Energy efficiency improvements are regarded by many as a cost-effective mitigation strategy (Szklo and Schaeffer, 2007; Morrow et al., 2015; Comodi et al., 2016; Malinauskaite et al., 2019), although they may only allow a modest reduction in emissions of 5–10% (Talaei et al., 2020; Lei et al., 2021). It has also been argued that a higher energy efficiency afforded by technology development could lead to an increase in refining throughput across the world (Lutz et al., 2021), a phenomenon known as rebound effect and one that would partially negate the benefits. Clearly, energy efficiency improvements cannot be the sole driver for decarbonization of the refining sector.

The oil and gas sector was an early adopter of CCS technology since the 1970s for enhanced oil recovery (EOR), which has provided a foundation of experience for deployment in other CO₂ mitigation applications. A large body of research thereof has examined the use of CCS technology for mitigating emissions in refineries (Simmonds et al., 2003; van Straelen et al., 2010; Kuramochi et al., 2012; Johansson et al., 2013). The consensus is that CO₂ capture from larger combined emission stacks is feasible (van Straelen et al., 2010). A recent analysis by the International Energy Agency Greenhouse Gas R&D Programme (IEAGHG, 2017) places the cost of CO₂ avoidance using post-combustion CCS in refineries at US$166–185 per ton of CO₂, with an overall direct emission avoidance share of 17–48%. These projections consider CO₂ capture from larger emission sources, including the power plant stacks, fluid catalytic cracker, crude atmospheric and vacuum distillation units, and steam methane reformer. They identify the utilities plant fuelled by natural gas as the main contributor to the overall cost of CO₂ avoidance (47%), followed by the CO₂ capture and compression system (38%), and the interconnectors and retrofits (15%). By contrast, other emissions from boilers, heaters, or furnaces scattered across a refining site are more costly to abate due to their lower CO₂ concentrations and flow rates, and the possible presence of impurities (van Straelen et al., 2010; Element Energy et al., 2014). However, the economics of CO₂ capture from these heterogeneous point sources remains poorly understood and requires site-specific appraisals for a more accurate assessment (Element Energy et al., 2014).

Since around 70% of a refinery’s emissions are the result of fuel combustion (IEAGHG, 2017), fuel switching constitutes another key mitigation strategy. The corresponding CO₂ abatement cost varies widely with the replacement fuel, with estimates in the UK in the order of US$30 t C O 2 − 1 for biomass, US$110 t C O 2 − 1 for hydrogen, and US$430 t C O 2 − 1 for electricity (Element Energy and Jacobs, 2018). Although attractive in terms of CO₂ abatement and cost, fuel switching to biomass could nevertheless generate a large environmental burden, in addition to being potentially disruptive to the biomass market. Furthermore, direct-fired heaters and boilers using solid biomass are considered impractical in oil refineries because of logistical and safety constraints (Progressive Energy, 2020). Conversely, gaseous fuels such as biomethane and hydrogen could serve as drop-in fuels without the need for significant restructuring of refinery operations, especially for the combined heat and power (CHP) plant. But there are concerns related to the nature of heat transfer and the level of NO_x emissions with hydrogen-fired boilers; and even if their operation is expected to be as reliable as their natural gas counterparts, such boilers have not yet been demonstrated in an industrial environment (Progressive Energy, 2020). Similarly, electric heating could become a suitable alternative, subject to a significant reduction in production cost and demonstration of operational reliability.

The net-zero paradigm entails balancing any residual CO₂ emissions with an equivalent amount of permanent CO₂ removal from the atmosphere. Because of large uncertainties in the cost of technologies such as direct air capture (DAC) (Dods et al., 2021), a recent focus in CCS development has been to achieve CO₂ capture rates well above 90% (Feron et al., 2019; Gao et al., 2019; Hirata et al., 2020; Brandl et al., 2021; Danaci et al., 2021). But regardless of the ability to achieve high capture rates, upwards of 30% of a refinery’s emissions may remain unaddressed by post-combustion CCS alone. The treatment of flared gases using post-combustion CCS is furthermore considered impractical, mainly because of the uncertainty in unplanned flaring (equipment failures, blow downs, or emergency shutdowns) (Emam, 2015; Calel and Mahdavi, 2020). This is where a multipronged approach becomes necessary. In particular, a system combining post-combustion CCS to tackle the largest emission point sources with fuel switching for smaller distributed emission sources may curtail refining emissions cost-effectively (Element Energy and Jacobs, 2018). Fuel switching is also relevant when the CCS installation and auxiliary on-site equipment are constrained by space. Further analysis is needed, however, to better understand the trade-offs between both post-combustion CCS and fuel switching, considering both economic and environmental impacts as well as technology readiness.

The CO₂ avoidance is defined as the quantity of CO₂ emissions avoided using abatement measures relative to a reference plant which uses a given mix of fuels and technologies. It is clear that both scope 1 (direct emissions from owned or controlled assets) and scope 2 emissions (indirect emissions from utilities, electricity, heating and cooling) need to be an integral part of any CO₂ avoidance assessment in order for strategic decisions to be fully aligned with net-zero ambitions. An increase in the CO₂ capture rate of the CCS plant generally goes in hand with an increase in overall (absolute) energy consumption and thus indirect environmental impacts (Feron et al., 2019). Similarly, the overall benefit of fuel switching to hydrogen, electricity, or biomass is largely dependent on indirect emissions associated with upstream processes used for their production. An archetypal example would be switching to hydrogen fuel produced from high-carbon electricity, which may not reduce the overall carbon footprint of a refinery, albeit reducing its direct CO₂ emissions.

Here, we discuss the merits and caveats of post-combustion CCS in a highly optimistic case where all point-source emissions of the model refinery from Figure 1B would be captured. The case study assumes that the CCS unit would be powered by a dedicated CHP plant, any CO₂ emissions of which would also be directed to the CCS unit—a realistic scenario insofar as installing CCS in existing refineries would entail retrofits, yet excess utilities (steam and electricity) might not be available on-site in most refineries. Further details about the case study assumptions and calculation procedure are reported in Section 3 of the ESI for completeness.

The first scenario in Figure 2A considers a natural gas-fired CHP plant. Notice how achieving 90% CO₂ avoidance requires a capture rate in the CCS unit greater than 96% when natural gas from Great Britain fuels the CHP—a discrepancy attributed to upstream emissions from the natural gas supply chain as aforementioned. Conversely, a 99% capture rate in the CCS unit delivers 86% and 79% CO₂ avoidance when the CHP fuel corresponds to natural gas and LNG, respectively, both at the global average emissions intensity. To put it in perspective, for our model refinery where post-combustion CCS covers 72% of the direct CO₂ emissions (Figure 1B and Supplementary Table S1), the CO₂ avoidance with a CHP plant fired by natural-gas at the global average emissions intensity and a 99% CO₂ capture rate is no more than 62%. This reinforces the need for complementary measures such as fuel switching and negative emissions technologies, in addition to reducing scope 2 emissions. Another important consideration is that the post-combustion CCS unit consumes around 0.13 tonnes of natural gas per tonne of CO₂ at capture rates of 90% and above, thus significantly increasing the primary energy requirements of a refinery.

For comparison, the second scenario in Figure 2B considers a hydrogen-fired CHP plant. Observe how scope 2 emissions (y-axis) attributed to blue (methane-derived with CCS) hydrogen increase compared to those of natural gas. Under the assumption of a 90% CO₂ capture rate in the blue hydrogen production process, they are predicted to triple in the case of natural gas from Great Britain and almost double in the case of LNG at the global average emissions intensity. This supports the conclusion that burning natural gas in the CHP plant and capturing the resulting CO₂ emissions would be more effective than switching to hydrogen fuel, unless this substitution fuel has a low indirect emission intensity as for instance with green (electrolytically-derived using renewable power) hydrogen. If blue hydrogen (generated from a global average supply of natural gas with a 90% CO₂ capture rate) was used to address the remaining 28% of the direct emissions from the model refinery, the overall CO₂ avoidance would increase from 62% to 75%; this would further increase to 87% if green hydrogen was used instead. To achieve net-zero, around 13–25% of the refinery’s direct emissions would still need to be offset through CO₂ removal technologies.

The broader implications of producing green hydrogen to fuel the CHP plant of a refinery should also be considered carefully. In particular, guaranteeing a continuous supply of green hydrogen would require hydrogen storage, increasing cost. Moreover, green hydrogen suffers higher conversion losses compared to renewable electricity, and switching to renewable electricity could thus allow for greater CO₂ avoidance rates. This cursory analysis points to the need for a detailed techno-economic analysis and life-cycle assessment between renewable electricity, green hydrogen, and blue hydrogen as future energy vectors in refineries.

The previous discussion has underlined the need for a combination of emission mitigation strategies to effectively decarbonize existing oil refineries, taking the best of post-combustion CCS and fuel switching and complementing with CO₂ removal technologies. Newer refinery installations could benefit further from the use of low-carbon power sources, such as solar or wind electricity, as the power plant typically is the single largest point-source emitter. Concentrated solar power (CSP) systems can already operate at steam temperatures between 60 and 250°C and have the ability to reach temperatures beyond 400°C (González-Garay et al., 2021). Not only could such CSP systems curb CO₂ emissions from the utility system, but they might also be directly coupled with the CCS unit in the future (Wang et al., 2017). Of course, a key challenge in practice is integrating such technologies efficiently within a refinery.

Incorporating CCS in any application causes some degree of environmental burden shifting. The additional energy and infrastructure requirements, along with the consumption of additional resources (e.g., MEA solvent), increase water consumption and smog formation among other environmental impacts (Giordano et al., 2018). These environmental trade-offs are driven primarily by scope 1 and 2 emissions from the extra fuel needed for capturing the CO₂ (Young et al., 2019). However, the relevance of burden shifting is unclear, as potential risks associated with increased impacts on indicators other than global warming potential are poorly understood, except perhaps for water scarcity due to its importance in arid regions (Zhu et al., 2021). More research is needed to understand the wider environmental implications of post-combustion CCS, fuel switching, and CO₂ removal. In particular, the environmental burden shifting caused by decarbonizing refineries could be analyzed through the framework of planetary boundaries (Rockström et al., 2009; Ryberg et al., 2018a,b), which has already been used to compare a range of CCU applications (González-Garay et al., 2019; Galán-Martín et al., 2021). This would allow for the nexus between carbon emissions, water use, and primary energy consumption to be considered as a whole (Wang et al., 2021), even opening up opportunities for expanding the scope to material flows (Elshkaki, 2019) and resource availability (Chamas et al., 2021).

A major focus herein has been on addressing scope 1 and 2 emissions from refineries, in the manner of a well-to-tank analysis. Yet these activities may only account for 10–20% of emissions from oil products, while the remaining 80–90% is associated with fuel use (Total, 2020; Bieker, 2021)—these so-called scope 3 emissions cover fuel combustion by consumers (tank-to-wheel) as well as flaring along with other activities in a company’s value chain. To comply with the net-zero vision, scope 3 emissions will eventually need to be eliminated or offset alongside scope 1 and 2 emissions.

Besides DAC, engineered CO₂ removal technologies include the use of biogenic carbon feedstock with CCS for bioenergy production, also known as BECCS (Fajardy and Mac Dowell, 2017). Higher penetration of CO₂ capture and utilization technology combined with the development of green hydrogen could also enable synthetic fuels, which have the potential to deliver near-zero emissions over the entire well-to-wheel life-cycle, so long as their production processes are carbon-neutral. Although the economics of synthetic fuels is currently hindered by high energy consumption, production costs are expected to fall as the technology scales up (E4tech, 2021; Gudde et al., 2019; Daggash et al., 2018). Furthermore, various chemical feedstocks and products could be displaced through plastic waste recycling, thereby lowering scope 3 emissions and enabling a circular carbon economy. For example, the pyrolysis of plastic waste could displace virgin naptha and lower the total impact by approximately 400 kg_CO2,eq for each tonne of plastic (Jeswani et al., 2021).

More generally, CO₂ utilization may be financially viable in a supportive market environment but commercially available utilization technologies are still lacking the scale and permanence of CO₂ removal required to be relevant for long-term climate stabilization (Mac Dowell et al., 2017). CO₂ utilization has a role in the portfolio of CO₂ mitigation approaches in the near-term, albeit likely a small one, as it is highly dependent on supportive regional policies (such as the 45Q tax credits for enhanced oil recovery in the United States) and coordinated market development for a diverse set of CO₂-based products. This is in contrast with CCS technologies, which offer the opportunity to use existing technologies and infrastructure without a significant reshaping of the industry, whilst permanently removing CO₂ from the atmosphere (Gabrielli et al., 2020).

Finally, the sustainability of CO₂ mitigation strategies in refineries ought to consider the social dimension alongside economic and environmental trade-offs. This could follow a triple helix approach, as recently advocated for CO₂ utilization assessment (McCord et al., 2021). Furthermore, the costs associated with the transition to net-zero should be managed in a socially equitable manner (GCCSI, 2020). The development of regulatory and policy frameworks that facilitate such a sustainable transition to net-zero for the refining sector will be a crucial milestone in this endeavour.