of their emissions come from their customers’ use of the energy products they sell. So, drives to achieve net-zero emissions will likely also require the introduction of low-carbon energy products such as biofuels. Incremental government mandates may provide further stimulus during this period. Consequently, to reduce the carbon intensity of liquid fuel products, one of the most important solutions may be a phased investment programme with an initial period of co-processing up to 20% renewable feedstock in an existing hydrotreating unit for little or no capital expenditure. As biofuel mandates become more stringent in the future, a dedicated HVO unit for processing 100% renewable feeds could follow. Such a strategy would be highly capital efficient, but there are challenges. For example, co-processing renewable feed can affect unit operation in several ways. Hydrogen consumption and heat release will increase, for example, and there are the risks of increased corrosion and fouling. Nevertheless, although it is vital to identify all the risks for a specific unit, the mitigation measures are well established. In addition, the type of dedicated HVO unit a company invests in is crucial. Many biofuel regulations around the world are likely to mandate the use of more difficult feeds in the
future, so refiners must plan carefully to avoid regret investment. SAF is quickly becoming the preferred product from HVO units, and high SAF yield can be facilitated by utilising a two-stage HVO unit and state-of-the-art catalysts and reactor internals, either in new units or by revamping existing units. Another technology that could play a major role during this period is gasification, as it enables unwanted streams such as steam cracker residues to be converted into synthesis gas (syngas), a high-value product that can be used for producing chemicals, hydrogen, and power. The third decarbonisation pathway requires carbon capture, utilisation and storage, which the International Energy Agency (IEA) says is a key technology for cost-effectively reducing carbon dioxide (CO₂) emissions from large industrial facilities. According to the IEA, there are currently 21 large-scale carbon capture, utilisation and storage facilities worldwide. One of these is using Shell’s Cansolv * CO₂ Capture System to capture about 1 MT/y of CO₂ from the flue gas. Shell Catalysts & Technologies is currently involved in the front-end engineering and design (FEED) or pre-FEED stage of many more.
Engineering challenges of CO₂ capture at scale
The oil and gas industry has been capturing CO₂ for decades, for example, in natural gas treating. However, for large-scale carbon capture and storage projects to be successful, it had to be done on post-combustion gases containing an abundance of oxygen. It also had to be made cost-effective, as Laurent Thomas of Shell Catalysts & Technologies explains. “The presence of oxygen would cause traditional amine solvents to degrade quickly, but the Cansolv DC103 absorbent that we use today, which is the result of a sustained, multi- year research and development programme, has a much higher oxidation resistance, and we continue to make improvements through further improving the formula.
“The challenge now is to make post- combustion capture cost-effective. Low- pressure gases in large-scale projects mean huge gas volumes and, therefore, very large equipment. Thus, although the technology is now commercially deployed, we continue to look for improvement opportunities. “For example, we’re working closely with our alliance partner, Technip Energies, to drive down the cost for customers and make carbon capture more viable for smaller emitters. That has led to rapid improvements in the last 18 months, enabling the technology to be more viable for a wider range of emitters across multiple industries.”
Powered by FlippingBook