Carbon-Dioxide-Based Engineered Geothermal Systems (2011)

Engineered Geothermal Systems (EGS) represent a substantial opportunity to expand the potential for geothermal power worldwide. Conventional geothermal systems use water as a heat extraction fluid, and typically as a working fluid. EGS represent an opportunity to use different heat extraction fluids, of which CO2 is one possibility. In-reservoir performance of CO2 as a geothermal heat extraction fluid is well understood, and CO2-based EGS are predicted to benefit from ease of in-reservoir flow due to the transport properties of CO2. However, there is no understanding of the performance of an integrated CO2-based EGS power plant, and the economic viability of the concept is unknown. This thesis builds on previous works to conduct whole-plant thermodynamic modelling to better understand the technical and economic feasibility of CO2-based EGS. This research includes: process modelling of the entire system; examination of the characteristic behaviour of components of the system; preliminary economic assessment and optimisation of the power plant design and operating parameters; analysis of the potential for condensation of H2O-rich fluids in surface equipment and associated corrosion risks; an evaluation of displacement of initial reservoir fluids; and a qualitative assessment of site selection considerations. This research reveals significant differences in the behaviour of CO2¬ as a geothermal heat extraction fluid compared to H2O. In contrast to water-based geothermal systems, CO2 subsurface flow is predominantly influenced by wellbore flow characteristics: frictional pressure drop in the wellbores is likely to outweigh in-reservoir pressure drop. The increased wellbore friction is due to the lower density of CO2, and the larger mass flow of CO2 necessitated by its lower heat capacity. CO2-based EGS performance is also shown to be much more strongly linked to cooling temperature than water. This is because cooling temperature alters CO2 injection well fluid density and therefore the static pressure change in the injection well. The effect is amplified by including a compressor in the surface plant design, due to the compression work also depending on cooling temperature, and higher compressor outlet pressures further increasing injection well densities. Lower site cooling temperature is shown to be more important than higher geothermal reservoir temperature by a factor of approximately three (on a degree basis). This research also reveals that it is preferable to include a compressor in the surface plant design for both technical and economic reasons. The role of wellbore static pressure change is demonstrated to have substantial effects on the economic performance of different potential geothermal resources: in contrast to traditional water-based systems, CO2-based geothermal performs better with increasing resource depth until a reservoir depth of 2000 to 3000 m is reached. This research also examines the role of mutual miscibility of CO2 and H2O, which is expected to alter operation during displacement by CO2 of water initially in the reservoir. Condensation of a H2O-rich phase from a CO2-rich fluid flow presents a risk to surface equipment, particularly the turbine where it may cause corrosion and erosion. This research demonstrates that condensation is likely in the turbine unless geothermal CO2 is produced at (or dried to) concentrations higher than 94 mol% CO2. A method for estimating the time required to sufficiently dry a geothermal reservoir is presented. For a water-saturated reservoir of typical EGS characteristics, drying times are estimated to be of the order of years. That calculation method also estimates of the quantity of CO2 likely to be retained underground in an EGS, from both storage in porous volume space and fluid losses due to outflow and geochemical reaction. A single doublet used for CO2-based EGS is estimated to retain in the range of 5 to 20 million tonnes of CO2 over a 25 year lifetime. The overall conclusions of this body of research are that CO2-based EGS is technically feasible in that a conception of power generation after dry-out has been presented; it is economically feasible if a source of CO2 is available in that capital costs may be on the order of 6000 USD per kW of capacity; and it is particularly attractive if there is a payment associated with retention of CO2 in the geothermal reservoir, as judged by the relationship between cost of CO2 and levelised cost of electricity. It is best suited to reservoirs with low water-content or suffering high injected fluid loss; which are preferably located where low surface cooling temperatures can be achieved, and at depths of the order of 1500 to 4000 m.