Techno-Economic Study of CO₂ Capture from Natural Gas Based Hydrogen Plants<br><br>

As reserves of conventional crude oil are depleted, there is a growing need to develop unconventional oils such as heavy oil and bitumen from oil sands. In terms of recoverable oil, Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H2) than the conventional crude oils. The current H2 demand for oil sands operations is met mostly by steam reforming of natural gas. With the future expansion of oil sands operations, the demand of H2 for oil sand operations is likely to quadruple in the next decade. As natural gas reforming involves significant carbon dioxide (CO2) emissions, this sector is likely to be one of the largest emitters of CO2 in Canada. In the current H2 plants, CO2 emissions originate from two sources, the combustion flue gases from the steam reformer furnace and the off-gas from the process (steam reforming and water-gas shift) reactions. The objective of this study is to develop a process that captures CO2 at minimum energy penalty in typical H2 plants. The approach is to look at the best operating conditions when considering the H2 and steam production, CO2 production and external fuel requirements. The simulation in this study incorporates the kinetics of the steam methane reforming (SMR) and the water gas shift (WGS) reactions. It also includes the integration of CO2 capture technologies to typical H2 plants using pressure swing adsorption (PSA) to purify the H2 product. These typical H2 plants are the world standard of producing H2 and are then considered as the base case for this study. The base case is modified to account for the implementation of CO2 capture technologies. Two capture schemes are tested in this study. The first process scheme is the integration of a monoethanolamine (MEA) CO2 scrubbing process. The other scheme is the introduction of a cardo polyimide hollow fibre membrane capture process. Both schemes are designed to capture 80% of the CO2 from the H2 process at a purity of 98%. The simulation results show that the H2 plant with the integration of CO2 capture has to be operated at the lowest steam to carbon (S/C) ratio, highest inlet temperature of the SMR and lowest inlet temperatures for the WGS converters to attain lowest energy penalty. H2 plant with membrane separation technology requires higher electricity requirement. However, it produces better quality of steam than the H2 plant with MEA-CO2 capture process which is used to supply the electricity requirement of the process. Fuel (highvale coal) is burned to supply the additional electricity requirement. The membrane based H2 plant requires higher additional electricity requirement for most of the operating conditions tested. However, it requires comparable energy penalty than the H2 plant with MEA-CO2 capture process when operated at the lowest energy operating conditions at 80% CO2 recovery. This thesis also investigates the sensitivity of the energy penalty as function of the percent CO2 recovery. The break-even point is determined at a certain amount of CO2 recovery where the amount of energy produced is equal to the amount of energy required. This point, where no additional energy is required, is approximately 73% CO2 recovery for the MEA based capture plant and 57% CO2 recovery for the membrane based capture plant. The amount of CO2 emissions at various CO2 recoveries using the best operating conditions is also presented. The results show that MEA plant has comparable CO2 emissions to that of the membrane plant at 80% CO2 recovery. MEA plant is more attractive than membrane plant at lower CO2 recoveries