Ebigbo, Anozie

The Kingdom of Saudi Arabia (KSA) has vast geothermal energy resources. When developed, these markedly strengthen the country's goals of achieving a carbon-neutral economy. To demonstrate the feasibility and techno-economic performance of small-scale, hydrothermal well doublet systems for direct use in KSA, we perform reservoir and wellbore flow and heat-transport simulations as well as an economic analysis. The maximum permissible flowrate is constrained to avoid thermoelastic fracturing in the near-wellbore region. Reservoir conditions of a sedimentary basin along the Red Sea coast (near Al Wajh) provide an ideal study case to which we add economic parameters considered representative for KSA. We derive a Levelized Cost of Heat (LCOH) ranging from 49 to 128 $/MWh for 50-mD hydrothermal doublet systems with an optimal well spacing of 600 m and a flowrate ranging from 110 kg/s to 50 kg/s. LCOH is strongly influenced by decreasing reservoir transmissivity. Also, a minimum injection temperature is required to avoid thermoelastic fracturing. Our economic analysis further highlights that capacity factor and well-drilling cost have the greatest impact on LCOH. Thus, this study provides a guide and workflow to conduct techno-economic investigations for decision-making, risk mitigation, optimizing geothermal-energy-extraction and economic-performance conditions of hydrothermal doublet systems.

Due to spatial scaling effects, there is a discrepancy in mineral dissolution rates measured at different spatial scales. Many reasons for this spatial scaling effect can be given. We investigate one such reason, i.e., how pore-scale spatial heterogeneity in porous media affects overall mineral dissolution rates. Using the bundle-of-tubes model as an analogy for porous media, we show that the Darcy-scale reaction order increases as the statistical similarity between the pore sizes and the effective-surface-area ratio of the porous sample decreases. The analytical results quantify mineral spatial heterogeneity using the Darcy-scale reaction order and give a mechanistic explanation to the usage of reaction order in Darcy-scale modeling. The relation is used as a constitutive relation of reactive transport at the Darcy scale. We test the constitutive relation by simulating flow-through experiments. The proposed constitutive relation is able to model the solute breakthrough curve of the simulations. Our results imply that we can infer mineral spatial heterogeneity of a porous media using measured solute concentration over time in a flow-through dissolution experiment.

CO₂-Plume Geothermal (CPG) power plants can produce heat and/or electric power. One of the most important parameters for the design of a CPG system is the CO₂ mass flowrate. Firstly, the flowrate determines the power generated. Secondly, the flowrate has a significant effect on the fluid pressure drawdown in the geologic reservoir at the production well inlet. This pressure drawdown is important because it can lead to water flow in the reservoir towards and into the borehole. Thirdly, the CO₂ flowrate directly affects the two-phase (CO₂ and water) flow regime within the production well. An annular flow regime, dominated by the flow of the CO₂ phase in the well, is favorable to increase CPG efficiency. Thus, flowrate optimizations of CPG systems need to honor all of the above processes. We investigate the effects of various operational parameters (maximum flowrate, admissible reservoir-pressure drawdown, borehole diameter) and reservoir parameters (permeability anisotropy and relative permeability curves) on the CO₂ and water flow regime in the production well and on the power generation of a CPG system. We use a numerical modeling approach that couples the reservoir processes with the well and power plant systems. Our results show that water accumulation in the CPG vertical production well can occur. However, with proper CPG system design, it is possible to prevent such water accumulation in the production well and to maximize CPG electric power output.

There is a potential for synergy effects in utilizing CO2 for both enhanced gas recovery (EGR) and geothermal energy extraction (CO2-plume geothermal, CPG) from natural gas reservoirs. In this study, we carried out reservoir simulations using TOUGH2 to evaluate the sensitivity of natural gas recovery, pressure buildup, and geothermal power generation performance of the combined CO2-EGR–CPG system to key reservoir and operational parameters. The reservoir parameters included horizontal permeability, permeability anisotropy, reservoir temperature, and pore-size-distribution index; while the operational parameters included wellbore diameter and ambient surface temperature. Using an example of a natural gas reservoir model, we also investigated the effects of different strategies of transitioning from the CO2-EGR stage to the CPG stage on the energy-recovery performance metrics and on the two-phase fluid-flow regime in the production well. The simulation results showed that overlapping the CO2-EGR and CPG stages, and having a relatively brief period of CO2 injection, but no production (which we called the CO2-plume establishment stage) achieved the best overall energy (natural gas and geothermal) recovery performance. Permeability anisotropy and reservoir temperature were the parameters that the natural gas recovery performance of the combined system was most sensitive to. The geothermal power generation performance was most sensitive to the reservoir temperature and the production wellbore diameter. The results of this study pave the way for future CPG-based geothermal power-generation optimization studies. For a CO2-EGR–CPG project, the results can be a guide in terms of the required accuracy of the reservoir parameters during exploration and data acquisition.

Flow through rock fractures is frequently represented using models that correct the cubic law to account for the effects of roughness and contact area. However, the scope of such models is often restricted to relatively smooth aperture fields under small confining stresses. This work studies the link between fracture permeability and fracture geometry under normal loads. Numerical experiments are performed to deform synthesized aperture fields of various correlation lengths and roughness values under normal stress. The results demonstrate that aperture roughness can more than triple for applied stresses up to 50 MPa – exceeding the valid range for roughness in most previously published models. Investigating the relationship between permeability and contact area indicates that the increase in flow obstructions due to the development of new contact points strongly depends on the correlation length of the unloaded aperture field. This study eliminates these dependencies by employing a parameter known as the No-Flow Fraction (NFF) to capture the effect of flow stagnation zones. With this concept, a new Cubic-law-based permeability model is proposed that significantly improves the accuracy of permeability estimations, compared to previous models. For cases, where the NFF is difficult to obtain, we introduce an empirical relationship to estimate the parameter from the aperture roughness. The new models yield permeability estimates accurate to within a factor of 2 of the simulated permeability in over three-quarters of the 3,000 deformed fractures studied. This compares with typical deviations of at least one order of magnitude for previously published permeability models.

Depleted oil fields in the Gulf of Suez (Egypt) can serve as geothermal reservoirs for power generation using a CO₂-Plume Geothermal (CPG) system, while geologically sequestering CO₂. This entails the injection of a substantial amount of CO₂ into the highly permeable brine-saturated Nubian Sandstone. Numerical models of two-phase flow processes are indispensable for predicting the CO₂-plume migration at a representative geological scale. Such models require reliable constitutive relationships, including relative permeability and capillary pressure curves. In this study, quasi-static pore-network modelling has been used to simulate the equilibrium positions of fluid–fluid interfaces, and thus determine the capillary pressure and relative permeability curves. Three-dimensional images with a voxel size of 0.65 μm3 of a Nubian Sandstone rock sample have been obtained using Synchrotron Radiation X-ray Tomographic Microscopy. From the images, topological properties of pores/throats were constructed. Using a pore-network model, we performed a sequential primary drainage, main imbibition cycle of quasi-static invasion in order to quantify (1) the CO₂ and brine relative permeability curves, (2) the effect of initial wetting-phase saturation (i.e. the saturation at the point of reversal from drainage to imbibition) on the residual-trapping potential, and (3) study the relative permeability-saturation hysteresis. The results improve our understanding of the potential magnitude of capillary trapping in Nubian Sandstone, essential for future field-scale simulations.