(505a) Simulation Model for the Optimization of An Integrated Post-Combustion CO2 Capture, Transport and Sequestration System

Carbon capture and storage is expected to play a significant part in the reduction of green house emissions. Carbon dioxide is captured from a point source, like a power plant, compressed and transported via pipelines and finally injected in natural formations. Injectivity is an indication of the formations resistance to CO2 injection. An unexpected reduction in the rate of CO2 injection in to natural formations has been observed. This is currently attributed to the reservoir formation, specifically its properties and interaction with injected carbon. This work aims to simulate the capture, transport and sequestration system of CO2 to help understand the effects that processes before injection have on the reduced injectivity. A 500MW coal power plant, in Fort Saskatchewan Alberta, coupled with a 90% removal post-combustion amine (Methanolamine (MEA)) capture system is considered as a base case. A 240 km flat transport route from the emission source to the storage site is also considered. Several natural formations were considered for robustness of the simulation and the pressure build up in the formation was estimated using a model developed by Mathias et al (2005). The simulations were conducted using VMGsim® process simulator. The initial model reveals that a 500MW power plant produces 813000 Kg/hr CO2 and requires 10900m3/hr of 30% MEA amine solution in a 24 stage absorber-stripper capture unit to remove 90% of the CO2 from the flue gas. Subsequently a 9 stage compression unit would be used to condition the pure CO2 stream for transport at 11 MPa. A 2407 m deep natural reservoir, with 0.1 porosity and injection rate of 1.66 X 104 t/day, would potentially be able to sustain CO2 injection at that rate for 45 years within the regulatory allowable reservoir pressure (90% of rock fracturing pressure).