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In order to assess the thermo-hydraulic modelling capabilities of various geothermal simulators, a comparative test suite was created, consisting of a set of cases designed with conditions relevant to the low-enthalpy range of geothermal operations within the European HEATSTORE research project. In an effort to increase confidence in the usage of each simulator, the suite was used as a benchmark by a set of 10 simulators of diverse origin, formulation, and licensing characteristics: COMSOL, MARTHE, ComPASS, Nexus-CSMP++, MOOSE, SEAWATv4, CODE_BRIGHT, Tough3, PFLOTRAN, and Eclipse 100. The synthetic test cases (TCs) consist of a transient pressure test verification (TC1), a well-test comparison (TC2), a thermal transport experiment validation (TC3), and a convection onset comparison (TC4), chosen to represent well-defined subsets of the coupled physical processes acting in subsurface geothermal operations. The results from the four test cases were compared among the participants, to known analytical solutions, and to experimental measurements where applicable, to establish them as reference expectations for future studies. A basic description, problem specification, and corresponding results are presented and discussed. Most participating simulators were able to perform most tests reliably at a level of accuracy that is considered sufficient for application to modelling tasks in real geothermal projects. Significant relative deviations from the reference solutions occurred where strong, sudden (e.g. initial) gradients affected the accuracy of the numerical discretization, but also due to sub-optimal model setup caused by simulator limitations (e.g. providing an equation of state for water properties)., Geothermics, 96, ISSN:0375-6505

The increased interest in subsurface development (e.g., unconventional hydrocarbon, deep geothermal, waste disposal) and the associated (triggered or induced) seismicity calls for a better understanding of the hydro-seismo-mechanical coupling in fractured rock masses. Being able to bridge the knowledge gap between laboratory and reservoir scales, controllable meso-scale in situ experiments are deemed indispensable. In an effort to access and instrument rock masses of hectometer size, the Bedretto Underground Laboratory for Geosciences and Geoenergies (‘Bedretto Lab’) was established in 2018 in the existing Bedretto Tunnel (Ticino, Switzerland), with an average overburden of 1000 m. In this paper, we introduce the Bedretto Lab, its general setting and current status. Combined geological, geomechanical and geophysical methods were employed in a hectometer-scale rock mass explored by several boreholes to characterize the in situ conditions and internal structures of the rock volume. The rock volume features three distinct units, with the middle fault zone sandwiched by two relatively intact units. The middle fault zone unit appears to be a representative feature of the site, as similar structures repeat every several hundreds of meters along the tunnel. The lithological variations across the characterization boreholes manifest the complexity and heterogeneity of the rock volume, and are accompanied by compartmentalized hydrostructures and significant stress rotations. With this complexity, the characterized rock volume is considered characteristic of the heterogeneity that is typically encountered in subsurface exploration and development. The Bedretto Lab can adequately serve as a test-bed that allows for in-depth study of the hydro-seismo-mechanical response of fractured crystalline rock masses., Solid Earth Discussions, ISSN:1869-9537

CO2 Plume Geothermal (CPG) energy systems circulate geologically stored CO2 to extract geothermal heat from naturally permeable sedimentary basins. CPG systems can generate more electricity than brine systems in geologic reservoirs with moderate temperature and permeability. Here, we numerically simulate the temperature depletion of a sedimentary basin and find the corresponding CPG electricity generation variation over time. We find that for a given reservoir depth, temperature, thickness, permeability, and well configuration, an optimal well spacing provides the largest average electric generation over the reservoir lifetime. If wells are spaced closer than optimal, higher peak electricity is generated, but the reservoir heat depletes more quickly. If wells are spaced greater than optimal, reservoirs maintain heat longer but have higher resistance to flow and thus lower peak electricity is generated. Additionally, spacing the wells 10% greater than optimal affects electricity generation less than spacing wells 10% closer than optimal. Our simulations also show that for a 300 m thick reservoir, a 707 m well spacing provides consistent electricity over 50 years, whereas a 300 m well spacing yields large heat and electricity reductions over time. Finally, increasing injection or production well pipe diameters does not necessarily increase average electric generation., Renewable Energy, 172, ISSN:0960-1481, ISSN:1879-0682

How to operate a geothermal system in the most efficient and safe manner? This is the most important and urgent question after a geothermal resource has been identified. The recently funded Innovative Training Network ‘EASYGO‘ will answer that question from different perspectives and give high-level training for early stage researchers (ESR; here PhD candidates) in geothermal operations.Tackling the challenges of sustainable geothermal operations requires an interdisciplinary and intersectoral approach. To achieve the main objective, researchers will work on the whole chain of geothermal operations, from production to power-plant engineering to injection. They will develop novel monitoring concepts, perform real-time simulations, develop system components, assess novel concepts for operations and test operational parameters at the field scale. The major strength and originality of the programme is that it is developed around large-scale infrastructure. Researchers will have access to the infrastructure in all countries for testing equipment and doing real-time measurements.EASYGO graduates will be a new generation of multidisciplinary experts in geothermal operations, trained to achieve standardised efficient and safe operations of geothermal systems to enable the ambitious international expansion plans. The mobility plan of EASYGO envisages each ESR to have at least one academic secondment and one industrial secondment.EASYGO consists of an intersectoral team of experts from academic and non-academic institutions. All academic participants are members of the IDEA League, a strategic alliance of leading European universities of technology. The members of the IDEA League with a strong research profile in geothermal energy, TU Delft (The Netherlands), RWTH Aachen (Germany), ETH Zurich (Switzerland) and Politecnico di Milano (Italy), constitute the academic consortium of EASYGO. Additionally, ten industry partners from all countries drive the research from an applied point of view. Our ambition is to contribute to making Europe a world leader in geothermal science, operational technology and education, thereby accelerating the energy transition.

Sedimentary basins are ubiquitous, naturally porous and permeable, and the geothermal heat in these basins can be extracted with geologic water or CO2 and used to generate electricity. Despite this, the broad potential that these formations may have for electricity generation is unknown. Here we investigate this potential, which required the creation of the generalizable GEOthermal techno-economic simulator (genGEO). genGEO is built with only publicly available data and uses five standalone, but integrated, models that directly simulate all components of geothermal power plants to estimate electricity generation and cost. As a result of this structure, genGEO, or a portion of it, can be applied or extended to study any geothermal power technology. In contrast, the current techno-economic tools for geothermal power plants rely on characterizations of unpublished ASPEN results and are thus not generalizable enough to be applied to sedimentary basin geothermal power plants which use subsurface CO2. In this study, we present genGEO as open-source software, validate it with industry data, and compare its estimates to other geothermal techno-economic tools. We then apply genGEO to sedimentary basin geothermal resources and find that using CO2 as a subsurface heat extraction fluid compared to water decreases the cost of geothermal electricity across most geologic conditions that are representative of sedimentary basins. Using genGEO results and p50 geologic data, we produce supply curves for sedimentary basin geothermal power plants in the U.S., which suggests that there is present-day potential to profitably increase the capacity of geothermal power by ~10% using water as the subsurface heat extraction fluid. More capacity is available at lower cost when CO2 is used as the subsurface fluid, but realizing this capacity requires geologically storing between ~2 and ~7 MtCO2/MWe. But developing sedimentary basin resources in the short-term using subsurface water may not eliminate options for CO₂-based power plants in the long-term because the least-cost order of sedimentary basins is not the same for both CO2 and water. With sufficient geologic CO2 storage, developing sedimentary basins using CO2- and water-based power plants may be able to proceed in parallel.

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., Energies, 14 (19), ISSN:1996-1073

Subsurface engineering applications, such as the development of enhanced geothermal systems and unconventional oil and gas reservoirs, and the geologic disposal of CO 2 and waste water, involve flu...

Hybrid geothermal power plants operate by using geothermal fluid to preheat the working fluid of a higher-temperature power cycle for electricity generation. This has been shown to yield higher electricity generation than the combination of a stand-alone geothermal power plant and the higher-temperature power cycle. Here, we test both a direct CO2 hybrid geothermal system and an indirect brine hybrid geothermal system. The direct CO2 hybrid geothermal system is a CO2 Plume Geothermal (CPG) system, which uses CO2 as the subsurface working fluid, but with auxiliary heat addition to the geologically produced CO2 at the surface. The indirect brine geothermal system uses the hot geologically produced brine to preheat the secondary working fluid (CO2) within a secondary power cycle. We find that the direct CPG-hybrid system and the indirect brine-hybrid system both can generate 20 % more electric power than the summed power of individual geothermal and auxiliary systems in some cases. Each hybrid system has an optimum turbine inlet temperature which maximizes the electric power generated, and is typically between 100 °C and 200 °C in the systems examined. The optimum turbine inlet temperature tends to occur where the geothermal heat contribution is between 50 % and 70 % of the total heat addition to the hybrid system. Lastly, the CO2 direct system has lower wellhead temperatures than indirect brine and therefore can utilize lower temperature resources., Journal of CO2 Utilization, 42, ISSN:2212-9820, ISSN:2212-9839

Depleted oil fields in the Gulf of Suez (Egypt) can serve as geothermal reservoirs for power generation using a CO-Plume Geothermal (CPG) system, while geologically sequestering CO. This entails the injection of a substantial amount of CO into the highly permeable brine-saturated Nubian Sandstone. Numerical models of two-phase flow processes are indispensable for predicting the CO-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 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 CO 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., International Journal of Greenhouse Gas Control, 103, ISSN:1750-5836, ISSN:1878-0148

The creation of deep reservoirs for geothermal energy or oil and gas extraction is impeded by insufficient stimulation. Direction and extension of the created fractures are complex to control and, therefore, large stimulated and interconnected fracture networks are difficult to create. This lack of control and efficiency poses an inherent risk of uneconomic reservoirs, due to insufficient heat-sweep surfaces or hydraulic shortcuts. Therefore, we present a technique, which locally increases the cross section of a borehole by applying a thermal spallation process to the sidewalls of the borehole. By controlled and local enlargement of the well bore diameter, initial fracture sources are created, potentially reducing the injection pressure during hydraulic stimulation, initiating fracture growth, optimizing fracture propagation and increasing the number of accessible preexisting fractures. Consequently, local thermal borehole enlargement reduces project failure risks by providing better control on subsequent stimulation processes. In order to demonstrate the applicability of the suggested technique, we conducted a shallow field test in an underground rock laboratory. Two types of borehole enlargements were created in a 14.5 m deep borehole, indicating the feasibility of the technology to improve the productivity of geothermal, oil and gas reservoirs.

We investigate how subsurface fluids of different compositions affect the electricity generation of geothermal power plants. First, we outline a numerical model capable of accounting for the thermophysical properties of geothermal fluids of arbitrary composition within simulations of geothermal power production. The behavior of brines with varying compositions from geothermal sites around the globe are then examined using the model. The effect of each brine on an idealized binary geothermal power plant is simulated, and their performances compared by calculating the amount of heat exchanged from the fluid to the plant's secondary cycle. Our simulations combine (1) a newly developed Non-linear Equation System Solver (NESS), for simulating individual geothermal power plant components, (2) the advanced geochemical speciation solver, Reaktoro, used for calculation of thermodynamic fluid properties, and (3) compositional models for the calculation of fluid-dynamical properties (e.g., viscosity as a function of temperature and brine composition). The accuracy of the model is verified by comparing its predictions with experimental data from single-salt, binary-salt, and multiple-salt solutions. The geothermal power plant simulations show that the brines considered in this study can be divided into three main categories: (1) those of largely meteoric origin with low salinity for which the effect of salt concentration is negligible; (2) moderate-depth brines with high concentrations of Na + and K + ions, whose performance is well approximated by pure NaCl solutions of equivalent salinity; and (3) deeper, high-salinity brines that require a more detailed consideration of their composition for accurate simulation of plant operations.

Continental rifting is initiated by a dynamic interplay between tectonic stretching and mantle upwelling. Decompression melting assists continental breakup through lithospheric weakening and enforces upflow of melt to the Earth's surface. However, the details about melt transport through the brittle crust and storage under narrow rift‐aligned magmatic segments remain largely unclear. Here we present a crustal‐scale electrical conductivity model for a magmatic segment in the Ethiopian Rift, derived from 3‐D phase tensor inversion of magnetotelluric data. Our subsurface model shows that melt migrates along preexisting weak structures and is stored in different concentrations on two major interconnected levels, facilitating the formation of a convective hydrothermal system. The obtained model of a transcrustal magmatic system offers new insights into rifting mechanisms, evolution of magma ascent, and prospective geothermal reservoirs., Geophysical Research Letters, 45 (23), ISSN:0094-8276, ISSN:1944-8007

A direct CO2-Plume Geothermal (CPG) system is a novel technology that uses captured and geologically stored CO2 as the subsurface working fluid in sedimentary basin reservoirs to extract geothermal energy. In such a CPG system, the CO2 that enters the production well is likely saturated with H2O from the geothermal reservoir. However, direct CPG models thus far have only considered energy production via pure (i.e. dry) CO2 in the production well and its direct conversion in power generation equipment. Therefore, we analyze here, how the wellhead fluid pressure, temperature, liquid water fraction, and the resultant CPG turbine power output are impacted by the production of CO2 saturated with H2O for reservoir depths ranging from 2.5 km to 5.0 km and geothermal temperature gradients between 20 °C/km and 50 °C/km. We demonstrate that the H2O in solution is exothermically exsolved in the vertical well, increasing the fluid temperature relative to dry CO2, resulting in the production of liquid H2O at the wellhead. The increased wellhead fluid temperature increases the turbine power output on average by 15% to 25% and up to a maximum of 41%, when the water enthalpy of exsolution is considered and the water is (conservatively) removed before the turbine, which decreases the fluid mass flow rate through the turbine and thus power output. We show that the enthalpy of exsolution and the CO2-H2O solution density are fundamental components in the calculation of CPG power generation and thus should not be neglected or substituted with the properties of dry CO2.

We investigate the potential for extracting heat from produced natural gas and utilizing supercritical carbon dioxide (CO2) as a working fluid for the dual purpose of enhancing gas recovery (EGR) and extracting geothermal energy (CO2-Plume Geothermal – CPG) from deep natural gas reservoirs for electric power generation, while ultimately storing all of the subsurface-injected CO2. Thus, the approach constitutes a CO2 capture double-utilization and storage (CCUUS) system. The synergies achieved by the above combinations include shared infrastructure and subsurface working fluid. We integrate the reservoir processes with the wellbore and surface power-generation systems such that the combined system’s power output can be optimized. Using the subsurface fluid flow and heat transport simulation code TOUGH2, coupled to a wellbore heat-transfer model, we set up an anticlinal natural gas reservoir model and assess the technical feasibility of the proposed system. The simulations show that the injection of CO2 for natural gas recovery and for the establishment of a CO2 plume (necessary for CPG) can be conveniently combined. During the CPG stage, following EGR, a CO2-circulation mass flowrate of 110 kg/s results in a maximum net power output of 2 MWe for this initial, conceptual, small system, which is scalable. After a decade, the net power decreases when thermal breakthrough occurs at the production wells. The results confirm that the combined system can improve the gas field’s overall energy production, enable CO2 sequestration, and extend the useful lifetime of the gas field. Hence, deep (partially depleted) natural gas reservoirs appear to constitute ideal sites for the deployment of not only geologic CO2 storage but also CPG.

Combined thermo-mechanical drilling is a novel technology to enhance drilling performance in deep hard rock formations. In this work, we demonstrate this technology in the field by implementing the concept on a full-scale drilling rig, and we show its feasibility under realistic process conditions. We provide evidence that the novel drilling method can increase the removal performance in hard rocks by up to a factor of three, compared to conventional drilling methods. From the findings of this work, we conclude that integration of thermal assistance to conventional rotary drilling constitutes an interesting approach to facilitate the drilling process, and therefore increase the access viability to deep georesources in hard rocks.

Several studies suggest that CO 2 -based geothermal energy systems may be operated economically when added to ongoing geologic CO 2 sequestration. Alternatively, we demonstrate here that CO 2 -Plume Geothermal (CPG) systems may be operated long-term with a finite amount of CO 2 . We analyze the performance of such CO 2 -limited CPG systems as a function of various geologic and operational parameters. We find that the amount of CO 2 required increases with reservoir depth, permeability, and well spacing and decreases with larger geothermal gradients. Furthermore, the onset of reservoir heat depletion decreases for increasing geothermal gradients and for both particularly shallow and deep reservoirs.

In contrast to conventional hydrothermal systems or enhanced geothermal systems, CO 2 Plume Geothermal (CPG) systems generate electricity by using CO 2 that has been geothermally heated due to sequestration in a sedimentary basin. Four CPG and two brine-based geothermal systems are modeled to estimate their power production for sedimentary basin reservoir depths between 1 and 5 km, geothermal temperature gradients from 20 to 50 °C km −1 , reservoir permeabilities from 1 × 10 −15 to 1 × 10 −12 m 2 and well casing inner diameters from 0.14 m to 0.41 m. Results show that CPG direct-type systems produce more electricity than brine-based geothermal systems at depths between 2 and 3 km, and at permeabilities between 10 −14 and 10 −13 m 2 , often by a factor of two. This better performance of CPG is due to the low kinematic viscosity of CO 2 , relative to brine at those depths, and the strong thermosiphon effect generated by CO 2 . When CO 2 is used instead of R245fa as the secondary working fluid in an organic Rankine cycle (ORC), the power production of both the CPG and the brine–reservoir system increases substantially; for example, by 22% and 20% for subsurface brine and CO 2 systems, respectively, with a 35 °C km −1 thermal gradient, 0.27 m production and 0.41 m injection well diameters, and 5 × 10 −14 m 2 reservoir permeability.

Geothermal energy has been successfully employed in Switzerland for more than a century for direct use but presently there is no electricity being produced from geothermal sources. After the nuclear power plant catastrophe in Fukushima, Japan, the Swiss Federal Assembly decided to gradually phase out the Swiss nuclear energy program. Deep geothermal energy is a potential resource for clean and nearly CO2-free electricity production that can supplant nuclear power in Switzerland and worldwide. Deep geothermal resources often require enhancement of the permeability of hot-dry rock at significant depths (4-6 km), which can induce seismicity. The geothermal power projects in the Cities of Basel and St. Gallen, Switzerland, were suspended due to earthquakes that occurred during hydraulic stimulation and drilling, respectively. Here we present an alternative unconventional geothermal energy utilization approach that uses shallower, lower-temperature, naturally permeable regions, that drastically reduce drilling costs and induced seismicity. This approach uses geothermal heat to supplement a secondary energy source. Thus this hybrid approach may enable utilization of geothermal energy in many regions in Switzerland and elsewhere, that otherwise could not be used for geothermal electricity generation. In this work, we determine the net power output, energy conversion efficiencies, and economics of these hybrid power plants, where the geothermal power plant is actually a CO2-based plant. Parameters varied include geothermal reservoir depth (2.5-4.5 km) and turbine inlet temperature (100-220 °C) after auxiliary heating. We find that hybrid power plants outperform two individual, i.e., stand-alone geothermal and waste-heat power plants, where moderate geothermal energy is available. Furthermore, such hybrid power plants are more economical than separate power plants., Energy Procedia, 114, ISSN:1876-6102, 13th International Conference on Greenhouse Gas Control Technologies, GHGT-13

CPG (CO2 Plume Geothermal) energy systems use CO2 to extract thermal energy from naturally permeable geologic formations at depth. CO2 has advantages over brine: high mobility, low solubility of amorphous silica, and higher density sensitivity to temperature. The density of CO2 changes substantially between geothermal reservoir and surface plant, resulting in a buoyancy-driven convective current – a thermosiphon – that reduces or eliminates pumping requirements. We estimated and compared the strength of this thermosiphon for CO2 and for 20 weight percent NaCl brine for reservoir depths up to 5 km and geothermal gradients of 20, 35, and 50 °C/km. We found that through the reservoir, CO2 has a pressure drop approximately 3–12 times less than brine at the same mass flowrate, making the CO2 thermosiphon sufficient to produce power using reservoirs as shallow as 0.5 km. At 2.5 km depth with a 35 °C/km gradient – the approximate western U.S. continental mean – the CO2 thermosiphon converted approximately 10% of the energy extracted from the reservoir to fluid circulation, compared to less than 1% with brine, where additional mechanical pumping is necessary. We found CO2 is a particularly advantageous working fluid at depths between 0.5 km and 3 km.

Recent geotechnical research shows that geothermal heat can be efficiently mined by circulating carbon dioxide through naturally permeable rock formations -- a method called CO 2 Plume Geothermal -- the same geologic reservoirs that are suitable for deep saline aquifer CO 2 sequestration or enhanced oil recovery. This paper describes the effect of thermal drawdown on reservoir pressure buildup during sequestration operations, revealing that geothermal heat mining can decrease overpressurization by 10% or more.

A review of coupled groundwater and heat transfer theory is followed by an introduction to geothermal measurement techniques. Thereafter, temperature-depth profiles (geotherms) and heat discharge at springs to infer hydraulic parameters and processes are discussed. Several studies included in this review state that minimum permeabilities of approximately 5 × 10−17

[1] Geothermal energy offers clean, renewable, reliable electric power with no need for grid-scale energy storage, yet its use has been constrained to the few locations worldwide with naturally high geothermal heat resources and groundwater availability. We present a novel approach with the potential to permit expansion of geothermal energy utilization: heat extraction from naturally porous, permeable formations with CO2 as the injected subsurface working fluid. Fluid-mechanical simulations reveal that the significantly higher mobility of CO2, compared to water, at the temperature/pressure conditions of interest makes CO2 an attractive heat exchange fluid. We show numerically that, compared to conventional water-based and engineered geothermal systems, the proposed approach provides up to factors of 2.9 and 5.0, respectively, higher geothermal heat energy extraction rates. Consequently, more regions worldwide could be economically used for geothermal electricity production. Furthermore, as the injected CO2 is eventually geologically sequestered, such power plants would have negative carbon footprints.

Carbon dioxide (CO2) sequestration in deep saline aquifers and exhausted oil and natural gas fields has been widely considered as a means for reducing CO2 emissions to the atmosphere as a counter-measure to global warming. However, rather than treating CO2 merely as a waste fluid in need of permanent disposal, we propose that it could also be used as a working fluid in geothermal energy capture, as its thermodynamic and fluid mechanical properties suggest it transfers geothermal heat more efficiently than water. Energy production and sales in conjunction with sequestration would improve the economic viability of CO2 sequestration, a critical challenge for large-scale implementation of the technology. In addition, using CO2 as the working fluid in geothermal power systems may permit utilization of lower temperature geologic formations than those that are currently deemed economically viable, leading to more widespread utilization of geothermal energy. Here, we present the results of early-stage calculations demonstrating the geothermal energy capture potential of CO2-based geothermal systems and implications of such energy capture for the economic viability of geologic CO2 sequestration., Energy Procedia, 4, ISSN:1876-6102, 10th International Conference on Greenhouse Gas Control Technologies

CO2-Plume Geothermal (CPG) technology involves injecting CO2 into natural, highly permeable geologic units to extract energy. The subsurface CO2 absorbs heat from the reservoir, buoyantly rises to the surface, and drives a power generation system. The CO2 is then cooled and reinjected underground. Here, we analyze the effects of multi-layered geologic reservoirs on CPG system performance by examining the CO2 mass fraction in the produced fluid, pore-fluid pressure buildup during operation, and heat energy extraction rates. The produced CO2 mass fraction depends on the stratigraphic positions of highly permeable layers which also affect the pore-fluid pressure drop across the reservoir.