Strategic revamps can offer a cost-efficient fast track to renewable fuel production

Growth in renewable fuels is offering refineries and new entrant producers opportunities with significant potential. Incentivization, mandates and regulations, from the EU’s ReFuelEU Aviation regulations to the US Renewable Fuel Standard developments, are creating an expanding market – and early movers can take full advantage.

But the clock is already ticking when it comes to renewable diesel and sustainable aviation fuel first mover advantages. Building greenfield capacity answers part of this challenge, but for existing refineries, converting what already exists toward renewables offers a fast-turnaround, and lower CAPEX option, explains Ole Frej Alkilde Lead Technology Manager and Lars Jørgensen, Technology Chief Specialist at Topsoe.

Hydroprocessing units designed for fossil fuel treatment can produce renewable diesel and SAF with modifications. The principle is the same. Hydrogen treatment under pressure and temperature over catalyst beds. The chemistry shifts, however, meaning oxygen-rich feedstocks like vegetable oils and animal fats demand different catalyst loadings, material selection or metallurgy upgrade and heat integration to petroleum fractions. These differences are manageable through revamp engineering that preserves the core asset while adapting it to new molecules.

And the good news? Revamps are commercially proven for defined feedstock windows and hydrogen availability, provided front-end studies are done rigorously. Twenty years of commercial operation have demonstrated this approach delivers reliable renewable fuel production. The question refiners now face is less about technical feasibility and more about implementation strategy.

Understanding the spectrum from co-processing to full revamp

The conversion of existing hydroprocessing units to renewable service spans a wide spectrum of intervention levels, each with distinct technical and commercial implications.

Low-level co-processing (typically 5–10%) represents the lightest-touch entry point. At these levels, well-pretreated renewable feedstocks can often be introduced with limited changes to hardware. Adjustments focus on catalyst selection, reactor temperature profiles and operating severity. Capital expenditure is minimal, and implementation can usually be aligned with a planned turnaround.

Feedstock quality is critical at this stage: elevated chlorides, phosphorus or metals can quickly negate the apparent simplicity of co-processing.

As renewable content increases beyond 10–20%, constraints become more pronounced. Hydrogen consumption rises, heat release profiles change, and corrosion risks increase due to halogens and higher water partial pressure. At this scale, revamps typically require targeted metallurgy upgrades, revised heat integration, hydrogen system debottlenecking and, in some cases, pretreatment enhancements. These projects still leverage existing infrastructure but demand a structured engineering approach and capital investment.

Full renewable conversion (up to 100%) represents the most extensive revamp scope. Units are operated exclusively in renewable service, often with dedicated feedstock logistics and product handling. While this maximizes renewable fuel output, most designs intentionally retain the ability to revert to fossil operation, though doing so may require catalyst changeout and operating adjustments. This flexibility can be strategically valuable in volatile feedstock and policy environments.

How can refinery revamps deliver fast renewable fuel market entry?

A grassroots renewable diesel or SAF facility typically requires 24 to 36 months from final investment decision to first production. Site preparation, foundation work, construction and equipment installation all need to happen. For existing refineries looking to diversify or with idle capacity, a revamp can be a good entry point for renewables as it compresses this timeline substantially. Even more extensive modifications that enable 100% renewable processing typically complete faster than new construction.

This timeline advantage translates directly to revenue capture. Markets where low-carbon fuel mandates create price premiums reward early movers. A refinery that brings renewable diesel production online 18 months ahead of a competing greenfield project captures that price differential across a longer period. The capital efficiency improves further when existing infrastructure, such as hydrogen generation, utilities, control systems, requires minimal modification.

The speediness factor also reduces exposure to regulatory uncertainty. Policy frameworks for renewable fuels continue evolving across jurisdictions. A shorter project timeline limits the window during which subsidy structures, blending mandates or carbon pricing mechanisms might change.

Staged implementation manages capital and risk

Few refineries operate with unlimited capital budgets or the ability to shoulder extended downtime. Revamp projects can come in phases that work within these constraints. An initial conversion might enable 30% to 40% renewable co-processing with fossil feeds. This first phase requires limited equipment changes – perhaps upgraded metallurgy in critical areas and modified operating parameters.

One European refinery followed exactly this path. The initial revamp allowed renewable co-processing at modest cost. When market conditions shifted and renewable diesel premiums increased, a second phase expanded renewable processing to 70% to 80% of throughput. A third phase later eliminated fossil co-processing entirely. Each stage built on prior work optimising efficiency and available equipment and skills.

This gradual approach gives refineries operational flexibility that can be significant strategically. If feedstock costs spike or policy support weakens, the unit can revert to fossil processing. When conditions improve, renewable production resumes. That optionality has tangible value in markets where used cooking oil prices can swing 40% in a quarter or where election cycles reshape subsidy programs.

This staggered model also allows for the spread of investment across a longer timeframe, enabling refineries to learn from operating experience before committing to larger investments. Early-phase learnings can reveal which feedstocks perform well, where bottlenecks emerge and how product yields respond to different catalyst loadings. These insights inform later engineering with precision that upfront studies cannot fully capture.

Technical challenges have known solutions

The most significant technical challenge in converting fossil hydroprocessing units to renewable service is hydrogen availability. Deoxygenation reactions consume five to ten times more hydrogen than conventional hydrotreating. Units operating near hydrogen balance in fossil mode are therefore frequently hydrogen-limited when processing renewable feeds. In many revamp projects, hydrogen compression or supply capacity becomes the single largest capital item and ultimately sets the maximum achievable throughput.

Reactor volume and configuration present another common constraint. Renewable feedstocks often require longer residence times to achieve full conversion and desired product properties, particularly for SAF production. This may necessitate revised catalyst loading strategies, modified internals or the addition of extra reactor capacity.

Heat management also changes materially. Deoxygenation reactions are highly exothermic, affecting furnace duty, exchanger design and temperature control strategies. Inadequate heat integration can limit throughput or compromise catalyst life.

Corrosion management deserves particular attention. Vegetable oils and animal fats contain chlorides, fluorides and other halogens that accelerate metal degradation in certain temperature and pressure regimes. Water and CO/CO2 production from oxygen removal creates additional corrosion pathways. Proper metallurgy selection and chemical injection programs control these mechanisms. Two decades of commercial operation have mapped corrosion behavior across diverse conditions and established reliable mitigation approaches – for instance, through appropriate metallurgy upgrade, chemical injection and operating discipline.

None of these challenges represents a fundamental barrier. They require systematic engineering evaluation and targeted capital investment. The critical step involves accurate characterization upfront through a detailed technical study that identifies specific bottlenecks and defines modification scope.

The study phase determines project success

Refineries that head into a revamp without thorough evaluation can face issues such as scope creep, budget overrun and delayed startups. Those that invest time in comprehensive studies at the front end, however, put themselves in a solid position to avoid rework and deliver projects on schedule. The study phase is crucial in mapping existing equipment against renewable processing requirements and identifies gaps.

This evaluation examines every piece of equipment – reactors, separators, compressors, heat exchangers, pumps. It reviews line sizes, materials of construction, instruments and control logic. The analysis considers not just whether equipment can manage renewable service but at what capacity and with what modifications. The study phase also addresses integration questions. Where does hydrogen come from and in what quantity? Can the refinery hydrogen plant scale production or does additional capacity need new infrastructure? Does the unit connect to existing tank farms or require new storage? Can the product blend into the refinery diesel pool or does it need dedicated logistics? Should there be an overall safety evaluation based on new service and process layout?

Feedstock procurement deserves equal scrutiny. Vegetable oils, used cooking oil, animal fats and future bio-crude sources all have different specifications and supply dynamics. A unit designed for pretreated, low-acidity feedstock cannot process crude pyrolysis oil without significant modification. The study needs to define feedstock specifications clearly and confirm that projected supply is actually acquirable at assumed costs.

Refineries should see the study as a strategic planning exercise rather than a box to tick off. They ideally should involve operations personnel who understand current unit performance and limitations, commercial teams who can validate feedstock supply and product offtake, and corporate development to ensure the revamp aligns with broader decarbonization commitments and capital allocation priorities.

Hydrocracking units offer particular advantages

While any hydroprocessing unit can potentially convert to renewable service, hydrocracking units bring inherent advantages. They operate at higher pressures than conventional hydrotreaters and manage elevated hydrogen supply rates. This design basis aligns well with renewable processing requirements.

Importantly, hydrocrackers also typically include fractionation sections that enable direct SAF production rather than just renewable diesel.

A US refinery converted a mild hydrocracking unit directly into combined SAF and renewable diesel production. The existing design pressure and hydrogen system capacity accommodated the transition without major modifications. The fractionation section allowed product slate flexibility that justified premium pricing. What might have required extensive modification in a conventional hydrotreater proceeded as a relatively straightforward conversion.

Planning for emerging feedstocks

Fats, oils and greases represent first-generation renewable feedstocks with established processing routes. The next wave involves more challenging molecules. Plastic pyrolysis oils, woody biomass liquids and other bio-crudes require more severe hydrotreatment and pose distinct corrosion and catalyst challenges. These materials contain higher heteroatom concentrations and more complex aromatic structures.

Refineries planning revamps today should consider future feedstock flexibility in their design basis. A unit optimized solely for pretreated vegetable oil may not accommodate plastic pyrolysis oil later without another round of modifications. Incremental upfront investment in more robust metallurgy and additional pretreatment capability preserves options as feedstock markets evolve.

This forward planning matters particularly in jurisdictions that incentivize waste-based feedstocks more heavily than used cooking oil. Refineries that lock themselves into a defined feedstock processing may end up leaving value on the table.

Moving from evaluation to execution

The refineries succeeding in renewable fuel production share common characteristics. They invest time in thorough technical and commercial studies. They engage experienced technology licensors like Topsoe early in the process. They sequence capital deployment in phases that align with market development and their own operational capabilities. They plan for feedstock diversity and product flexibility.

Most fundamentally, they recognize that their existing asset base represents an advantage rather than a liability. Converting proven equipment to new service delivers faster, cheaper and often more flexible outcomes than greenfield construction. The commercial units operating today validate this approach, while the dozens of projects currently in engineering and construction will expand that installed base substantially over the next 36 months.

The transition to renewable fuels will require both new facilities and converted existing capacity. The question facing refiners is which path (or if both paths) suits their specific circumstances and timeline. For many, the answer starts with a comprehensive evaluation of what already exists and what modifications would unlock its potential for renewable service.

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10-step refinery checklist before undertaking a renewable revamp

1. Business and strategic framing
• What is the target product slate (renewable diesel vs SAF vs both)?
• Is speed to market or long-term flexibility the primary objective?
• What is the opportunity cost of repurposing this unit from fossil service?

2. Feedstock definition and security
• Which feedstocks will be processed (UCO, animal fats, bio-crudes)?
• Are supply volumes contractually secured at assumed prices?
• What are the contaminant levels (chlorides, phosphorus, metals, acidity)?
• Is additional pretreatment required to protect the hydroprocessing unit?

3. Hydrogen system assessment
• Current hydrogen balance and margin
• Compressor capacity and limitations
• Hydrogen purity requirements
• Options for debottlenecking (recovery, new compression, SMR expansion)

4. Unit hardware and metallurgy
• Reactor volume and internals suitability
• Materials of construction in corrosion-prone areas
• Heat exchanger network and furnace capacity
• Separator and cold-end system robustness

5. Heat release and operability
• Exothermicity management at higher renewable ratios
• Temperature control strategies
• Water handling and separation capacity

6. Catalyst and cycle strategy
• Renewable-specific catalyst selection
• Loading patterns for staged revamps
• Expected cycle length and regeneration strategy

7. Integration and logistics
• Feedstock storage and handling requirements
• Product segregation and blending
• SAF logistics and airport pipeline access where relevant

8. Regulation and certification
• Sustainability certification (e.g. ISCC, RSB)
• GHG accounting methodology
• Eligibility for regional mandates and incentives

9. Phasing and execution
• Can the project be staged to manage capital and risk?
• Alignment with turnaround schedules
• Operator training and startup planning

10. Organizational readiness
• Involvement of operations, engineering and commercial teams
• Clear ownership of feedstock procurement and product offtake

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