Capital priorities in the downstream industry
Margins opportunities in chemicals and biofuels dominate long-term investments.
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The refining industry is a core component of any modern economy, ultimately providing the energy, fuels, and chemicals required for global development.According to BofA Global Research of America, throughout most of the last half-century, every 1% change in world GDP tended to translate into a 1% change in energy demand. However, historic refinery closures during the 2020-21 pandemic created a deficit in 2022.
Sanctions such as those recently imposed on Russia and an inability to respond to price signals are creating inefficiencies for refiners globally while they search for more supply amidst demand destruction. But with feedstock and raw material shortages, and high energy costs, turning challenges into opportunities could possibly be enhanced by setting objectives, executing strategies, and adapting new technology.
Some objectives include alleviating naphtha deficits such as heavy naphtha to maximise downstream aromatics production. Execution of connectivity strategies is another important objective and is foremost to linking renewable and biofuels processes to downstream operations, affecting everything from fuels and olefins production to plant utilities.
Refiners in major markets from Asia to North America are seeing value in reconfiguring the final conversion section of a refinery towards naphtha production, considering long-term downward projections for fossil-based gasoline and diesel. We are seeing market incentives to maximise intermediate streams, including light and heavy naphtha for olefins and aromatics production.
To date, plant capacity, complexity and level of integration have influenced the amount of naphtha a refinery can deliver to steam cracking facilities and aromatics units. Against this backdrop, the current global average crude oil-to-chemicals (COTC) is about 8-10% conversion to chemicals per barrel of oil.
For a very well-integrated complex such as Petro Rabigh in Saudi Arabia, each complex can achieve 17-20% conversion to chemicals. However, information from Axens emphasised that announced COTC projects could produce about 40% of chemicals per barrel of oil. The scale of conversion delivered with COTC technology provides an additional competitive factor over current world-scale petrochemical facilities.
Integrated COTCs facilities are more complex to operate, so optimising the process configuration and associated catalytic and thermal conversion assets will ensure operability and productivity. It is no secret that higher complexity requires higher capital investment, predicating a staged investment strategy to spread out CAPEX over longer periods.
Complexity apparently favours process licensors who can provide the best-integrated technologies to convert heavier crude assays to produce maximum chemicals with the least utilities and hydrogen consumption (preferably from green hydrogen sources).
Along with plans to link refiners to the petrochemical value chain, processing renewable and biomass-derived feedstock through hydroprocessing and FCC units has gained favour with investors in transitional and sustainability-focused markets. However, routes to producing renewable fuels with existing refinery assets are not without their challenges.
For the expanding fuels market, the focus on FCC and hydrotreating for coprocessing fossil feedstocks with triglyceride-rich biomass feedstock and other highly oxygenated feedstocks such as pyrolysis oils has created new process and operational challenges.1
Like the challenges refiners faced with the introduction of shale-based crude feedstocks a decade ago, resolving the operational nuances with renewable feedstocks is ongoing. Some of the challenges have involved:
• Achieving targeted density and cold flow pour point (CFPP)
• Co-processing renewables can be hindered by high oxygen content (in the oxygenated compounds), predicating exothermic reactions and high hydrogen consumption
• High acid numbers in many renewables increases corrosion risks due to the presence of high chlorine content and carboxylic acids
• Contaminants in renewables (Si, P) depositing on catalysts increase pressure drop and accelerate deactivation.
Further downstream, the plastics ecosystem is not without its own technical challenges. Plastics production and recycling are firmly in a transition where companies keep resources in use, if possible, and then recover and regenerate valuable products and materials at the end of life.Moreover, this transition is bringing forward challenges to balance emissions with circular plastics end-of-life goals.
Low CAPEX optimisation strategies
For too long, low-ranking CAPEX improvement projects have led to antiquated control systems. With rapidly increasing energy costs affecting energy markets, refineries and chemical plants are pursuing high-impact solutions based on first-principles methods (in-house or outside expertise) while also adapting enabling technologies from other industries, such as AI/ML, as discussed in the following summaries:
Fired heater optimisation
Hiding in plain sight, fired heaters are major emitters of GHGs in the hydrocarbon processing industry. Incomplete fuel gas combustion through furnaces and the use of excess air leads to higher toxic emissions. In addition, fuel quality variations and trying to increase production using ageing heaters and boilers can lead to a breakdown in control, safety, and thermal efficiency.
From the crude distillation unit’s (CDU) furnace at the front-end of a refinery to world-scale furnaces seen in steam crackers, most fired heaters are designed for a thermal efficiency of 70-90%, whereas actual operating efficiencies are much lower. As the furnace ages, these challenges further exacerbate, leading to early replacement.
While modern furnaces have electronics that gather data, there is minimal ability to perform real-time analytics and predict events in advance or provide predictive insights into interventions needed for optimal operation. According to Avnish Kumar at LivNSense, even a 1% reduction in energy consumption from furnace operations will lead to reduction of millions of tons of atmospheric emissions (equivalent savings of $5 billion/per annum).
Utilising existing assets
The Calumet Specialty Products Partners L. P. $50 million renewable hydrogen project in Great Falls, Montana, USA, allows increased production of renewable diesel and further reduces carbon intensity. Utilisation of an existing hydrocracker reduces CAPEX while still being able to produce 77 million gallons per year (mgpy). More importantly, once a renewable H2 production unit and feedstock pretreatment unit are completed, total renewable diesel production is expected to reach 153 mgpy.
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