Life Cycle Assessment and Greenhouse Gas Abatement Costs of Hydrogen Production from Underground Coal Gasification Open Access
- Other title
GHG abatement costs
Life Cycle Assessment (LCA)
Carbon Capture and Sequestration (CCS)
Underground Coal Gasification (UCG)
Underground Coal Gasification
- Type of item
- Degree grantor
University of Alberta
- Author or creator
- Supervisor and department
Kumar, Amit (Department of Mechanical Engineering)
- Examining committee member and department
Gupta, Raj (Department of Chemical and Materials Engineering)
Lipsett, Mike (Department of Mechanical Engineering)
Department of Mechanical Engineering
- Date accepted
- Graduation date
Master of Science
- Degree level
Large amounts of hydrogen (H2) are required for the upgrading of bitumen from oil sands to produce synthetic crude oil (SCO). Currently, natural gas is used in the bitumen upgrading industry to produce H2 through steam methane reforming (SMR). This process has a significant life cycle greenhouse gas (GHG) footprint. Due to rising SCO production from the Canadian oil sands and climate change concerns, there is a growing need to explore more environmentally sustainable pathways for H2 production that have lower GHG footprint. Western Canada is endowed with considerable reserves of deep un-mineable coal that can be converted to syngas through a gasification process called underground coal gasification (UCG). The syngas can be transformed into H2 through commercially available technologies used in conventional fossil-fuel based H2 production pathways. Moreover, GHGs (mainly CO2) from the H2 plant operation can be captured using a physical solvent like Selexol and sequestered underground or used as a feedstock for enhanced oil recovery (EOR) operations.
A life cycle assessment (LCA) is a useful tool to evaluate the environmental impact of a system. This research presents a model to perform energy balances, estimate H2 conversion efficiency, and implement LCA to quantify life cycle GHG emissions in different unit operations of H2 production from UCG-based syngas with and without carbon capture and sequestration (CCS). In addition, a detailed analysis of the impact of key UCG parameters, i.e., H2O-to-O2 injection ratio, ground water influx, and steam-to-carbon ratio in syngas conversion, is completed on the results. Furthermore, seven practical H2 production scenarios, applicable to western Canada, are considered to assess the GHG abatement costs of implementing UCG vis-à-vis SMR along with the consideration of CCS.
The life cycle GHG emissions are calculated to be 0.91 and 18.0 kg-CO2-eq/kg-H2 in a small-scale H2 production (16.3 tonnes/day) from UCG-based syngas with and without CCS, respectively. The heat exchanger efficiency and the separation efficiency of the pressure swing adsorption (PSA) unit are major parameters affecting these emissions. The emissions increase marginally with a rise in the H2O-to-O2 injection ratio and the steam-to-carbon ratio in H2 production from UCG with CCS. Considering SMR technology without CCS as the base case, the GHG abatement costs of implementing the UCG-CCS technology is calculated to be in the range of C$41-109 /tonne-CO2-eq depending on the transportation distance from the UCG-H2 production plant to the CCS site. On the other hand, the GHG abatement costs for SMR-CCS-based scenarios are higher than for UCG-CCS-based scenarios; they range from C$87-158 /tonne-CO2-eq in a similar manner to UCG-CCS. However, there is no GHG abatement for implementing UCG without CCS; the life cycle GHG emissions are higher in UCG than in SMR. The sale of the CO2 captured in the H2 production plant (applicable in SMR-CCS and UCG-CCS) to an EOR operator reduces the GHG abatement costs; in fact, a prospect for revenue generation is realized in the UCG-CCS case.
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