ISO 14068, operators gain an additional assurance that these results can be verified and trusted by regulators and stakeholders worldwide.
Figure 2. Transforming decarbonisation from a compliance burden to a performance driver.
Looking ahead: pathways to net zero The future of downstream oil and gas will be shaped by even greater complexity as facilities integrate renewable feedstocks, expand low-carbon fuels, and implement carbon capture. This will require an even higher level of automation and digital sophistication. The vision is clear: plants that are not only optimised for efficiency but are also flexible, resilient, and designed for net zero objectives. These transitions will increase process complexity and require even more sophisticated automation. Yokogawa’s vision of ‘autonomous operations’ anticipates this future, combining AI, machine learning, and adaptive control to manage complex plants with minimal human intervention. Automation and digitalisation are already proving their value as essential enablers. By embedding sustainability into the fabric of operations and supporting it with certified CO2 accounting methods, they provide a pathway for downstream operators to thrive in a decarbonising energy system.
Conclusion Decarbonisation in downstream oil and gas cannot be achieved through compliance alone – it demands a strategic shift where energy efficiency and emissions reduction are built into every operational decision. Process automation, advanced instrumentation, and digital tools are the foundation of this transformation. Downstream operators need solutions designed to evolve with these needs. Whether enabling the flexible operation of refineries processing bio-feedstocks, integrating renewable power into petrochemical complexes, or supporting carbon capture and storage facilities, such solutions will provide the digital backbone for the low-carbon refinery of the future. Energy efficiency and CO2 reduction are no longer optional – they are central to long-term competitiveness. By harnessing developing technologies, and by adopting certified methodologies for CO2 accounting, operators can reduce their carbon footprint, strengthen competitiveness, and ensure long-term viability in the low-carbon economy. The journey ahead is complex, but the roadmap is clear: smarter operations, transparent data, and continuous optimisation will define the next era of downstream excellence. HYDROCARBON 49
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Dave Denison, Emerson, considers how hydrocarbon organisations can utilise centralised, cloud-enabled engineering tools to replicate best practices across sites, simplify troubleshooting and configuration maintenance workflows, while capturing enterprise-level performance gains.
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he hydrocarbon processing industry faces intense global competition, supply chain disruptions, mounting pressure for sustainable operations, and volatile markets – all conditions demanding maximum operational efficiency. In this challenging environment, companies must find new ways to extract every possible gain in efficiency, both at the plant level and across the enterprise. Historically, plant personnel and engineering teams have looked to increase operational excellence by innovating on control strategies, process graphics, and enhanced processes to deliver increased
production and efficiency. These efforts have generated substantial gains, enabling organisations to achieve higher output safely. However, many companies are discovering that traditional plant-level approaches are reaching diminishing returns, signalling the need for more comprehensive, enterprise-wide strategies. Forward-thinking organisations are now focused on finding more sophisticated approaches to engineering across their enterprises. The key lies in systematically identifying the best-performing plants, teams, control strategies, and practices. Companies must then replicate these successes across all sites. Traditional approaches involving dedicated teams, extensive site visits,
and significant investments of time and resources could theoretically accomplish this goal. However, few companies have enough expert engineers to sustain such efforts, and constant change in plant environments can make results short-lived. A more effective and scalable solution uses purpose-built enterprise engineering software, leveraging the latest technologies to deliver comprehensive visibility, while enabling standardisation through a single, centralised platform.
A challenging environment Gaining visibility of control systems across multiple plants using traditional methods is neither fast nor easy.
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Conventional control system design has focused on isolating systems to secure mission-critical operations. This architecture makes it difficult to gather data directly from these systems and complicates the task of managing fleets as a cohesive whole. Today, most centralised engineering teams wanting to gain visibility of the control system’s engineering data across the enterprise must manage exported configuration files manually, which can be complicated to keep organised and up to date. Engineers may also attempt to access configurations by connecting to each site’s systems remotely, but that effort may compromise security to access these systems, and it can be both time-consuming and operationally risky (Figure 1). Once the engineering team has all its configuration files, they often need to leverage third-party tools to
Figure 1. Today’s engineering teams are often more centralised and collaborative, and they need access to cloud technologies that increase visibility of configurations across the entire enterprise.
browse, search, or compare data, adding cost and complexity. Moreover, the team is typically working with raw data, which comes with little to no context from the control system, making it difficult to accurately identify key issues. Modern enterprise engineering software transforms this landscape by addressing these challenges. Purpose-built by the automation supplier, these platforms centralise visibility across multiple control systems, whether distributed throughout an enterprise or within a single complex facility, while maintaining the security integrity that operational teams require. The result is improved visibility, easier standards compliance, and efficient configuration management.
Improved enterprise visibility Enterprise engineering software empowers centralised engineering teams by providing far greater visibility into the configuration of every control system across the enterprise. Leveraging edge compute environments, enterprise engineering tools transfer system configurations to a cloud environment via secure connections. Engineers can remotely access the cloud system from any location, with role-based access control providing a customised experience that displays configurations of all authorised systems within their scope of responsibility (Figure 2). This type of centralised cloud repository transforms traditional workflows by eliminating the need for engineers to manually collect configuration files. Real-time synchronisation with on-premises control systems ensures that the configuration data remains current and accurate, with changes automatically reflected as soon as they are implemented at an individual site. This continuous synchronisation provides engineering teams with confidence that they are working with the most recent system information when making critical decisions. Beyond current configurations, the platform also maintains historical archives, enabling engineers to track configuration changes and trend performance over time. This historical perspective proves invaluable for root cause analysis, particularly when investigating issues that may stem from control system modifications.
Simpler standards compliance
Figure 2. Enterprise engineering software leverages the cloud and edge environments to provide improved visibility into the configuration of every control system across the enterprise.
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Whether verifying deployment of uniform control strategies enterprise-wide, confirming that operations teams utilise appropriate graphics at each location, or enforcing recipe standards across specialty chemical manufacturing sites, central engineering groups promote standardised control module and graphics libraries to ensure consistent, proven operations. Organisations approach standardisation through various strategies. Some rely primarily on automation supplier-provided libraries as their foundation. Others develop
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engineering personnel have made it difficult to allocate staff effectively across wide areas. Comparing configurations has always been possible by using third-party tools, but with limitations. These tools are often complex to use, and identifying differences in configuration required both expertise in the software and many hours of manually manipulating data. With purpose-built enterprise engineering software, engineers can view multiple control system configurations side-by-side in a single dashboard. This allows them to instantly and intuitively see what is different between two or Figure 3. Enterprise engineering software enables teams to more more systems. The team can also run regular easily make, test, and implement changes using their digital twin reports from the enterprise engineering simulation software. software to alert them when changes are made to systems anywhere across the enterprise. After the engineer has identified an issue, they can comprehensive custom corporate libraries tailored to their recommend configuration changes and send those specific processes, while many adopt hybrid approaches recommendations to the sites where they should be that combine vendor standards with proprietary implemented. Or, in the case of greenfield engineering, modifications to optimise both consistency and a user can create corporate templates and roll out working operational effectiveness. configurations across multiple sites quickly and easily, Typically, the goal of a standardised engineering library helping the company replicate its best practices to lock in is to ensure all sites across the enterprise are pulling control operational excellence. elements from the libraries to create a single source of Enterprise engineering software can also be used to truth across the organisation. When the engineering team compare a site’s digital twin simulation with its associated knows it has a single source of truth for all sites, production system. The engineering team can make and modifications, updates, upgrades, and maintenance are all test configuration changes in the digital twin, exploring a much easier to perform. wide range of options with no risk to plant productivity Over time, however, many sites tend to customise and safety. When they have a solution that meets their control strategies, graphics, and more. With each deviation needs, the team can merge the changes into the across the enterprise, it becomes more difficult for production server (Figure 3). engineers and maintenance personnel to perform critical tasks like troubleshooting. In addition, each change runs the risk of causing problems. If a process is not running, Support for the tools driving the future or is running sub-optimally due to a change, engineers of automation need a way to quickly identify and understand the change The most advanced enterprise engineering software is also so they can troubleshoot more efficiently. designed to leverage AI tools to help improve engineers’ With enterprise engineering software, the central efficiency. Using natural language, users can ask critical engineering team can log into the cloud application and questions of the software without the need to develop immediately see what configuration elements a site is complex query statements. For example, users can simply currently using and compare those with the corporate ask the software to show everywhere across the enterprise standard elements. Using historical data, engineers can where a specific standard is being used, or where it has quickly identify when changes were made and correlate been changed. They can even ask questions about the these modifications with changes in performance and configuration itself, such as tracing references between functionality of the process. control logic components, or identifying all the Teams can also use enterprise engineering software to areas where the production system differs from the perform benchmarking across the enterprise. If the simulation environment. company has similar processes or units across different sites, or even the same large facility, they can track and Capturing competitive advantage trend how modifications have improved or degraded Thriving in today’s complex hydrocarbon industry means operations over time and across geographic boundaries. capitalising on every opportunity to increase efficiency and operational excellence. For most organisations, this demands a shift toward comprehensive enterprise-wide Comprehensive configuration optimisation that transcends individual plant management improvements. Modern software solutions, particularly When an organisation needs to manage multiple control enterprise engineering platforms, not only help teams systems, they can dramatically increase efficiency by having identify opportunities to drive more value, they also a single central location to access their engineering data. provide a streamlined solution to execute them faster and While this has always been true, it has become increasingly easier than with traditional methods. valuable in recent years, where shortages of expert January 2026 54 HYDROCARBON ENGINEERING
José Miguel González, TECAM, Spain, explores how emissions control systems can align with emerging trends across the hydrocarbon processing sector, to ensure optimised and sustainable operations.
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s environmental regulations become increasingly stringent worldwide, industrial operators in the hydrocarbon sector face increasing pressure to reduce their atmospheric emissions without compromising operational efficiency. The need to align production with sustainability objectives is driving a deep transformation in how emissions control systems are conceived, designed, and integrated within plant operations.
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n Reduced footprint and CAPEX: modular designs integrated into process skids minimise space requirements and installation time. In practice, this means that emissions control is no longer a passive compliance measure, but an active contributor to plant efficiency.
Emerging technology developments
Figure 1. RTO system for VOC emissions abatement at a chemical plant in Barcelona, Spain.
This article explores the evolution of emissions abatement technologies in refineries and petrochemical plants, focusing on emerging trends such as process integration, digitalisation, modular engineering, and lifecycle optimisation. The objective is to provide a technical perspective on how emissions control systems are evolving to meet the dual challenge of compliance and competitiveness.
The regulatory and operational context Regulatory frameworks such as the European Industrial Emissions Directive (IED), the US Clean Air Act, and local emission limit values are tightening across various regions. For operators, the challenge lies not only in compliance, but in ensuring that abatement systems remain adaptable to new feedstocks, fluctuating production rates, and decarbonisation pathways. In parallel, refineries and petrochemical facilities are undergoing transitions in their product mix – integrating renewable feedstocks, recycling streams, and bio-based components. These shifts often alter the composition and load of volatile organic compounds (VOCs), hazardous air pollutants (HAPs), and other emissions. As a result, conventional abatement systems designed for constant state conditions are being pushed to their limits. The industry is therefore moving towards more flexible and intelligent emissions control systems, capable of maintaining performance across variable conditions while reducing total lifecycle costs.
The shift towards integrated emissions control Traditionally, air pollution control systems were considered add-on units – installed downstream of process equipment to capture pollutants before discharge. This ‘end-of-pipe’ approach is increasingly giving way to integrated emission management strategies, where the abatement system is engineered as part of the overall process design. Integration offers multiple advantages: n Thermal and energy recovery: waste heat from thermal or catalytic oxidation units can be reused for process heating, steam generation, or feed pre-heating. n Shared utilities and controls: centralised control systems allow emission units to interact with process data, optimising air flow rates and burner modulation. January 2026 56 HYDROCARBON ENGINEERING
Regenerative thermal oxidisers (RTOs) evolution
RTOs remain the dominant technology for treating VOCs and HAPs in hydrocarbon processing. However, their design has evolved substantially in recent years. The latest generation features: n High-efficiency ceramic media that achieve over 95% heat recovery, reducing fuel consumption. n Dynamic flow reversal systems controlled by predictive algorithms to stabilise temperature and flow. n Smart valves and actuators for faster switching cycles, extending the lifespan of components and minimising pressure fluctuations. In hybrid configurations, RTOs can be combined with selective catalytic reduction (SCR) systems for simultaneous VOC and NOX removal – an increasingly attractive solution for facilities with multi-pollutant emission flows.
Catalytic and low-temperature oxidation
For processes where exhaust streams have lower concentrations or oxygen sensitivities, catalytic oxidation offers a high-efficiency alternative. The introduction of advanced catalysts, including precious-metal-free formulations, allows these systems to operate efficiently at lower temperatures and to handle more complex gas compositions. The focus is now shifting to catalyst durability and regeneration, given that exposure to silicon, sulfur, or halogenated compounds can rapidly degrade performance. Continuous research in catalyst coatings and washcoat formulations is extending operational lifetimes and reducing maintenance frequency.
Solvent and carbon capture systems
Emissions control is also converging with carbon capture and solvent recovery technologies. In many refineries, VOC streams contain valuable hydrocarbons that can be condensed or adsorbed for reuse. Integrating adsorption units (activated carbon, zeolites) with oxidation systems enables selective recovery before destruction – turning what was once a waste stream into a resource. Meanwhile, the increasing deployment of post-combustion CO2 capture requires careful consideration of upstream air quality control, as contaminants such as SOX, NOX, and VOCs can impair amine solvents and membranes. Designing emissions control systems with carbon capture compatibility is therefore becoming an essential design criterion.
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The role of digitalisation and predictive maintenance Digitalisation is reshaping emission management, providing real-time visibility and control across entire plants. Through Industrial Internet of Things (IIoT) platforms and advanced process analytics, operators can monitor emissions continuously and adapt system parameters dynamically. Some of the key digital capabilities being adopted include: n Continuous emissions monitoring systems (CEMS) integrated with predictive analytics to detect deviations before limits are exceeded. n Model-based control (MBC) for oxidiser and scrubber units, optimising temperature and residence time based on process load. n Digital twins that simulate system behaviour under varying feed conditions, aiding both design and operations. n Condition-based maintenance that replaces scheduled interventions with data-driven actions, reducing downtime and extending component life. The outcome is a move from reactive to proactive emissions control, where systems self-adjust to maintain compliance while minimising operational costs.
Modular and scalable engineering The hydrocarbon sector is increasingly favouring modular engineering approaches for both new and retrofit installations. Modularisation enables faster project execution, improved quality control, and easier future expansion. From an emissions control perspective, modularity provides scalability to match phased production increases, simplified logistics for remote or space-constrained sites, and standardisation that reduces engineering time and simplifies spare parts management. Pre-assembled RTO or scrubber skids can be fully tested before shipment, reducing commissioning time and minimising disruptions during plant integration.
Lifecycle optimisation and sustainability Thinking about the lifecycle is becoming a key differentiator in emissions control projects. Beyond initial performance, operators are assessing systems based on their total environmental footprint – including materials, energy consumption, and end-of-life recyclability. Several trends are shaping this approach: n Energy recovery optimisation: integrating heat exchangers and economisers to minimise auxiliary fuel use. n Low-carbon materials: utilising stainless steels and refractories with lower embodied CO2. n Simplified maintenance access: reducing the need for high-temperature shutdowns. n End-of-life design: recyclable packing media and reusable structural components. January 2026 58 HYDROCARBON ENGINEERING
Furthermore, emissions control is increasingly viewed within the broader framework of industrial decarbonisation.
Regional and industry differences While emissions control principles are universal, their implementation varies widely across regions and industrial sectors. In Europe, policy instruments such as the EU Emissions Trading System (ETS) and Industrial Emissions Directive are driving facilities towards high-efficiency abatement and continuous monitoring. In North America, flexible performance-based standards are stimulating adoption of hybrid systems that combine thermal oxidation with recovery stages. In the Middle East and Asia-Pacific, rapid industrial expansion and diversification are increasing demand for scalable, modular solutions that can adapt to new chemical processes and feedstocks. Across all regions, the emphasis is converging on technology reliability, maintainability, and adaptability rather than purely on destruction efficiency.
Future outlook: towards emission neutral operations Looking ahead, emissions control will continue to evolve from compliance-driven to performance-driven design. Three major developments can be anticipated over the coming decade: n Integration with decarbonisation and energy efficiency programmes – linking emission reduction to carbon neutrality goals. n Increased use of AI and machine learning to optimise multi-unit control and predict equipment performance. n Circular approaches where emissions are not only destroyed but valorised through recovery and reuse of byproducts or heat. Ultimately, the future of emissions control in the hydrocarbon industry will depend on the ability to combine robust engineering with adaptive intelligence – delivering systems that are efficient, modular, and resilient to both market and regulatory change.
Conclusion Emissions control in the hydrocarbon sector is entering a new phase defined by integration, intelligence, and sustainability. The technologies themselves – from thermal to catalytic oxidisers and scrubbers – are mature, but the way they are engineered and operated is transforming rapidly. By including emission management into process design, leveraging digital tools, and focusing on lifecycle efficiency, the industry can achieve a balance between environmental performance and operational excellence. This evolution is not only a response to regulatory demands but an opportunity to enhance competitiveness, resilience, and responsibility across the global hydrocarbon value chain.
I
Ed Everett, Castlet, UK, explores how planned maintenance on electrostatic precipitators and their power control systems can minimise disruption across oil refining and petrochemical operations, ensuring efficiency and cost optimisation.
n industries such as oil refining, petrochemicals, and gas processing, keeping equipment running efficiently is essential to maintaining compliance, productivity, and profitability. Electrostatic precipitators (ESPs) and their power control systems play a vital part in maintaining this efficiency. When these systems fail unexpectedly, the consequences can be highly disruptive, causing costly downtime, environmental non-compliance, and sometimes enforced shutdowns. To prevent system failures, planned maintenance on ESP power control systems is crucial in preventing problems before they occur – rather than relying on emergency callouts when it may be too late. This article explores the difference between planned maintenance and emergency callout response approaches, how proactive strategies can help prevent ESP control system failures, and highlights best practices for plant operators who cannot afford unplanned downtime.
The role of ESP power control systems in emissions control With air pollution rising, advanced engineering solutions play a key part in helping heavy industries to improve the performance of their ESPs to ensure particulate emissions stay within regulatory limits. ESPs remove fine particles such as dust, ash, or smoke from industrial exhaust gases. These innovative devices are designed to remove fine dust particles from a flowing gas stream using electrical energy. The system supplies and regulates the high-voltage current needed to charge particles so they can be captured efficiently. Usually, ESP power control systems include transformer-rectifier units that convert alternating current into the high-voltage direct current required for operation. This process also involves control cubicles and electronic controllers which manage voltage, current, and HYDROCARBON 59
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rapping sequences. These functions ensure safe and consistent performance to manage dust particle capture. However, over time, the combination of electrical stress, high operating temperatures, and environmental exposure can lead to wear and deterioration of ESP systems. Common issues within ESP systems can stem from transformer rectifier faults, degraded controller hardware, loose or corroded electrical connections, and poor airflow through cooling systems. Minor issues can quickly escalate, reducing the efficiency of the ESP. The impact of this can cause knock-on effects across the plant, disrupting production, causing emissions levels to rise, and incurring potential repercussions both financially and reputationally.
The hidden cost of unplanned failures When a fault occurs unexpectedly, plant operators typically rely on emergency callouts to get systems back online. While this reactive approach is often necessary, it can come with significant drawbacks. Emergency repairs usually involve higher repair costs due to engineers working overtime, the delivery of necessary parts, and lost production time. In industries that operate continuously, even a few hours of downtime can result in substantial losses. Beyond the cost implications, unplanned failures can lead to regulatory non-compliance if emissions rise above permitted levels. For operators in regulated sectors like refining or petrochemicals, a temporary breach can trigger fines, mandatory shutdowns, or damage to environmental credentials.
Furthermore, not planning ahead can place strain on staff and resources, as engineers must work under pressure to restore function rather than optimise performance. This increases the chance of future issues arising, with more of a temporary fix in place than a permanent solution.
Preventative maintenance strategies To mitigate against future ESP power system failures and promote cost-effectiveness, plant operators must put a proactive strategy in place when it comes to maintenance. This strategy can look different depending on the unique demands of different ESP power control systems, however it usually involves scheduling inspections, testing, and regular servicing to ensure all components are functioning correctly and that potential faults are identified before they result in downtime. In practice, this involves a site visit from an engineer to undertake comprehensive works including cleaning, component testing, heat source checks, aeration, cooling and corrosion checks, to ensure the ESP power control system is running reliably and efficiently. It is therefore beneficial for plant operators to have a relationship in place with an experienced engineer to ensure these checks are carried out as planned. By detecting signs of wear and tear early on, operators can avoid unplanned stoppages that cause disruption to production. Regularly scheduled repairs can improve overall reliability and ensure that ESPs continue to operate within emission limits. It can also extend the lifespan of system components, helping operators to get the most from their investment while maintaining predictable (and budgeted) preservation costs. A preventative strategy can also give operators confidence that they are fully compliant with environmental and safety regulations. Over time, data gathered from routine site visits can be used to improve performance, allowing maintenance schedules and component lifecycles to be adjusted based on insights.
Unexpected emergency callouts
Figure 1. A new three-phase MCSIII control cubicle during the final stages of installation.
Even with a firm plan in place, emergencies can still arise. From component failures to sudden faults in the transformer rectifier or control system, there are many emergencies that can bring operations to a halt. In these situations, emergency response is crucial to minimise disruption and restore the plant to normal operating conditions in a safe and timely manner. It can therefore be beneficial to have an existing relationship in place with a site engineer, to ensure a safe pair of hands in the result of an emergency. When issues arise, engineers can be deployed to quickly diagnose and control functionality and implement temporary or permanent solutions depending on the severity of the issue. This fast, expert response ensures that operations resume as quickly as possible while maintaining safety and compliance standards.
The benefits of planned maintenance
Figure 2. Maintaining transformer rectifier units from the roof of an electrostatic precipitator.
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While emergency callouts do sometimes happen and can be a good safety net, relying on them as the primary maintenance strategy can be costly. A reactive strategy tends to shorten the lifespan of critical equipment, as repeated high-stress incidents can accelerate system degradation. It also leaves operators vulnerable to unpredictable costs and unplanned downtime,
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Figure 3. A Castlet Site and Service Engineer optimising an MCSIII control cubicle.
strategy in place to manage spare parts and ensure they are readily available. This could include controllers, rectifiers, cooling fans, and surge suppressors, to allow operators to carry out regular checks, and to respond quickly if an issue arises. Regular optimisation and upgrades are also key. Over time, control systems evolve, and retrofitting older ESP controllers with newer models can significantly improve reliability and functionality. Documentation is another aspect that should not be overlooked. Maintaining detailed records of inspections, calibrations, and repairs provides evidence of compliance and helps track recurring issues. Sharing this information across operations and engineering teams creates a unified understanding of system health and supports informed decision-making. Finally, operators should prioritise continuous improvement. Each maintenance cycle offers an opportunity to review what worked, what did not work, and how procedures can be refined. Over time, this feedback loop helps to optimise performance and minimise downtime.
Case study both of which are difficult to manage in busy production environments. It is clear that planned maintenance therefore has many benefits over a reactive, emergency response approach. A proactive schedule allows operators to control costs and plan work around production windows, minimising disruption. In contrast, emergency repairs are reactive, unpredictable, and often more expensive. From a reliability standpoint, regular check-ins ensure consistent system availability and performance. Emergency callouts, by their nature, occur only after a fault has already caused disruption. Planned reviews also support compliance, as equipment performance and emissions levels are continually monitored and adjusted. With reactive repairs, there is always a higher risk of operating outside specification before a problem is detected. Over the lifespan of an ESP system, proactive maintenance delivers better reliability, lower total cost of ownership, and longer asset life. Emergency callouts should be seen as a necessary contingency rather than a primary strategy.
How to integrate maintenance into wider plant operations For operators in uptime-critical industries, such as oil refining and petrochemicals, integrating maintenance into wider operational planning is essential in ensuring optimal efficiency and productivity. To avoid disruption, it is important for scheduled works to align with production cycles and planned shutdowns across the wider plant. Any activities should also be planned based on historic data from the equipment. Modern ESP control systems, such as Castlet’s MCS III series, can log alarm histories, voltage trends, and spark frequencies. By analysing this data, early warning signs can be identified – such as system stress – to allow workers to intervene before a fault develops. Another element to consider when planning maintenance is spare components. The service provider should put a robust January 2026 62 HYDROCARBON ENGINEERING
Reliability and responsiveness are critical in maintaining compliance, productivity, and profitability for plants in energy-intensive industries. Planned maintenance plays a crucial role in achieving this and futureproofing ESP control systems keeps plants running and emissions under control. Castlet manages various ESP power control systems across the oil, gas, petrochemical, and heavy industrial sectors. A client required a solution to reduce maintenance turnaround time for ESP cleaning. The engineering team designed, assembled, and commissioned an MIGI rapper control panel to energise multiple rapper devices on programmable cycles and intensives, and offer flexible, microprocessor-based control logic for optimised cleaning under varying operating conditions. This solution identified the device number and fault cause on the panel’s display, enabling fault-reporting functionality and allowing any intensity adjustments to be made easily. The integration of fault detection resulted in easier upkeep and encouraged an open line of communication with upstream power controls and the facility’s DCS/PLC. Furthermore, this resulted in reduced energy consumption, enhanced uptime, and future-proof flexibility for their system, with Castlet offering ongoing support both remotely and on-site.
Futureproofing plant operations Through a planned maintenance programme incorporating regular inspections, calibration, and system testing, ESP power supplies and controllers are guaranteed to perform reliably under demanding operating conditions. Through early diagnosis and the resolution of faults, operators can minimise downtime and keep facilities operating compliantly – avoiding unplanned outages and the knock-on cost effects of irregular emissions output. It is important to upgrade legacy control systems to modern platforms to extend asset life and enhance data visibility for better decision-making in the future. By investing in scheduled maintenance for ESP power control systems, operators can reap financial savings and achieve greater reliability, safety, and peace of mind.
Lenny Shaver, Advanced Energy, and Mike Schoneman, Speed Valve & Specialty, offer a technical analysis of long-wave infrared imaging (LWIR) systems for flare pilot verification and assist gas reduction.
T
he US Environmental Protection Agency (EPA) regulation 40 CFR 63.670 requires that industrial flares ‘be operated with a flame present at all times when regulated material is routed to the flare’ and requires the facility owner to ‘continuously monitor the presence of the pilot flame’ to prevent the atmospheric release of hazardous, uncombusted waste gases. Meeting this requirement presents both technical and financial challenges for hydrocarbon processing facilities.
Traditionally, monitoring has relied on techniques such as thermocouples or pyrometers, which can lead to significant reliability issues. Placing thermocouples directly into flames causes both thermal shock and corrosion, whereas pyrometers (though non-contact technology) are susceptible to signal loss and inaccuracy during weather events including heavy rain, fog, or snow. Resulting failures create risk for the plant – either regulatory non-compliance or a potentially costly and lethal industrial incident. HYDROCARBON 63
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There are ways to mitigate the risk of a failed sensor. For example, facilities often resort to putting out a high baseline flow of assist gas – about 5500 - 6100 standard ft3/hr – which ensures the pilot flame is large and hot enough to be detected. The downside is that gas is expensive; and this inefficient practice leads to waste, inflated operational costs, and unnecessary emissions. An alternative approach for monitoring flare stacks, based on long-wave infrared (LWIR) thermal imaging systems, addresses these challenges. This article will take a closer look at this approach and illustrate how a major petrochemical facility adopting LWIR cameras was able to reduce assist-gas flow by 70%. This resulted in first-year operational savings of almost US$1 million and anticipated annual OPEX savings of nearly US$2 million.
LWIR camera setups As mentioned previously in this article, any solution for flare stacks ideally needs to be non-contact. Non-contact IR-based measurement is already on the list of technologies accepted by the EPA. In addition to delivering non-contact measurements, LWIR systems are minimally affected by fog, rain, snow, or any other harsh weather conditions due to a spectral operating range between 8 - 14 µm. Furthermore, the development and integration of microbolometer sensors have enabled greater levels of miniaturisation and reliability. As costs have fallen, LWIR cameras are also increasingly being used for flame stack monitoring. They are widely considered as best-practice technology for new installations and for facilities looking to improve safety, ensure compliance, and reduce operational costs. However, the technology is not universally adopted. Wider adoption has been limited by perceptions that implementation requires significant upfront capital expenditure and that there are operational hurdles of integrating an advanced technology into established plant infrastructure and workflows.
Case study To address these concerns, this section explores a recent real-world implementation for flaring stacks, using a FlareSpection camera, to examine the operational savings from such a system. This camera is a non-contact thermal imaging technology designed (and ATEX-certified) for the harsh and challenging environment of flare monitoring. Housed in a stainless steel, corrosion-resistant housing, the system features a microbolometer as its long-wave infrared sensor – a type of uncooled detector known for its thermal stability and durability. The result is a reliable imaging solution for complex and maintenance-intensive cooling systems. The sensor delivers a resolution of 640 x 480 pixels, which is sufficient detail to distinguish even small pilot flames from distances up to and beyond 300 m, even when the pilot flame is in front of a much larger flare event. Software is equally important and, in this implementation, the facility adopted LumaSpec RT real-time thermal acquisition and analysis software. This platform processes the raw thermal data from the camera and allows operators to define specific regions of interest (ROIs), with the ROIs configured to isolate and continuously monitor the precise zones where the pilot flames are located, separate from the main flare body. Operator set temperature thresholds and alarms alert when a thermal signature within a pilot’s ROI has dropped below the thresholds – i.e. when a potential flameout has occurred. Data outputs from the software are transmitted to the plant’s distributed control system (DCS) using standard industrial protocols, supporting integration that allows the thermal data to be used for both alarms and automated control. Additionally, LumaTrend, a thermal imaging software, and SQL Historian were implemented for long-term trend analysis. Finally, existing pyrometers were retained where applicable to serve as a redundant data point during the transition.
Implementation
Figure 1. Example of an oil refinery in wintery conditions.
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Step one in any such project is an analysis, identifying the optimal camera placements to give an unobstructed view of the pilot flames on all flare stacks. This is undertaken through surveys and, in this case, it was determined that the cameras could be effectively positioned at a distance up to 300 m from the stacks, keeping all sensitive electronic equipment away from the heat, vibration, and corrosive environment at the base of the flare.
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Figure 2. Identify pilot flame from distances of 300 m
(984 ft).
Weather conditions likely to be encountered also needed to be considered. In this installation, considerations included everything from hurricanes and low-temperature extremes to heavy snow and rolling fog, with weather-resilient enclosures installed on dedicated mounting poles. For data delivery, armoured fibre optic cables run to junction boxes and then back to the central control room, typically using the plant’s existing fibre network. Fibre gives a high-bandwidth signal and is also immune to electromagnetic interference to enable a noise-free signal. A vital aspect of any installation is the configuration of the operational workflow. ROIs were configured for each of the flare stacks and alarm thresholds set based on the known site-specific thermal characteristics of a healthy pilot flame. In this case, LumaSpec RT software was used to carefully map the specific locations of the pilot burners. While there were changes to previous measurement systems, these adjustments were kept to a minimum. The most significant modification to the plant’s operational workflow was the establishment of a new control loop for assist-gas modulation. This was implemented to enable the DCS to use thermal data from the cameras to confirm the pilot flame was lit and remove the need to run high volumes of assist gas as a safety buffer. Training after such a change is essential. Control room personnel need to understand the new system and be able to interpret the thermal imaging data as well as manage the new automated control loops.
Operational savings vs capital outlay
The initial question was one of cost. Is the shift to LWIR cameras worth the financial investment? In addition, every site will have its own unique requirements affecting the capital outlay (including cameras, housings, poles, and the establishment of a new control loop for assist-gas modulation, and other potential hardware and software) and operational savings equation. However, for the seven-flare facility described previously, the operational January 2026 66 HYDROCARBON ENGINEERING
and financial results of the project were immediate and substantial. For one representative flare, the facility was able to reduce the assist-gas flow and cost by over 70%. Previously, the flare had been operating with a flow rate of approximately 6000 standard ft3/hr, at a cost of more than US$400 000/yr. After the new system was commissioned and the control loop optimised, the assist-gas flow was safely reduced to 1800 standard ft3/hr. This reduction lowered the operating cost for that single flare to approximately US$120 000/yr: a per-flare saving of over US$280 000/yr. Across all seven flare stacks, the realised savings from the first year of operation have been reported at US$950 000. Further potential savings have also been identified, with calculated savings on assist gas being US$1.97 million/yr once the plan for further incremental reductions is completed. Beyond the direct economic return, the system provides a critical compliance benefit, giving a robust, reliable method for pilot verification that meets EPA requirements, functioning as a dependable primary system and providing a crucial back-up during the failure of legacy thermocouples (eliminating the risk of non-compliance events associated with sensor failure). Furthermore, the automation of the system reduced the need for manual operator intervention and provided a continuous, verifiable record of pilot status, enhancing both safety and operational efficiency.
Findings The use of LWIR cameras delivers both a robustness and resilience to failure and challenging weather conditions that are not possible via thermocouples or pyrometers. The technology can scale well with a single system potentially monitoring multiple stacks. Its ability to integrate directly into a plant’s DCS facilitates process optimisation as well as critical EPA compliance. Vendor support can play a key role to smoothly migrate to this technology, not least when it comes to periodic tuning and optimisation. It is worth noting that the reduction of assist gas cannot be instantaneous but needs to be undertaken as part of an incremental, phased reduction strategy that maintains complete combustion and flame stability. This requires thorough operator training and validation against existing burner-indication instruments to build confidence and ensure safe operation at each new, lower flow rate. Further to this, flare and pilot characteristics will vary from stack to stack and operators should therefore set temperature and alarm thresholds for the ROIs for each stack, with careful validation undertaken. For maximum benefit, facilities should combine the real-time thermal data with their process historian to perform trend-based analysis, identifying further opportunities for optimisation. For example, future options for the facility cited in this article include expanding the system with additional cameras to cover other process units, pursuing further assist-gas optimisation, and using data to enable predictive maintenance analysis and long-term emissions reporting.
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Axens
Axens is focused on the decarbonisation of aviation through the use of its JetanolTM and VeganTM technologies, which contribute to sustainable aviation fuel (SAF) production. Vegan is Axens’ HEFA technology, ensuring full flexibility from 100% renewable diesel to 100% SAF production. This can be achieved thanks to the use of a robust process scheme and through Axens’ 700 series
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BASF
refining industry. BASF’s refinery catalysts business is part of the company’s Performance Chemicals division. The division’s portfolio also includes chemical catalysts and adsorbents, fuel and lubricant solutions, as well as oilfield chemicals and mining solutions. Customers from a variety of industries including chemicals, plastics, consumer goods, energy and resources, and automotive and transportation benefit from its innovative solutions.
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BASF is a leader in innovative catalysts for the petroleum refining industry, offering tailored fluid catalytic cracking (FCC) catalyst and additive solutions based on its customers’ specific needs. With a strong focus on customer-driven research and development, BASF continuously innovates its FCC Refining Catalysts portfolio, creating new technologies that enhance operational efficiency and profitability in the
Clariant Catalysts continues to lead innovations addressing global sustainability challenges. In 2026, its portfolio will further expand with technologies enabling carbon emission reductions across multiple sectors. MegaMaxTM catalysts are powering the green methanol lighthouse projects of European Energy in Kasso, Denmark, and of Shanghai Electric in China. The HyProGenTM 800 DCARB series enables efficient hydrogen production via ammonia cracking. The DRI catalyst solutions reduce carbon emissions in steel production, while StyroMaxTM UL-100 achieves
Crystaphase is a partner for reactor filtration, dispersion, and optimisation – clearing the path to performance in even the most challenging environments. Its technologies, including CatTrap®, ActiPhase®, HeavyTrap®, and RDT®, have been installed in thousands of units worldwide and help refiners reduce pressure drop, increase throughput, and extend cycle length. Crystaphase recommendations are backed by rigorous sample analysis and technical service. The team works closely with refiners to assess unit behaviour, identify subtle inefficiencies, and apply iterative, data-driven optimisations. RDT Technology is an innovative, patented solution that seeks to correct micro-maldistribution and mitigate radial temperature spreads (ΔT) by using loaded materials to enhance intra-bed distribution. Applied in a combined bed layer – an intermingling of catalyst and RDT media – RDT Technology is designed to
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Evonik Catalysts has been a leader in the catalyst and adsorbents industry for more than 80 years. The company provides a complete ‘one stop shop’ approach that includes innovative and sustainable catalyst products, comprehensive services, and expert customer support from specialist teams based around the world. Evonik Catalysts continues to place both customers and the environment at the heart of its operations – driving efficient, sustainable, and cost-effective chemical processes across key downstream applications, such as fuel desulfurisation, catalyst regeneration, and refining technologies. The company’s latest sustainable innovation, OctamaxTM, has been designed to improve sulfur removal performance in
January 2026 68 HYDROCARBON ENGINEERING
RDT Technology can improve temperature uniformity and deliver a meaningful cycle extension – without invasive capital modifications. For refineries seeking to unlock more value from its existing reactor hardware, RDT Technology offers a compelling, cost-effective, and evidence-based path forward.
refinery fuels while maximising octane retention, to preserve fuel quality. The technology combines regenerated NiMo and CoMo catalysts optimised under precise conditions for use in cracked gasoline hydrodesulfurisation (HDS) units. As a result, Octamax provides refiners with a cost-effective, high-performance solution for producing ultra-low sulfur gasoline, at a time when downstream operators are striving to balance commercial viability with environmental responsibility. By regenerating spent catalysts, Octamax helps reduce potential landfill waste and conserve valuable raw materials. Testing has shown Octamax to deliver improved HDS activity and comparable octane selectivity to conventional fresh catalysts, proving that sustainability does not require a compromise in performance.
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Johnson Matthey
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Merichem Technologies
the company also has advanced carbon products for mercaptan sweetening, offering flexible options to match process needs for effective, reliable performance. In addition, Merichem’s patented SULFURTRAP® solid iron-based adsorbent provides an easy, safe, and effective solution for H2S removal. It delivers high sulfur loading and low pressure drop even at end-of-run conditions, while its non-caking formulation ensures easier, safer changeouts and uninterrupted operation in its Skid-Mounted Lead/Lag Vessel System. These targeted sulfur removal solutions meet today’s environmental and operational demands while looking to build a more sustainable future.
MERYT Catalysts & Innovations
advanced materials. Project lines include conversion to fuels and improved purification technologies designed to deliver more efficient transformations with greatly reduced energy requirements. A major strategic effort of MERYT’s is the progress towards engineering scale-up of metal-organic frameworks (MOFs) for separation, purification, capture, and catalytic processes. MERYT is currently defining the design and capacity of its first MOF production line in Spain, positioning these materials as a
Heraeus Precious Metals is a global leader in the precious metals industry and covers the whole value chain of a wide range of products – from trading to precious metals products and the recycling of such products. With over 30 years of experience developing heterogeneous and homogeneous precious metal catalysts, Heraeus serves a wide range of industries, including gas purification, fine chem and pharma, the conversion of renewable feedstocks, and the hydrogen economy. The company’s strength lies in its advanced catalyst manufacturing capabilities. Heraeus combines in-depth materials science expertise with flexible production infrastructure to deliver standard and customised catalysts that are tailored to specific industrial requirements. This enables
Johnson Matthey (JM) is a global leader in sustainable technologies, applying cutting-edge science to help the downstream sector reduce emissions and improve efficiency. With over 200 years of innovation, JM partners with refiners and petrochemical producers to deliver proven, forward-looking solutions. In fluid catalytic cracking (FCC), JM is addressing the challenge of opportunity feedstocks through advanced additives that mitigate metal contaminants. These solutions enable refiners to boost base catalyst performance and enhance profitability. Supported by INTERCATTM addition systems and state-of-the-art advanced cracking evaluation (ACE) testing, JM ensures customers can optimise performance in real time.
Merichem Technologies brings over 50 years of expertise in sulfur management, delivering licensed process technologies, catalysts, carbon, and adsorbents that protect the environment, improve operations, increase profitability, and extend asset reliability. Merichem’s portfolio addresses hydrogen sulfide (H2S), mercaptans (RSH), and other sulfur contaminants across gas and liquid streams in a variety of sectors including refining, petrochemical, and renewable fuels. Merichem supplies proprietary catalysts designed for its licensed technologies, including high-performance formulations for H2S removal in gas treating, and RSH sweetening and extraction in liquid streams. For select technologies,
MERYT is a specialised provider of advanced catalytic and adsorptive solutions for the downstream refining and petrochemical sector. Over the past year, MERYT has expanded its technical activity to support operators processing increasingly complex feedstocks, including heavier, renewable, and more oxygenated streams. In parallel, MERYT is progressing several industry-focused research and development initiatives involving
January 2026 70 HYDROCARBON ENGINEERING
transformative option for high-efficiency refinery and petrochemical processes. Over the past year, MERYT has also increased its global footprint, expanding across Europe, China, and the Gulf Cooperation Council (GCC) region. Working with industrial partners and major academic institutions, MERYT continues to
drive new collaborative programmes, applying its technical and operational experience to deliver practical, high-impact solutions. The company is also advancing a flagship initiative to establish regional catalysts and MOFs capabilities to support the deployment of advanced materials – helping enable a more resilient, future-ready supply chain for the Middle East.
Rezel Catalysts Corp.
catalyst in China. This catalyst demonstrates excellent performance – including higher conversion rates and reduced coking – in a 500 000 tpy PDH unit. Concurrently, Rezel is expanding its global footprint through a strategic memorandum of understanding (MoU) with Aramco. Aiming to establish Saudi Arabia’s first catalyst manufacturing and precious metals reclaim plant, this initiative will enhance supply chain resilience for regional refineries and introduce advanced closed-loop environmentally sustainable catalyst manufacturing systems, underscoring Rezel’s commitment to providing localised, sustainable products and services for the global downstream sector.
Sabin Metal Corp.
world for safely and responsibly processing, sampling, and refining precious metal-bearing catalysts. Now in its ninth decade of worldwide service, Sabin specialises in the recovery and refining of platinum, palladium,
Rezel Catalysts Corp. is a leading global manufacturer and licensor of catalysts, offering innovative solutions for the downstream refining and petrochemical sectors. With a diverse portfolio that includes FCC, RFCC, and a comprehensive range of precious metal catalysts, Rezel is dedicated to providing high-performance, value-oriented technologies that improve operational efficiency and promote a more sustainable industry environment. Rezel recently marked a milestone achievement with the successful first industrial application of its independently developed chromium-based propane dehydrogenation (PDH)
The Sabin Metal Group of Companies provides customers with logistical support, precious metal financial services, pre-reclaim kilning, and some of the most sophisticated facilities in the
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ruthenium, rhodium (PGMs), plus rhenium, gold, and silver from spent precious-metals catalysts including zeolite, soluble and insoluble alumina, silica-alumina, and carbon. Sabin’s refined platinum and palladium are certified ‘Good Delivery’ by the London Platinum and Palladium Market (LPPM). n Sabin Metal Corp., Scottsville, New York, US, specially equipped for the intricacies of safely and accuracy processing, sampling, and refining a wide variety of precious metal materials. n Sabin Metal West, sampling for spent precious metals hydrocarbon catalysts; employs pyro-metallurgical
recovery of PGMs for maximum recovery of precious metals. n Sabin International Logistics Corp. (SILC), licensed hazardous waste, hazardous materials, and general commodities transporter; permitted and Licensed Freight Broker. Providing global transportation and logistics for precious metals materials door-to-door. n SMC (Canada) Ltd, in Cobalt, Ontario, Canada, processing technologies to extract the highest possible metal values from residual materials of refining, smelting, and milling operations.
UNICAT
non-restrictive flow distribution and extend unit cycle times by at least 50%, directly enhancing profitability and uptime. Collaboration is central to the company’s approach. By partnering closely with customers and industry leaders, UNICAT ensures its technologies solve real world problems, reduce costs, and unlock new opportunities. The recently commercialised pre-reforming catalyst technology is designed to protect downstream reforming catalysts, reduce carbon formation, and extend overall unit cycle life and performance, while future developments in pressure swing absorption promise further transformative benefits. Guided by brand values of innovation, collaboration, and profit-enhancing solutions, UNICAT continues to invest in technologies that empower customers, strengthen financial outcomes, and drive sustainable progress across industries.
UNICAT is dedicated to revolutionising catalyst technology, delivering improved customer experience, financial outcomes, and operational performance. At the heart of its mission is innovation, driven by engaging with customers to develop a pipeline of solutions that create measurable value. The breakthrough Magcat® Textured Sphere catalysts represented a leap in technology and performance, offering excellent strength, increased geometric surface area, enhanced heat transfer, and reduced pressure drop. This innovation was recognised with the prestigious Queen’s Award for Enterprise Innovation (2022). In addition, UNICAT has enhanced its Advanced Filtration System (AFS) technology, optimising uniform flow channels to maximise foulant capture. These improvements deliver
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