Feasibility Analysis of Deploying Coupled Compressed CO2 Energy Storage and Carbon Sequestration Systems in Different Basalt Formations
Authors: Sihao Huang, Kunqing Jiang, Xin Chen, Wei Chen, Xianbiao Bu
Published: 2026

ABSTRACT
The combination of the excellent carbon sequestration performance of basalt with compressed CO2 energy storage in aquifers has great research potential. However, the geochemical reactions caused by injected CO2 can affect reservoir properties, thereby affecting the system performance. Therefore, it is necessary to explore the feasibility of the system deployment. Based on this, this study constructed a compressed CO2 energy storage system based on basalt formations and explored the effects of different basalt formations and operating parameters on performance. The results indicate that the deployment of a compressed CO2 energy storage system in basalt formations is feasible, and the injection and extraction of gas during the energy storage process will significantly promote the dissolution of CO2. Economic analysis also indicates that it can recover the initial investment within its lifecycle, and its levelized cost of electricity is similar to the CAES systems in porous media. The formation with olivine as the main component has the best carbon sequestration performance, but the difference in the energy storage performance is not significant. The energy storage performance of the system is mainly affected by the gas-injection velocity. The energy efficiency at an injection velocity of 50 kg/s increased by 6.17%–6.52% compared to 30 kg/s. The carbon sequestration performance of the system is greatly affected by the porosity. The dissolution capacity of CO2 at a porosity of 0.4 increased by 75.73%–98.22% compared with that at 0.2.

Introduction

With the proposal of the Paris Agreement, green renewable energy has entered a stage of rapid development. However, most renewable energy sources have intermittent and unstable characteristics, which cannot provide a stable and continuous energy supply and need to be combined with energy storage technology. Compressed air energy storage in aquifers (CAESA) is a large-scale energy storage technology with flexible site selection and capacity configuration, which can be matched with various renewable energy systems.

During the initial operation of the CAESA system, a large amount of buffer gas needs to be injected into the aquifer to maintain reservoir stability. CH4 or N2 was commonly used as buffer gases in the past, but their economy and energy storage density were relatively poor. Oldenburg innovatively proposed using CO2 as a buffer gas for CAESA in 2009 and validated this concept. CO2 is easier to obtain and cheaper and has higher compressibility compared to CH4 and N2. Kim et al. compared the performance of N2 and CO2 as buffer gases, and the results showed that CO2 had better performance. A large amount of CO2 is injected into the aquifer as a buffer gas and stored there for a long time, laying a solid foundation for the combination of CAESA and CO2 capture and storage (CCS) technology. Furthermore, some researchers have proposed using supercritical CO2 instead of compressed air as the working fluid, , namely, compressed CO2 energy storage in aquifer (CCESA). Li et al. compared the performance of CAESA and CCESA systems, and the results showed that the CCESA system has higher energy recovery efficiency and lower operating costs.

Many underground media have the ability to safely capture CO2, among which basalt formations have superior carbon sequestration performance compared to other formations. , The structural stability and long-term elasticity of basalt make it an ideal reservoir for long-term storage of CO2. Once CO2 is stored in basalt formations, it will be gradually mineralized and permanently captured underground, avoiding further release into the atmosphere, , and thanks to the structural stability of basalt, making it inherently suitable for subsurface energy storage. The characteristics of basalt formations make them compatible with both CCS and CCESA technologies. Therefore, using basalt-based CCS sites for energy storage provides the possibility to fully utilize existing subsurface facilities. In addition, a simple carbon sequestration system has poor economic benefits. Combining it with energy storage technology can improve the system’s economy and facilitate the promotion and utilization of this technology.

However, compared to injecting compressed air into aquifers, injecting CO2 will lead to complex geochemical reactions that affect the physical properties of reservoirs. The rapid mineralization reaction characteristics of basalt formations cannot be ignored when evaluating the performance and security of basalt-based CCESA-CCS systems, and the geochemical reaction process caused by CO2 injection cannot be ignored. In addition, as the intensity of geochemical reactions is largely related to the mineral composition of the reservoir, different types of reservoirs may have a significant impact on energy storage and carbon sequestration performance, therefore further comparative research is needed. These geochemical reaction processes may alter reservoir porosity, gas migration processes, and capture mechanisms, directly affecting system energy storage efficiency and CO2 sequestration processes. − Previous studies on CCESA mostly regarded the reservoir as inert storage containers, ignoring the influence of this coupled water rock CO2 chemical process. ,

Therefore, in order to successfully deploy the CCESA-CCS system in basalt formations and facilitate site selection, it is crucial to evaluate the impact of geochemical reactions on the system performance in different types of basalt formations. Therefore, this study constructed a thermohydrogeochemical coupling model for CO2 energy storage systems in different types of basalt formations, in order to explore the feasibility of deploying the system in basalt formations and the reservoir and operational factors that affect system performance. The purpose is to provide guidance for the successful deployment and operation of CCESA-CCS systems in various types of basalt formations.

Methods

Concept Model

The schematic figure of the CCESA-CCS model in this study is shown in Figure a, which is a rotationally axis-symmetric model. The model consists of caprock, aquifer, bedrock, and a wellbore connecting the surface and the top of the aquifer. Previous studies have shown that the anticline aquifer is an ideal gas storage site, and the injected gas can effectively trap at the top of the aquifer and maintain the stability of gas bubbles. Therefore, the anticline aquifer was selected as the target reservoir. As shown in Figure a, the top depth of the anticline is 3000 m, the radius is 800 m, and the height is 200 m. The thickness of the aquifer is 50 m, and the thicknesses of the caprock and bedrock are 100 m. The lateral span of the model was 2000 m. The wellbore is perforated at the top of the aquifer, with a diameter of 0.226 m and a perforation length of 10 m. Table lists the parameters used in the simulation.

Schematic illustration of the numerical model (a) CCESA-CCS system schematic figure. (b) Numerical grids. (c) Initial and boundary conditions. (d) Energy storage scheme.

1Aquifer Parameters of the CCESA-CCS Systemparametersaquifercaprock and bedrockporosity0.30.001permeability (mD)10000.001vertical/horizontal permeability ratio (−)0.21specific heat capacity (J·kg–1·°C–1)920920pore compressibility (Pa–1)4.5 × 10–10 4.5 × 10–10 thermal conductivity (W·m–1·°C–1)2.52.5rock particle density (kg·m–3)26002600salinity (kg/kg)0.010.01relative permeability modelliquid phase: van Genuchten model krl=S*[1−(1−[S*]1/m)m]2 S*=(Sl−Slr)/(1−Slr) residual liquid saturation0.20.2gas phase: Corey model krg=(1−S∧)2(1−S2∧) S∧=(Sl−Sr)/(1−Slr−Sgr) residual gas saturation0.050.05capillary pressure modelvan Genuchten model P cap = −P 0([S*]−1/m – 1)1–m S* = (S l – S lr)/(1 – S lr)residual liquid saturation0.20.2

Aquifer Parameters of the CCESA-CCS System

The CCESA-CCS model mesh is shown in Figure b, and the model contains 30,040 meshes. The model has encrypted the grid in the near-wellbore area. The grid size in the horizontal direction remains consistent and increases with an increase in the distance from the well. The vertical grid size for the aquifer area is set to 1 m, while the vertical grid size for the caprock and bedrock areas is set to 5 m.

The initial liquid saturation of all grid cells is set to 1.0 and does not contain any gaseous or dissolved CO2. The surface water pressure is set to 0.1 MPa, and the groundwater pressure follows the distribution of static water pressure. The surface temperature is set to 10 °C, and the underground temperature distribution increases with a geothermal gradient of 30 °C/km. The initial and boundary conditions of the model are shown in Figure c, where q w represents heat flux and mass flux. The horizontal boundaries of the model are set to allow fluids to flow in and out freely. The top and bottom boundaries are set to be closed so that no fluid or heat transfers through them. The wellbore sidewall attached to caprocks is closed and only allows heat transfer but no fluid flow; the wellbore sidewall attached to the aquifer is open so mass and heat can freely exchange.

Before conducting the energy storage cycle, a large amount of CO2 needs to be injected as cushion gas to drain the formation water near the wellhead and prevent it from being extracted along with CO2. Injecting a large amount of cushion gas can also maintain the stability of reservoir pressure during the energy storage stage. This study assumes that cushion gas injection lasts for 100 days, with a gas injection velocity of 10 kg/s and injection temperature of 45 °C. After the injection of cushion gas is completed, the energy storage stage will be carried out. The main process is to continuously inject 12 h of supercritical CO2 into the aquifer, with injection velocity of 40 kg/s and injection temperature of 140 °C. Then, the well is shut in for 4 h. The stored CO2 is extracted at a rate of 120 kg/s for energy supply, which lasts for 4 h. After the energy supply is completed, the well is shut in for 4 h to complete the cycle. The energy storage scheme of CCESA-CCS system is shown in Figure d.

Basalt formations are mainly composed of plagioclase, pyroxene, and olivine, and their lithology and mineralization activities vary greatly depending on the proportion of each component. This paper compares the energy storage efficiency and carbon sequestration performance of the system when plagioclase, pyroxene, and olivine are the main components of the formations. The compositions of the three different types of basalt formations are shown in Table .

2Basalt Formations and Its Main Componentsnumberbasalt formationsmineral components1Columbia River Formation (Tholeitic basalt)plagioclase (50%), pyroxene (25%), volcanic glass (15%), ilmenite (5%), and olivine (5%)2Shandong Yaoshan Formation (Alkaline basalt)pyroxene (65%), plagioclase (30%), olivine (3%), and ilmenite (2%)3Kilauea Volcano Formation (Alkaline basalt)olivine (55%), pyroxene (20%), plagioclase (15%), volcanic glass (7%), and ilmenite (3%)

Basalt Formations and Its Main Components

After CO2 injection into the reservoir, it will break the physical and chemical equilibrium between the formation water and the rock, resulting in phenomena such as dissolution, precipitation, and migration of precipitation components. CO2 dissolves in formation water to form carbonic acid, which lowers the pH value of the in situ water. Hydrogen ions dissociated from carbonic acid attack basalt formations, dissolve primary minerals in the rock matrix, and release divalent cations (Ca2+, Mg2+, and Fe2+). The released divalent cations react with carbonate ions dissociated from carbonic acid to form stable carbonate minerals. The main geochemical reactions that occur in aquifers after the CO2 injection are shown in Table .

3Main Geochemical Reactions of Basalt Formationscomponentsprimary minerals dissolutionsecondary minerals precipitationplagioclaseNaAlSi3O8 + 4H+ ⇔ Na+ + Al3+ + 2H2O + 3SiO2(aq)Ca2+ + CO2 + H2O ⇔ CaCO3 + 2H+ CaAl2Si2O8 + 8H+ ⇔ Ca2+ + 2Al3+ + 4H2O + 2SiO2(aq) pyroxene[Mg,Fe]Si2O6 + 4H+ ⇔ [Mg2+,Fe2+] + 2H2O + 2SiO2(aq)[Mg2+,Fe2+] + CO2 + H2O ⇔ [Mg,Fe]CO3 + 2H+ olivine[Mg,Fe]2SiO4 + 4H+ ⇔ 2[Mg2+,Fe2+] + 2H2O + SiO2(aq)[Mg2+,Fe2+] + CO2 + H2O ⇔ [Mg,Fe]CO3 + 2H+ volcanic glassvolcanic glass + xH+ ⇔ Mg2+ + Fe2++ Fe3++ Al3++ H2O + .···.[Mg2+,Fe2+] + CO2 + H2O ⇔ [Mg,Fe]CO3 + 2H+ 2[Fe3+,Al3+] + 3CO2 + 3H2O ⇔ [Fe,Al]2(CO3)3 + 6H+ ilmeniteFeTiO3 + 6H+ ⇔ Fe2+ + Ti4+ + 3H2OFe2+ + CO2 + H2O ⇔ FeCO3 + 2H+ Ti4+ + 2CO2 + 2H2O ⇔ Ti(CO3)2 + 4H+

Main Geochemical Reactions of Basalt Formations

Numerical Model

According to the principle of mass-energy conservation, the mass-energy conservation equation of the multiphase flow in the wellbore-reservoir system can be expressed as 1 ddt∫VnMKdVn=∫ΓnFK·ndΓn+∫VnqKdVn where M is the mass or energy per volume, F is the mass or energy flux, q is the confluence source, n is the normal vector of the surface element dΓn, which points to the interior of V n. The integration is over an arbitrary subdomain V n of the system, which is bounded by the closed surface Γn.

The mass accumulation in aquifers can be expressed as 2 MK=φ∑βSβρβXβK where the total mass of component K is obtained by summing over the fluid phase β, φ is the porosity, S β is the saturation of phase β, ρβ is the density of phase β, and X β K is the mass fraction of component Κ present in phase β.

The energy accumulation in aquifers can be expressed as 3 MK=(1−ϕ)ρRCRT+ϕ∑βρβSβUβ where ϕ is the porosity of the rock, ρR is the grain density of the rock, C R is the specific heat of the rock, and U β is the specific internal energy of phase β.

The energy flux in aquifers can be expressed as 4 FK=−λ∇T+∑βhβρβuβ while, the mass flux is the sum over phases 5 FK=∑βXβKρβuβ where λ is the thermal conductivity of the rock, T is the temperature of fluid, h β is the specific enthalpy of phase β, and u β is the velocity in phase β.

Phase β velocity in aquifers can be expressed as 6 uβ=−kkrβμβ(∇Pβ−ρβg) where k is the absolute permeability, k rβ is the relative permeability of phase β, μβ is the viscosity of phase β, P β is the pressure of phase β, and g is the gravitational acceleration.

The energy accumulation in the wellbore can be expressed as 7 MK=∑βρβSβ(Uβ+uβ22+gzcos⁡θ) where z is the along wellbore coordinate, and θ is the incline angle of the wellbore.

Transport along the wellbore is governed in general by the processes of advection, diffusion, and dispersion. The total advective mass transport term for component k can be written in one-dimension as 8 FK=−λ∂T∂z−1A∑β∂∂z[AρβSβuβ(hβ+uβ22+gzcos⁡θ)]−q′ where λ is the thermal conductivity of the wellbore, A is the well cross-section area, u β is the average velocity vector of phase β in the wellbore, and q′ is the heat loss/gain of the wellbore.

Economic Assessment

The economics of the CCESA system can be evaluated through its net present value (NPV), profitability index (PI), internal rate of return (IRR), payback period (PBP), and levelized cost of electricity (LCOE). The net present value (NPV) of the system can be calculated as follows 9 NPV=∑t=0nCFt(1+i)t=∑t=1nRelec,t−Celec,t−CO&M,t(1+i)t−Csystem where n is the system lifecycle, 30 years, i is the discount rate, 6.6%, and CF t is the net cash flow during period t, which is the cash inflow minus cash outflow for that year. R elec,t is the power generation revenue of the system during period t, C elec,t is the purchase cost of electricity during period t, C O&M,t is the operation and maintenance cost during period t, and C system is the initial investment cost of the system.

The initial investment cost C system consists of equipment costs for compressor, expansion turbine, heat exchanger, deep-well pump, and drilling cost, which can be calculated as follows 10 Csystem=fsystem·(Ccomp+Cexp+CHX+Cwell+Cpump)

Among them, f system is the coefficient of labor and installation costs, 1.1, C comp is the initial investment cost of the compressor, C exp is the initial investment cost of the expansion turbine, C HX is the initial investment cost of the heat exchanger, C well is the drilling cost, and C pump is the initial investment cost of the deep well pump.

The operation and maintenance cost of the system C O&M,t is mainly related to the initial investment cost of the system, and its calculation is as follows 11 CO&M,t=fO&M·Csystem where f O&M is the operation and maintenance rate, 2%.

The initial investment cost of the compressor C comp is determined by the rated power consumption P comp, which can be calculated as follows 12 Ccomp=6.77·5840(Pcomp)0.82 while P comp is the rated power of the compressor.

The initial investment cost of the expansion turbine C exp is determined by the rated power P exp, which can be calculated as follows 13 Cexp=6.77·6000(Pexp)0.7 while P exp is the rated power of the expansion turbine.

The initial investment cost of the heat exchanger C HX is determined by the heat exchange area A HX, which can be calculated as follows 14 CHX=6.77·220·AHX0.62

The drilling cost C well is related to the drilling depth Z, and its calculation is as follows 15 Cwell=7.85(487500+1500Z+0.4Z2)

The initial investment cost of the deep-well pump C pump is related to the rated power of the pump P pump, and its calculation is as follows 16 Cpump=6.77·1970·fH·fcorr·Ppump

Among them, f H is the drilling depth correction factor, 1.7, f corr is the equipment anticorrosion factor, 1.35, P pump is the rated power of the pump, and its calculation formula is as follows 17 Ppump=mgZ1000ηpump where m is the gas injection flow rate, g is the gravitational acceleration, Z is the drilling depth, and ηpump is the pump efficiency, 72%.

The system revenue R elec,t is mainly obtained from electricity sales, and its calculation is as follows 18 Relec,t=Welec,trelec where W elec,t is the power generation value during period t, and r elec is the electricity sales revenue, set at 866.6 CNY per MWh. While the power generation value W elec,t can be calculated as follows 19 Welec,t=kRTin,tk−1[(Pin,tPout,t)(k−1)/k−1] where k is the specific heat capacity ratio, assumed to be 1.4, R is the gas constant, T in,t is the inlet temperature during period t, P is the pressure (subscripts “in” and “out” indicate whether it is at the inlet or outlet of the device).

The cost of purchasing electricity C elec,t is mainly related to the power consumption of pumps and compressors, and its calculation is as follows 20 Celec,t=cele,t(Wpump,t+Wcomp,t) where c ele,t is the electric price at time t. This article assumes that the injection and compression of gas will be carried out during the valley electricity price, with a price of 0.38 CNY/kWh, and extraction will be carried out during the peak electricity price, with a price of 1.7 CNY/kWh. W pump,t is the power consumption of the deep-well pump during period t, and W comp,t is the power consumption of the compressor during period t, it can be calculated as follows 21 Wcomp,t=kRTin,tk−1[(Pout,tPin,t)(k−1)/k−1]

The PI is the ratio of the present value of all future net cash inflows to the present value of initial investments, it can be calculated as follows 22 PI=∑t=1nCFt(1+i)t|CF0|=1+NPV|CF0| where CF0 is the cost of the system in year 0, which is the initial investment of the system.

The internal rate of return (IRR) represents the annualized compound rate of return of the project, it can be calculated as follows 23 NPV=∑t=0nCFt(1+IRR)t=0

The discounted PBP is the number of years it takes for an investment to recover its initial cost after accounting for inflation, interest, and other matters affected by the time value of money to be worthwhile to the investors, it can be calculated as follows 24 PBP=(N−1)+∑t=1NCFtCFN where N is the number of years in which the investment is recovered.

The levelized cost of energy (LCOE) is the unit energy cost during the lifecycle of the project, which is the total cost of the system during that lifecycle divided by the amount of energy generated by the system, and its calculation is as follows 25 LCOE=ClifecyclePlifecycle where C lifecycle is the total cost of the system throughout its lifecycle, while P lifecycle is the total energy generated by the system during its lifecycle.

Performance Evaluation Indicators

In this study, we focus on the efficiency of the coupled wellbore-reservoir system for storing energy, the energy efficiency of the CCESA system can be expressed as the ratio of the energy out to the energy in 26 η=Epro/Einj 27 E=∫t1t2qh(t)dt where η is the energy efficiency of CCESA, E pro is the energy produced through wellbore, and E inj is the energy injected through wellbore. While q is the mass flow rate at the wellhead, h(t) is the specific enthalpy of CO2 at time t, t 1 is the start time of injection or production, and t 2 is the end time of injection or production.

There are many issues that could affect the storage efficiency of the CCESA system, such as aquifer property variations, heating loss of the wellbore, and geochemical effects. However, the main purpose of this study is to test the energy storage of the CO2 cycle. Therefore, the numerical model must neglect some redundant issues in simulation. The following constraints should be applied: assuming there is no convection or heat source in the rock; assuming that the injection pressure of the system is constant.

Results and Discussion

Due to the current lack of simulation studies combining CO2 energy storage with the geological carbon sequestration technology, in order to verify the accuracy of the model, it is necessary to separately validate the energy storage and carbon sequestration performance of the model. To verify the energy storage performance of the model, a CO2 energy storage model for aquifers was constructed based on Shi’s simulation, and energy storage simulations were conducted under its numerical parameters, the numerical grids are shown in Figure a,b. The comparison between the simulation results and Shi’s results is shown in Figure c,d, and the results of the validation model are similar to Shi’s simulation results. After 360 days of energy storage cycles, the energy recovery efficiency of the system increased from 0.9154 to 0.9536, slightly higher than Shi’s simulation results from 0.9162 to 0.9515. The error is within 5%, so the energy storage simulation results of the validation model are relatively accurate.

(a) Horizontal profile numerical grids. (b) Vertical profile numerical grids. (c) Comparison of energy flow rate. (d) Comparison of energy recovery efficiency.

To verify the carbon sequestration performance of the model, a basalt carbon sequestration model similar to Jiang’s was constructed, and CO2 sequestration simulations were conducted under the parameters of Jiang’s model, the numerical grids are shown in Figure a. The simulation results are shown in Figure b. After 20 years of carbon sequestration, 74,000 g mol primary minerals were dissolved, while 64,300 g mol secondary minerals were precipitated. The simulation results are slightly higher than Jiang’s results. The error is within 5%, so the model’s carbon sequestration simulation results are relatively accurate.

Carbon sequestration performance verification based on Jiang’s model (a) numerical grids. (b) The amount of CO2 mineralization capture after 20 years storage in the basalt aquifer.

In the buffer gas injection stage, CO2 is injected at a rate of 10 kg/s into the aquifer, which lasts for 100 days. As CO2 is injected into the aquifer, the water in the aquifer is gradually displaced by the gas under the effect of a pressure gradient. Due to density differences, injected CO2 will accumulate at the top of the aquifer, causing a rapid increase in gas saturation near the wellbore area, as shown in Figure . Higher gas saturation effectively reduces the likelihood of formation water flowing back toward the wellbore, thereby lowering the risk of water production during system operation. Meanwhile, elevated CO2 saturation in the near-well area enhances the dominance of the gas phase in multiphase flow, weakening the competitive flow between gas and water and facilitating smoother CO2 injection and withdrawal processes. Compared with sandstone reservoirs, basalt formations have a higher stability and energy storage efficiency under geochemical reactions. However, the difference among the three formations is not obvious.

Gas saturation of different basalt aquifers with the initial bubble development (a) 50th day. (b) 100th day.

Figure a,b compares the changes in wellhead pressure and temperature of energy storage systems using air and CO2 as working gases under different basalt reservoirs. From the figure, it can be observed that the injection pressure of the compressed air energy storage system is relatively high, making gas injection difficult. In comparison, the compressed CO2 energy storage system benefits from the high density and compressibility of CO2, and its injection pressure is much lower. It can also be observed that the gas extraction temperature of the compressed CO2 energy storage system is relatively high, indicating that its thermal storage performance is better. Due to the high injection pressure and low extraction temperature of the compressed air energy storage system, its energy released power is also lower, as shown in Figure c, which is much lower than the system using CO2 as the working fluid under the same operating conditions. In addition, the comparison in Figure d also indicates that the energy recovery efficiency of the compressed air energy storage system is significantly lower than that of compressed CO2. This is due to the advantages of high density and high compressibility of CO2, which results in less space required to store the same amount of CO2, and shorter migration distance of CO2 after injection, leading to less energy loss during the migration process. Therefore, selecting CO2 as the energy storage working fluid has better performance. Under the same reservoir conditions, the energy released power of the compressed CO2 energy storage system is approximately 19.98–20.44 MW, and the per unit mass energy release of CO2 is approximately 166.54–170.32 kJ/kg. The energy release power of the compressed air energy storage system is about 19.03–19.47 MW, and the per unit mass energy release of air is about 158.57–162.28 kJ/kg, with a difference of about 5.02%.

Compare to air (a) the pressure changes at the wellhead; (b) the temperature changes at the wellhead; (c) the changes in average energy released power; (d) the changes in the energy recovery efficiency.

In addition, the differences in carbon sequestration performance between basalt and sandstone formations were analyzed, as shown in Figure . From the graph, it can be observed that the amounts of dissolved and mineralized CO2 in sandstone formations are relatively low. This is because the main minerals in sandstone formations are quartz and feldspar, which have relatively stable chemical properties. Basalt is rich in alkaline earth metal ions such as Ca, Mg, and Fe, which can react chemically with dissolved CO2 to form carbonate precipitates. From the comparison in the figure, it can be seen that the difference in CO2 dissolution is relatively small. This is because the CO2 dissolution is mainly affected by the reservoir pressure and temperature. As further mineralization reactions occur in basalt formations, the carbonate ions formed by the CO2 dissolution are consumed, promoting the dissolution of CO2. Therefore, the level of CO2 dissolution in basalt formations is relatively high. The difference in CO2 mineralization is even more pronounced as inert quartz is predominant in sandstone formations and only a small amount of rocks such as feldspar and chlorite can undergo mineralization reactions with carbonate ions at a slower rate. Compared to sandstone formations, the carbon sequestration performance of the three types of basalt formations is much better, and from the perspective of permanent sequestration, the intense mineralization reaction in basalt formations is more conducive to long-term stable geological carbon sequestration.

Carbon sequestration capacity between basalt formations and sandstone formations (a) dissolved capture. (b) Mineralized capture.

After CO2 injection into the reservoir, it will break the physical and chemical equilibrium between groundwater and rock, resulting in phenomena such as dissolution, precipitation, and migration of precipitation components. Their combined effect may lead to complex results, thereby affecting the system performance. Research has shown that periodic injection and extraction of CO2 can cause repeated expansion and contraction of the gas–liquid interface, thereby affecting carbon sequestration. To verify this claim, Figure a,b compares the carbon sequestration capacity during the energy storage cycle with the geological carbon sequestration alone. From the comparison, it can be seen that the frequent injection and extraction of gas during the energy storage cycle greatly accelerate the dissolution of CO2. This further confirms the promoting effect of gas–liquid interface fluctuations caused by energy storage processes on CO2 dissolution sequestration. The impact of energy storage cycle on mineralization sequestration is relatively complex. On one hand, the energy storage cycle promotes CO2 dissolution, increases the concentration of carbonate ions in the formation water, and to some extent promotes the positive progress of mineralization reaction. On the other hand, frequent injection and production of CO2 causes fluctuations at the gas–liquid interface, which is not conducive to the formation of precipitation.

Compare between energy storage cycle and carbon sequestration (a) dissolved capture. (b) Mineralized capture. (c) Well bottom pressure.

Frequent injection and extraction of CO2 will have a positive impact on CO2 dissolution sequestration, but the pressure changes near the wellhead during the injection and extraction processes will also have a certain impact on the safety of the system. As shown in Figure c, the change in well bottom pressure indicates that due to the gradual dissolution of injected CO2, the pressure gradually decreases during the carbon sequestration process. Unlike the carbon sequestration process, the injection of gas during the energy storage cycle will increase the well bottom pressure, whereas the extraction of gas will rapidly decrease the pressure. This process will cause fluctuations in the aquifer pressure, but the fluctuation is only about 0.4 MPa, which does not affect the safety of the carbon sequestration process.

Comparing dissolved and mineralized capture, it can be found that the amount of dissolved CO2 is significantly higher over a shorter period. This is because dissolved capture is a physical process with a relatively fast response speed. Compared to others, mineralized capture is a complex chemical process involving multiple steps of solid–liquid–gas three-phase, which involves three steps: CO2 dissolution, mineral dissolution, and carbonate precipitation. Among them, the mineral dissolution rate is relatively slow, which limits the rate of the mineralized capture. From the graph, it can also be observed that as the energy-storage cycle progresses, the amount of mineralized CO2 gradually increases. Therefore, a longer energy-storage period will increase the mineralization rate.

The introduction of energy storage cycles can improve the dissolution of CO2, but the injection and extraction of the gas require additional costs. Therefore, it is necessary to conduct an economic analysis on the system. As shown in Table , the economic assessment results of the system indicate that the initial investment cost of the system is 167.29 million CNY, the net present value is 19.26 million CNY, and the payback period is 26.26 years. It can be found that the introduction of compressed CO2 energy storage can achieve profitability through peak electricity sales, achieve cost recovery within the system life cycle, and achieve a profit of 19.26 million CNY. By comparison, it can be observed that the PI of the system is greater than 1, and its IRR is also greater than the discount rate (6.6%), indicating that the system has the ability to generate profits throughout its life cycle. Therefore, it is economically feasible to accelerate the speed of geological carbon sequestration by increasing the number of energy storage systems. By comparing the levelized cost of electricity of different technologies, it can be found in Table that the LCOE of this study is similar to the CAES in porous rocks, only 0.69 CNY/kWh, which is much lower than that of batteries, PHS, and offshore CAES in saline aquifers technologies.

4Economic Assessment Resultsparametersvalueparametersvaluecompressor cost C comp 52.92 million CNYexpansion turbine cost C exp 19.96 million CNYdeep-well pump cost C pump 4.99 million CNYdrilling cost C well 74.15 million CNYsystem initial investment cost C system 167.29 million CNYlevelized cost of electricity0.69 CNY/kWhprofitability index1.115internal rate of return8.43%net present value19.26 million CNYpayback period26.26 a

Economic Assessment Results

5LCOE of Different Energy Storage Technologies technologyLCOEtechnologyLCOEbatteries (NiCd)3.66 CNY/kWhPHS1.35 CNY/kWhgeneric underground CAES1.05 CNY/kWhoffshore CAES in saline aquifers10.02 CNY/kWhonshore CAES in porous rocks0.68 CNY/kWhCCESA in basalt formations0.69 CNY/kWh

LCOE of Different Energy Storage Technologies

Based on this, we focused on analyzing the impact of different types of basalt on the energy storage efficiency and carbon sequestration and conducted an analysis on the impact of the physical properties and injection parameters of the aquifer. As shown in Figure a, the energy efficiency of the system gradually increases with the level of CO2 cycling. It can be easily observed that energy efficiency rapidly improves in the early stages of the cycle but gradually slows down as it progresses. During the initial cycle, some of the injected heat was not fully recovered, resulting in a decrease in the efficiency. However, the progressive thermal accumulation in the reservoir improves the thermal conditions, thereby enhancing the energy recovery efficiency in subsequent cycles. By comparison, it can also be found that as the porosity increases, the energy efficiency of the system gradually increases but the growth trend gradually decreases. This is because, as the porosity increases, more gas accumulates near the wellbore, forming a high-temperature zone, as shown in the red zone in Figure . The high-temperature zone near the injection well reduces the energy dissipation during energy storage. Comparing different basalt formations, it can be found that the mineralized activity of basalt has a relatively small impact on the energy efficiency. It can also be observed from Figure that the temperature difference is relatively small.

Energy efficiency varies with energy storage cycle (a) under different porosities. (b) Under different permeabilities. (c) Under different injection velocity.

Aquifer temperature comparison with different basalts under different porosities (a) formation 1. (b) Formation 2. (c) Formation 3.

The permeability of the reservoir affects the gas migration in the aquifer after injection, which, to some extent, affects the energy storage capacity of CO2. Therefore, the energy recovery efficiencies of CO2 under different permeabilities were compared. As shown in Figure b, unlike the effect of porosity on the energy storage efficiency, a smaller permeability is more conducive to energy storage. This is because when the permeability is low, the gas migration distance in the aquifer is relatively small, and a large amount of gas accumulates in the near-wellbore area, as shown in Figure , reducing energy dissipation during gas migration. As the permeability increases, the energy storage efficiency of the system gradually decreases, and the gaps caused by differences in permeability also gradually decrease. This is because only a small portion of the injected gas can be transported to the distant area of the aquifer, so the energy dissipation problem caused by the distance of transportation gradually weakens as the distance from the wellbore increases. It can also be seen from Figure that the gas migration distance of the third formation, mainly composed of olivine, is relatively short and the temperature dissipation is low, resulting in high energy recovery efficiency.

Aquifer temperature comparison with different basalts under different permeabilities (a) formation 1. (b) Formation 2. (c) Formation 3.

The fluid injection and extraction velocity affect the energy flow of the injected fluid, thereby affecting the energy efficiency of the system. As shown in Figure c, the influence of the fluid velocity on energy efficiency is significant. A higher fluid injection velocity is more conducive to the energy storage. When the injection and extraction velocity is 50 kg/s, the energy recovery efficiency of the system is increased by 6.17% to 6.52% compared to 30 kg/s. However, as the injection velocity increases, the energy efficiency gap caused by the difference in the injection velocity gradually decreases. This indicates that excessively high injection/extraction velocity will not bring high returns to the system. From Figure , it can also be seen that as the fluid injection velocity increases, the high-temperature area near the injection well significantly increases, which can reduce energy dissipation during the energy-storage process. Comparing the aquifer temperature of different basalt formations in Figure , it can be found that the temperature difference is relatively small, which also leads to a small difference in the energy recovery efficiency.

Aquifer temperature comparison with different basalts under different injection velocity (a) formation 1. (b) Formation 2. (c) Formation 3.

As shown in Figure a, the porosity has a more significant impact on carbon sequestration. With the increase of the porosity, the dissolution capacity of CO2 significantly increases, while the mineralization capacity gradually decreases. This is because the larger the porosity, the more opportunities for CO2 to come into contact with formation water within the same migration distance. Therefore, the amount of CO2 dissolved at a porosity of 0.4 is about twice that of 0.2. Unlike CO2 dissolution capture, a smaller porosity is more conducive to mineralization capture. This is because the smaller porosity allows more gas to migrate to further areas of the aquifer, increasing the concentration of carbonate ions in the distant formation water, increasing the contact area between carbonate ions and basalt, and promoting the forward mineralization reaction. From Figure , it can also be seen that when the porosity is low, more reactive CO2 migrates to distant areas of the aquifer, increasing the possibility of mineralized sequestration. It can also be seen from Figure that the CO2 activity of the olivine-dominated formation is the highest among the three formations, and more CO2 migrates to distant areas, therefore, its mineralization activity is the best. Comparison shows that when the porosity is 0.4, the CO2 mineralization capture capacity of formation 3 is 1.48 times that of formation 1, while when the porosity is 0.2, the mineralization capture capacity increases to 1.61 times that of formation 1.

Comparison of carbon sequestration capacity (a) under different porosities. (b) Under different permeabilities. (c) Under different injection velocity.

CO2 activity (a) with different basalt aquifers. (b) Under different porosities.

As shown in Figure b, the carbon sequestration performance of basalt aquifers increases with an increase of permeability. This is because as the permeability increases, the distance of CO2 migration becomes further, causing more CO2 to dissolve into the distant formation water, increasing the concentration of carbonate ions in the formation water and promoting the forward progress of mineralization reactions. Compared to the impact of porosity on carbon sequestration, the influence of permeability is more reflected in the CO2 mineralization capacity. The comparison in Figure also illustrates this issue. It can be found that the CO2 activity of formation 3 is the highest, while the formation 1 is the smallest. When the permeability is 500 mD, the CO2 mineralization capture capacity of formation 3 is 1.46 times that of formation 1, while it will increase to 1.58 as the permeability increases to 1500 mD.

CO2 activity (a) with different basalt aquifers. (b) Under different permeabilities.

The injection and extraction processes of gas can cause expansion and contraction of the gas–liquid interface in the aquifer, thereby affecting the carbon sequestration process. From Figure c, it can be observed that the CO2 dissolution sequestration capacity significantly increases at a higher injection flow velocity. This is because the higher injection velocity causes further expansion and contraction of the gas–liquid interface in the aquifer, promoting the dissolution of the CO2. The effect of the injection velocity on the CO2 mineralization sequestration capacity is relatively small. As can be seen from the comparison in Figure , the difference in CO2 activity under different injection velocities is small. This is because, on one hand, the higher injection velocity promotes the dissolution of CO2 and increases the concentration of carbonate ions in the formation water. On the other hand, frequent injection and extraction of CO2-induced gas–liquid interface fluctuations are not conducive to precipitation generation. Comparing the three types of basalt formations, it can be found that the CO2 activity of formation 3 is significantly higher, and its mineralization sequestration performance is the best. After 100 days of the energy storage cycle, the amount of mineralization sequestration is 1.31 times that of formation 1. This value increased to 1.47 times after 200 days of the energy storage cycle.

CO2 activity (a) with different basalt aquifers. (b) Under different injection velocity.

Conclusion

This article constructs different basalt aquifer CO2 energy storage models, explores the impact of basalt formations on energy storage and carbon sequestration, and compares the differences in the system performance under different reservoir properties and gas injection parameters.

The simulation results show that frequent injection and extraction of CO2 significantly improve the carbon sequestration capacity, mainly reflected in CO2 dissolution capture. The economic assessment results indicate that the introduction of energy storage systems can recover investment costs and achieve profitability throughout the system’s lifecycle. Its LCOE is similar to the onshore CAES system in porous rocks, which has advantages compared to batteries, PHS, and offshore CAES in saline aquifers technologies. Therefore, deploying the CCESA-CCS system in basalt formations is feasible and optimizes the carbon sequestration process through the rational utilization of energy storage cycles. The carbon sequestration performance of different types of basalt varies greatly, and the olivine dominated formation (formation 3) has the highest CO2 mineralization activity.

The porosity has a relatively small impact on the energy recovery efficiency, and its impact is mainly reflected in carbon sequestration. As the porosity increases, the CO2 dissolution capacity significantly increases. When the porosity is 0.4, the CO2 dissolution capacity is relatively increased by 75.73% to 98.22% compared to 0.2.

As the permeability increases, the energy recovery efficiency of the system gradually decreases and its impact is greater than that of porosity. In contrast, a higher permeability is more conducive to dissolution and mineralization capture. However, as the distance of gas migration increases, the gas saturation gradually decreases, resulting in a limited impact of permeability on the carbon sequestration performance.

A higher gas injection velocity is beneficial to energy storage. While the energy efficiency at an injection velocity of 50 kg/s has increased by 6.17% to 6.52% compared to 30 kg/s, it puts higher demands on the performance of the pump. The higher fluid velocity also leads to further expansion and contraction of the gas–liquid interface, promoting the dissolution of the CO2. However, the impact of gas injection velocity fluctuations on CO2 mineralization capture can be ignored.