CO2 Capture from Sulphur Recovery Unit Tail Gas by Shell Cansolv Technology

A significant driver for the climate change effect is CO2 emission from the sources where fossil fuel is consumed to generate energy. Capturing and sequestration of CO2 from these emission sources is a practical way to mitigate GHG emission impact. However the cost of CCS projects has been a major obstacle to implementing these technologies worldwide. Two main aspects which influence the cost of a CO2 capture project are the CO2 utilization pathway and the CO2 capture technology selection. CO2-Enhanced Oil Recovery (EOR) can be a very good potential pathway to increase the revenue of the CCS project. CO2-EOR also can be an attractive way of using CO2 in areas such as Middle East where the oil and gas reservoirs are mature. However one of the main constraints can be limited access to CO2 especially where no power plant is close to a potential oil reservoir. For technology selection, the choice is typically between Pre- and Post-Combustion. Pre-combustion CO2 capture technologies have been deployed in oil refineries & gas processing plants for decades, but the main source for CO2 emissions in these facilities is often off-gas (also known as acid gas) which is usually sent to the flare system or incinerator. These off-gases are at low pressure, so a compression system is required to pressurize the gas before sending it to the Pre-combustion CO2 capture unit. On the other hand, Post-combustion CO2 capture technology can often require an additional desulfurization step to remove SO2 which can potentially result to higher operational and capital cost as well as waste management and complexity of operation. This paper will discuss the deployment of Shell Cansolv technology to capture CO2 from off-gas downstream of the Sulfur Recovery Unit (SRU) in a single train, potentially as a new CCS application in the oil and gas sectors. The off-gas from Tail Gas Treatment Unit (TGTU) downstream of the SRU will usually contain a higher amount of CO2 compared to coal and gas power plants. The absorption affinity of Shell Cansolv solvent at low pressure off-gas compared to other pre-combustion technologies allows the elimination of the primary compression system located upstream of the CO2 capture unit. Since there is H2S slippage from the TGTU absorber overhead, the amine should be characterized in terms of absorption affinity and stability in the reduced environment. The impact of H2S on amine performance in terms of degradation has been investigated in comparison to a post-combustion application where H2S is incinerated and converted to SOx. SOx contaminates amine to form Heat Stable Salt (HSS), so it needs to be removed prior to the post-combustion CO2 capture unit in a separate FGD unit (Flue Gas Desulfurization). Shell Cansolv DC amine in pre-combustion lineup absorbs both H2S and CO2 in a single absorber so incinerator and FGD unit is not required compared to post-combustion applications. Shell Cansolv DC amine has been tested to remove up to 99% CO2 which is higher than the 90% typical capture rate for most post-combustion applications. The other advantage of this application is the ability to operate at high temperature (∼60 C). This is often a key design parameter especially in the Middle East where most applications are considered hot climate applications. All design parameters of the CO2 capture unit such as liquid per gas ratio (L/G), stripping factor at the regenerator side and absorber packing height have been evaluated and optimized to reduce both capital and operational costs of the project. Eventually, in a case study, an economic comparison was conducted and the result indicated potentially more than 40% reduction in the cost of a CO2 capture unit as well as same magnitude increase in Net Present Value (NPV) compared to pre-combustion technology.

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