An Integrated Framework for Geothermal Energy Storage with CO 2 Sequestration and Utilization

Subsurface geothermal energy storage has greater potential than other energy storage strategies in terms of capacity scale and time duration. Carbon dioxide (CO 2 ) is regarded as a potential medium for energy storage due to its superior thermal properties. Moreover, the use of CO 2 plumes for geothermal energy storage mitigates the greenhouse effect by storing CO 2 in geological bodies. In this work, an integrated framework is proposed for synergistic geothermal energy storage and CO 2 sequestration and utilization. Within this framework, CO 2 is ﬁrst injected into geothermal layers for energy accumulation. The resultant high-energy CO 2 is then introduced into a target oil reservoir for CO 2 utilization and geothermal energy storage. As a result, CO 2 is sequestrated in the geological oil reservoir body. The results show that, as high-energy CO 2 is injected, the average temperature of the whole target reservoir is greatly increased. With the assistance of geothermal energy, the geological utilization efﬁciency of CO 2 is higher, resulting in a 10.1% increase in oil displacement efﬁciency. According to a storage-potential assessment of the simulated CO 2 site, 110 years after the CO 2 injection, the utilization efﬁciency of the geological body will be as high as 91.2%, and the ﬁnal injection quantity of the CO 2 in the site will be as high as 9.529 (cid:1) 10 8 t. After 1000 years sequestration, the supercritical phase dominates in CO 2 sequestration, followed by the liquid phase and then the mineralized phase. In addition, CO 2 sequestration accounting for dissolution trapping increases signiﬁcantly due to the presence of residual oil. More importantly, CO 2 exhibits excellent performance in storing geothermal energy on a large scale; for example, the total energy stored in the studied geological body can provide the yearly energy supply for over 3.5 (cid:1) 10 7 normal households. Application of this integrated approach holds great signiﬁcance for large-scale geothermal energy storage and the achievement of carbon neutrality. (cid:1) 2023 THE AUTHORS. Published by Elsevier LTD on behalf of Chinese Academy of Engineering and Higher Education Press Limited Company. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).


Introduction
The atmospheric concentration of carbon dioxide (CO 2 ) is increasing sharply due to the acceleration of global industrialization in recent years.This increasing CO 2 concentration is the main cause of climate change and other deleterious impacts on our living environment [1].According to the International Energy Agency (IEA) report, global energy-related carbon dioxide emissions increased by 6% to 3.63 Â 10 10 t in 2021 [2].The absolute increase in global carbon dioxide emissions exceeded 2 Â 10 9 t, the largest increase in history [2].
Since 2000, CO 2 has been used as an excellent working fluid for extracting geothermal energy from deep geothermal layers [3].Compared with underground brine, CO 2 has three main https://doi.org/10.1016/j.eng.2022.12.010 2095-8099/Ó 2023 THE AUTHORS.Published by Elsevier LTD on behalf of Chinese Academy of Engineering and Higher Education Press Limited Company.This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

⇑ Corresponding author.
E-mail address: zhenhuarui@gmail.com(Z.Rui).# These authors contributed equally to this work.Engineering 30 (2023) [121][122][123][124][125][126][127][128][129][130] Contents lists available at ScienceDirect Engineering j o u r n a l h o m e p a g e : w w w .e l s e v i e r .c o m / l o c a t e / e n g superiorities: ① The mineral solubility of CO 2 is smaller than that of formation brine, which reduces pipe or equipment scaling [3]; ② the kinematic viscosity of CO 2 is lower than that of formation brine, which reduces the pressure losses to reservoir rocks [4,5]; and ③ CO 2 is more compressible than liquid water, which allows the generation of a thermosiphon, reducing the strict requirement for circulation pumps [6][7][8][9].It has been found that CO 2 has a higher heat transfer rate than formation brine [10].However, the geothermal layers have their limited potential for CO 2 storage due to its limited reservoir volume for sequestration [11,12].Therefore, sedimentary geothermal basins with extremely low permeability caprocks have been proposed for CO 2 storage, as they have been recognized to have large potential for this purpose [13][14][15][16][17]. Recently, the depleted natural gas reservoirs [18] and depleted oil reservoirs [19] was proposed for the suitable sites for CO 2 sequestration and energy storage [20].
Fossil fuel burning generates significant CO 2 emissions, accounting for 73% of global carbon emissions [21].CO 2 utilization and storage are currently regarded as one of the most feasible and applicable CO 2 capture, utilization, and storage (CCUS) technologies, accounting for 77% of total global carbon reduction to date [22].One of the most promising methods of CO 2 utilization and storage is to simultaneously use enhanced oil recovery combined with CO 2 sequestration in target reservoirs [23][24][25][26][27][28].The performance of CO 2 in enhanced oil recovery greatly relies on the mass transfer between CO 2 and crude oil [29][30][31][32][33][34].It has been found that miscibility or near-miscibility achieves higher oil recovery than immiscibility [35][36][37][38].In addition, the CO 2 storage potential is more significant under the condition of miscibility or nearmiscibility than under immiscibility [35][36][37][38].To achieve miscibility, the system pressure should be at or above the minimum miscibility pressure (MMP) [39].However, it is uneconomical to increase the target reservoir pressure artificially to achieve miscibility [40,41].Recently, chemical solvents such as alcohol, propanol, and dimethyl ether [42,43] have been introduced to accompany CO 2 in enhanced oil recovery, reducing the MMP between CO 2 and crude oil by more than 10%.In addition to reduc-ing the MMP, modified CO 2 injection-such as water alternating gas (WAG) and so forth-has been investigated in order to improve the CO 2 injection performance by increasing the sweep efficiency of CO 2 [44][45][46][47][48][49].
In this work, we propose an integrated framework for synergistic geothermal energy storage and CO 2 sequestration and utilization.Within this framework, CO 2 is first injected into geothermal layers, where the geothermal energy is efficiently transferred to the low-temperature CO 2 due to the higher heat transfer coefficient of the latter.The resultant high-energy CO 2 is then introduced into the target reservoir for simultaneous CO 2 utilization and sequestration and geothermal energy storage.The schematic work flows of this integrated framework are shown in Fig. 1.

Overview of simulation tools
In this work, simulations were performed using the TOUGHREACT-EOR code package, which can simulate the interaction between CO 2 and multicomponent oil phases, as well as the multicomponent reactive transport of a complex aqueous phase in subsurface multiphase systems.This simulator has been updated by introducing a multicomponent oil phase to the existing simulation framework of multiphase flow and heat flow with reactive transport [50][51][52].For numerical calculations, spatial discretization was carried out using the integral finite difference (IFD), and the time discretization was the fully implicit difference.A sequential iterative approach that referred to a previous work [53] was used in the coupled calculation of flow and reactive transport.Details on the reactive transport simulator are provided in a previous work [54].
The updated oil-bearing multiphase, multicomponent simulation program, coupled with a thermo-hydro-chemical (T-H-C) simulator, still possesses all the merits of the original simulator (i.e., non-isothermal, multiphase solute transport considering convection diffusion, geochemical reactions, and a comprehensive database of thermodynamic and kinetic parameters).The key differences are that the updated simulator takes into account the following processes: ① flash evaporation to solve the mass transfer process between CO 2 and the multicomponent oil phase; and ② CO 2 miscibility and immiscibility.Overall, the updated simulator can quantitatively characterize the migration and transformation of CO 2 among the supercritical phase, dissolved-in-water phase, dissolved-in-oil phase, and mineralized phase; thus, it is an optional software for carbon sequestration research in CO 2geological utilization technology.

Model initial and boundary conditions
In this study, we developed a three-dimensional (3D) wellborereservoir coupling model.Fig. 2 presents the longitudinal section of the wellbore-reservoir coupling model, which uses different governing equations to calculate the fluid phase behavior in the wellbore and reservoir.The one-dimensional (1D) two-phase momentum equation is used for the wellbore and the 3D multiphase Darcy's Law is employed for the reservoir [55].The thickness of the entire stratum is 2.02 km, including a geothermal layer located at the bottom, with a thickness of 100 m and a depth of 3.52 km, and an oil reservoir at the top, with a thickness of 20 m and a depth of 1.5 km.A group of injection-production wells in an inverse ''nine-point" well pattern is defined in the model to finish the desired simulation work.Based on the symmetry principle, the 1/4 area of the well pattern is simulated and Dirichlet conditions with fixed temperature and pressure are considered for the lateral boundaries.A semi-analytical solution is used to calculate the heat exchange between the wellbore and formation [56].
Fluids are heated in the geothermal formation through a 200 m horizontal well and then injected into the oil reservoir along a 2.0 km long vertical well.Details of the target reservoir's initial physical parameters and the pseudo components of the crude oil used in our model are provided in Tables 1 and 2 [57], respectively.Details of the geothermal formation's initial physical parameters and the wellbore parameters are presented in Table 3 [58].
The geochemical conditions of the model are set according to the site data.The aqueous solution type is Na-HCO 3 , and the stratigraphic lithology is feldspar quartz sandstone.We consider three mechanisms influencing the kinetically controlled mineral dissolution and precipitation, and the reaction rate constant (k) is calculated using the Lasaga model (1984), as shown in Eq. ( 1): where k 25 (molÁ(m 2 Ás) À1 ) is the kinetic constant at 25 °C, and E a (kJÁmol À1 ) is the activation energy, R is gas constant, T 0 is absolute temperature (K), a is the activity of the species.The power terms (n) for both the acid (H) and base (OH) mechanisms are for H + , superscripts nu indicate neutral mechanisms.The reaction kinetic parameters related to the geochemical calculation are listed in Tables 4 and 5 [59 -61].
The solubilities of the CO 2 and the hydrocarbon component in the gas and oil phases are calculated by flash calculations using the Peng-Robinson (PR) equation of state, and the solubility of the CO 2 in the water phase is calculated using Henry's law.The oil viscosity (l) in our model is considered to be a function of temperature, pressure, the compression coefficient, and the where f is the fluidity of multicomponent fluids; N is the number of components; u i and u j are the viscosity of components i and j, respectively; h i ðh j Þ is the function of x i (x j ) and M i (M j ); and E A i;j is the average efficiency interaction coefficient between component i and j, as shown in Eqs. ( 3)-( 5): where l c is the critical viscosity; T is temperature (K); P is pressure (Pa); a is pressure coefficient (Pa À1 ); x i is the molar fraction of component i; and M i and M j are the molecular mass of components i and j, respectively.In this work, the target reservoir is developed by alternately injecting CO 2 and water for 10 years.In the first (i.e., 0-2.5 years) and third (i.e., 5.0-7.5 years) periods of 2.5 years, CO 2 injection is performed.In the second (i.e., 2.5-5.0 years) and fourth (i.e., 7.5-10.0years) periods of 2.5 years, water injection is performed to improve the sweep volume of the injected fluid and enhance the heat transfer capacity of the geothermal layers.After 10 years of alternating injection cycles, CO 2 is injected continuously for 100 years for CO 2 sequestration and geothermal energy storage; here, it should be noted that geothermal energy is stored in the target geological reservoir body accompanying CO 2 sequestration.Three cases are adopted in this simulation: case 1, in which the CO 2 or water is first injected into the geothermal layers for energy assimilation, and the high-energy CO 2 is then injected into the target geological reservoir body for CO 2 utilization-that is, enhanced oil recovery; case 2, in which CO 2 or water is injected into the target reservoir directly for oil recovery; and case 3, in which the target oil reservoir is assumed to be depleted, and CO 2 is then injected for 100 years for sequestration and, more importantly, geothermal energy is stored in the CO 2 accompanying the CO 2 sequestration.

Calculation of energy storage with CO 2
At a given pressure and temperature, the total energy stored in CO 2 is composed of the temperature exergy and the pressure exergy [63], which are given by Eq. ( 6): where e x,H represents the specific enthalpy (i.e., total energy) of CO 2 under given conditions, in kJÁkg À1 ; e x,T represents the specific exergy to temperature, in kJÁkg À1 ; and e x,P represents the specific exergy to pressure, in kJÁkg À1 .The e x,P can be considered to be the work done by CO 2 expansion under isothermal conditions, which can be expressed as shown in Eq. ( 7) [58]: where e x represents the specific exergy, in kJÁkg À1 ; T s represents the system temperature, in K; P 1 represents the absolute pressure of CO 2 in the target reservoir, in MPa; P 2 represents the absolute pressure of natural gas at the ground surface, in MPa; V represents the specific volume of CO 2 , in m 3 Ákg À1 ; and R g represents the gas molar constant.
When the temperature is changed from T s to the given temperature, the e x,T is calculated as shown in Eq. ( 8) [64]: where T 1 represents the temperature of CO 2 , in K; and C P represents the specific heat capacity at the given pressure, in kJÁ(kgÁK) À1 .

Improved reservoir temperature
The initial temperature of the target reservoir is 333.15K.The temperature increment of high-energy CO 2 /water after flowing through the geothermal layer is expressed as follows (Fig. S1 in  Appendix A): During the first 2.5 years, CO 2 is injected through the geothermal layer, which has a temperature of 383.15 K, and is then injected into the target reservoir, which has an initial temperature of 333.15 K.The temperature of the high-energy CO 2 (which averages 341.75 K) is always higher than the initial reservoir temperature (333.15K).To improve the utilization efficiency of the CO 2 , its injection is alternated with water injection in the second 2.5-year period.It can be seen that the temperature of the injected water is higher than that of the CO 2 , reaching as high as 355.45K, because the specific heat capacity per unit mass of water is higher than that of CO 2 .
In the third period of 2.5 years, high-energy CO 2 is reinjected into the target reservoir.As shown in Fig. S1, the temperature of the high-energy CO 2 decreases sharply at the beginning of the injection.After 2.5 years of water injection, condensate water has filled in the wellbore at the section between the geothermal layer and the target reservoir.When the high-energy CO 2 flows through this section, substantial heat loss occurs due to heat exchange with the condensate water, resulting in an intense decrease in the tem-perature of the high-energy CO 2 .However, the temperature of the high-energy CO 2 gradually increases to around 341.15 K, which is deemed to be beneficial for CO 2 utilization.In the fourth 2.5-year period, water is again injected, this time with an average temperature as high as 351.15K, which is much higher than the original target reservoir temperature of 333.15 K.
The temperature distributions over the target reservoir during the two cycles of CO 2 /water injection are shown in Appendix Fig. S2.The temperature around the injecting wellbore for the high-energy CO 2 /water injection is much higher than that of the main body of the target reservoir.Compared with the highenergy CO 2 injection, the high-energy water injection results in a much higher temperature around the injection wellbore.The average temperature of the target reservoir during the 0-2.5-year and 5.0-7.5-yearperiods of high-energy CO 2 injection is 335.4 and 336.41 K, respectively, which is higher than the initial temperature of the target reservoir.Moreover, the average temperature of the target reservoir during the 2.5-5.0-year and 7.5-10.0-yearperiods of high-energy water injection is 336.9 and 338.23 K, respectively; thus, the high-energy water injection better promotes the target reservoir temperature than the high-energy CO 2 injection.Compared with injecting CO 2 /water directly, the high-energy CO 2 / water injection results in the target reservoir having relatively higher temperatures.Higher temperatures enhance the transfer of CO 2 to crude oil and reduce the oil's viscosity, which result in a higher efficiency of CO 2 utilization for enhanced oil recovery.Furthermore, a higher temperature is critical for large-scale geothermal energy storage in CO 2 .

CO 2 geological utilization
Fig. 3 presents the oil viscosity distribution over the target reservoir after 10 years of CO 2 /water injection.The oil viscosity is relatively higher near the wellbores than in the main body of the target reservoir.The residual oil near the wellbores is efficiently swept by the CO 2 and injected water, which causes the viscosity to become heavier due to the extraction effect of the CO 2 ; that is, the CO 2 has a strong extraction effect on the light hydrocarbons in the crude oil.After two cycles of CO 2 extraction, the viscosity of the crude oil increases significantly.The oil viscosity over the whole target reservoir body after cycles of high-energy CO 2 /water injection (case 1) is generally smaller than that after injecting CO 2 / water directly (case 2).The additional geothermal energy contributes to the viscosity reduction and facilitates CO 2 utilization for enhanced oil recovery.Fig. 4 presents the oil production in terms of the development time for high-energy CO 2 /water injection (case 1) and direct CO 2 / water injection (case 2).After the first four years of injection, the oil production is similar in both cases.During the initial development stage, the quantity of CO 2 injected plays the key role in improving CO 2 utilization and sequestration.During the 4th to 10th years of injection, the introduced geothermal energy reduces the oil viscosity and improves the mobility of the crude oil, which favors CO 2 utilization.Without geothermal energy, the injected CO 2 /water can readily break through due to the high mobility ratio between the crude oil and the CO 2 /water.However, as the mobility ratio decreases over time due to the introduced geothermal energy, the oil production of the direct CO 2 /water injection lags behind that of the high-energy CO 2 /water injection.In other words, the additional geothermal energy plays a more important role in improving CO 2 utilization during the 4th to 10th years of injection than during the first four years.
When the displacement efficiency in 10 years is calculated according to the sweep volume, the result is 63.6% for case 1 and 53.5% for case 2, as shown in Fig. 4.This result indicates that the main mechanism for enhancing oil recovery in case 1 is the enhanced mass transfer between the CO 2 and the oil due to the high-energy injection.The averaged oil saturation (Fig. S3 in Appendix A) after the high-energy CO 2 /water injection is generally lower than that after the direct CO 2 /water injection, which validates the higher efficient utilization of CO 2 with the assistance of geothermal energy.

Energy storage and CO 2 sequestration during oil reservoir development
In the first 2.5 years, a relatively larger amount of CO 2 dissolves into the crude oil as CO 2 is injected continuously (Fig. S4 in Appendix A).As a result, the molar fraction of CO 2 increases, especially near the injection wellbores, with an averaged value of 0.4485.During the 2.5-5.0-yearperiod, water is injected, and the CO 2saturated reservoir fluids are displaced by the injected water, which results in a sudden decrease in the molar fraction of CO 2 .Subsequently, CO 2 is reinjected, and the molar fraction of CO 2 increases to an averaged value of 0.2209, which is less than that during the first round of CO 2 injection.During the 7.5-10-year period, water is again injected, and the molar fraction of CO 2 decreases to an averaged value of 0.1766.As can be seen, the injected water has a major influence on the CO 2 dissolution in the reservoir fluids, which is not beneficial for CO 2 sequestration.
The direct CO 2 /water injection (case 2) results in relatively smaller molar fractions of CO 2 in the oil phase (Figs.S4 and S5 in Appendix A).There are two main reasons for this.First, the higher temperatures in the high-energy injection scenario (case 1) keep the viscosity of the reservoir fluids at a relatively low level, which is essential for achieving sufficient contact between the CO 2 and the reservoir fluids.In addition, the CO 2 molecules have a higher diffusion coefficient at higher temperatures, which is critical for the miscibility between the CO 2 and the reservoir fluids.Therefore, the additional geothermal energy is beneficial for CO 2 sequestration in the target reservoirs.The reservoir porosity near the injection wellbore in case 1 is greater than that in case 2 (Fig. S6 in  Appendix A).This finding suggests that, with the assistance of geothermal energy, the CO 2 /water in case 1 exhibits better performance in flowing and sweeping the residual reservoir fluid out from the target reservoir.The resulting free space in the target reservoir is a suitable site for future large-scale CO 2 sequestration and geothermal energy storage.
CO 2 can also be used as a suitable agent for geothermal energy storage, by transferring deep geothermal energy to a relatively shallow target reservoir for large-scale energy storage.As mentioned previously, the total energy stored in CO 2 is highly dependent on the system pressure and temperature, and is composed of the temperature exergy and the pressure exergy.Fig. S2 presents the average temperature increase of the target reservoir due to the injection of high-energy CO 2 /water.The reservoir pressure is greatly increased after injecting high-energy CO 2 /water (Fig. S7 in Appendix A); it should be noted here that the original reservoir pressure is 15.0 MPa.The target reservoir presents a lesser pressure increase after the injection of high-energy CO 2 /water (case 1) than after the direct CO 2 /water injection (case 2).When geothermal energy is transferred into the target reservoir, the viscosity of the reservoir fluids is significantly reduced, which is beneficial for the dissolution of CO 2 in the reservoir fluids, resulting in a relatively lower reservoir pressure.
In this simulation, CO 2 is injected at 43.2 t per day; after ten years of CO 2 /water injection, the total CO 2 injected is 78 840 t, and 5250 t of CO 2 are produced accompanied by reservoir fluids.Thus, for case 1, the effective storage quantity of CO 2 is 68 340 t.Similarly, in case 2, 78 840 t of CO 2 are injected and the quantity of CO 2 produced is 6750 t.Thus, for case 2, the effective storage quantity of CO 2 is 65 340 t.According to Eq. ( 3), the geothermal energy stored in the CO 2 in case 1 can be calculated to be around 2.10 Â 10 4 GJ.(The CO 2 in case 2 is not considered to store geothermal energy in this work.)In order to improve the storage capacity of geothermal energy and CO 2 sequestration in the target geological reservoir body, the target oil reservoir is deemed to be depleted at this point, and five more injection wells are built for CO 2 injection (Section 4.4).

Energy storage and CO 2 sequestration in a geological oil reservoir body
Based on the geological background of Block H59 in Jilin Oil-China [40], a 1:1 3D numerical model was established, as shown in Fig. 5.According to the existing well deployment, six injection wells are opened for CO 2 injection in the model.This model is employed to assess the potential of the site sequestration and energy storage capacity of CO 2 .The heat extraction rate gradually decreases as the injection time increases (Fig. S8 in Appendix A), indicating that, as more CO 2 is injected into the target reservoir over time, the temperature of the CO 2 decreases.Therefore, the heat extraction process is stopped after 30 years of CO 2 injection through the geothermal layer, considering the low efficiency of heat extraction.After 30 years, CO 2 is injected directly into the target oil reservoir for another 80 years for CO 2 sequestration.
After 10 years of oil reservoir development (i.e., water injection alternating with CO 2 injection), CO 2 is then injected for 100 years for CO 2 sequestration and energy storage, until more than 90% of the total porosity of the entire site is occupied.Fig. 6 presents the spatial distribution of the CO 2 after 110 years at different reservoir depths.Due to its buoyancy, CO 2 accumulates in large quantities at the top of the oil reservoir geological body.In order to improve the utilization efficiency of the oil reservoir geological body, six injection wells are opened for CO 2 injection after 10 years' oil production.Fig. 7 presents the utilization efficiency of the reservoir geological body and the corresponding total quantity of CO 2 injection.It is found that the utilization efficiency of the geological body increases as more CO 2 is injected.The final quantity of CO 2 injection at the site is as high as 9.529 Â 10 8 t, at which the utilization efficiency of the geological body is up to 91.2%.
In addition to CO 2 sequestration, the CO 2 is employed as an excellent medium for geothermal energy storage.According to Eq. ( 3), the total energy stored in the target geological reservoir body is calculated in terms of the injection time.Fig. 8 presents the geothermal energy stored in the target geological reservoir body as CO 2 is injected.It can be seen that the energy stored is transformed into a standard coal mass in Fig. 8.The calorific value of standard coal is 2.933 Â 10 4 kJÁkg À1 , which is a method for representing standard energy.We find that the geothermal energy stored by CO 2 increases linearly as more CO 2 is injected and sequestrated in the target geological reservoir body.The geothermal energy stored through CO 2 is as much as 2.46 Â 10 8 GJ after 100 years of CO 2 injection.If it is assumed that the general energy consumption of a normal household is around 7.0 GJÁa À1 , then the energy stored through CO 2 could provide the yearly energy supply for over 3.5 Â 10 7 normal households.Therefore, a substantial amount of geothermal energy stored through CO 2 can be meaningful for a future energy supply.In addition, the integrated approach well combines geothermal energy storage with CO 2 sequestration and utilization, and its wide application holds great significance for both large-scale geothermal energy storage and the achievement of future carbon neutrality goals.In order to evaluate the security of CO 2 sequestration in the target geological oil reservoir body, we quantitatively investigated the phase transitions of CO 2 in the next 1000 years when sequestrated in the target reservoir, as shown in Fig. 9.More specifically, the proportion of CO 2 in each phase-that is, the CO 2 dissolved in the oil phase, water phase, gas phase (supercritical), and mineralized phase-is calculated in terms of the sequestrated time.The CO 2 in the target oil reservoir body mainly exists as supercritical CO 2 , accounting for up to 70% of the total CO 2 ; this is followed in order by CO 2 in the liquid phase and then CO 2 in the mineralized phase.The amount of CO 2 dissolved in the oil phase is greater than that in the water phase; in other words, in the geological oil reservoir body, CO 2 tends to dissolve into the oil phase rather than the water phase for sequestration.As the sequestration process continues, the quantity of CO 2 dissolved in the aqueous phase increases as the CO 2 is further transformed into carbonate minerals, of which there are up to around 7.2 Â 10 5 t after 1000 years' sequestration.Thus, the total amount of gaseous CO 2 decreases.In comparison, the total amount of CO 2 dissolved in the oil phase remains basically unchanged.

Conclusions
This work proposed an integrated framework for synergistic geothermal energy storage, carbon sequestration, and CO 2 utilization.The key conclusions are summarized as follows: (1) When injected through the geothermal layer, CO 2 is heated to an average temperature of 341.75 K.After the injection of high-energy CO 2 for 2.5 years, the average temperatures of the target reservoir increase by around 276.15 K, and the average pressure of the target reservoir increases to 25.1-47.7 MPa, which is beneficial for efficient CO 2 utilization and geothermal energy storage.
(2) By introducing geothermal energy into the target reservoir, the solubility of CO 2 in the reservoir fluids is greatly improved.The injection of high-energy CO 2 /water exhibits a better performance  than the direct injection of CO 2 /water in sweeping the reservoir fluids out from the pore and throat, due to the introduction of the geothermal energy.Hence, the free space in the target reservoir becomes a suitable site for future large-scale CO 2 sequestration and geothermal energy storage.
(3) When CO 2 is injected for 110 years, the utilization efficiency of the geological body reaches 91.2% and the final injection quantity of CO 2 in the site is as high as 9.529 Â 10 8 t.After 1000 years of sequestration, CO 2 mainly exists in the form of supercritical CO 2 , which accounts for up to 70% of the total CO 2 ; this is followed in order by CO 2 in the liquid phase and then CO 2 in the mineralized phase.Moreover, the amount of CO 2 dissolved in the oil phase is greater than that in the water phase; in other words, CO 2 sequestration accounting for dissolution trapping increases significantly due to the presence of residual oil.
(4) CO 2 can be employed as a suitable medium for geothermal energy storage, as it can extract heat from deep geothermal layers and then be used to efficiently store the extracted heat in the target reservoir.As much as 2.46 Â 10 8 GJ of geothermal energy can be stored in the CO 2 after 100 years of CO 2 injection, which could provide a yearly energy supply for over 35 Â 10 6 normal households.This degree of large-scale energy storage is of great significance for providing a future large-scale supply of geothermal energy.
(5) The integrated approach synergistically combines geothermal energy storage with CO 2 sequestration and utilization, which is of great significance for large-scale geothermal energy storage in the future; in addition, the combined approach is beneficial for achieving the goal of carbon neutrality.

Fig. 1 .
Fig. 1.Schematic work flows of the integrated framework for geothermal energy storage and CO 2 sequestration and utilization.

Fig. 5 .Fig. 6 .
Fig. 5. Concept model of the oil reservoir site for sequestration and energy storagepotential assessment.

Fig. 7 .
Fig. 7. Utilization efficiency of the reservoir geological body and its corresponding total quantity of CO 2 injection.

Fig. 8 .Fig. 9 .
Fig. 8. Geothermal energy stored in the target geological reservoir body as CO 2 is injected.

Table 1
Initial parameters of the target oil reservoir.
c : the critical pressure; T c : the critical temperature; V c : the critical volume; i-C 5 : isopentance.a 1 atm = 101325 Pa.

Table 3
List of thermo-physical parameters of the deep geothermal layer.
Minerals with an initial volume fraction of 0 were secondary components that may have been present during the simulation.S: the specific reactive surface area per unit mass of solid; vol%: volume percentage of minerals to total rock skeleton.aCalcite is controlled by local equilibrium.