Numerical study on the hydrodynamic and thermodynamic properties of compressed carbon dioxide energy storage in aquifers

Renewable Energy xxx (xxxx) xxx

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Numerical study on the hydrodynamic and thermodynamic properties of compressed carbon dioxide energy storage in aquifers Yi Li a, b, Hao Yu a, Yi Li c, *, Yaning Liu d, Guijin Zhang a, Dong Tang a, Zhongming Jiang a a

School of Hydraulic Engineering, Changsha University of Science and Technology, Changsha, 410114, China Key Laboratory of Dongting Lake Aquatic Eco-Environmental Control and Restoration of Hunan Province, Changsha, 410004, China c Hubei Key Laboratory of Ecological Remediation of River-lakes and Algal Utilization, School of Civil Engineering, Architecture and Environment, Hubei University of Technology, Wuhan, 430068, China d Department of Mathematical and Statistical Sciences, University of Colorado Denver, Denver, CO, 80204, USA b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 20 May 2019 Received in revised form 19 November 2019 Accepted 25 November 2019 Available online xxx

Solving the undesirable intermittence and fluctuation problems of renewable energy production needs complementary energy storage on a large scale. Compressed air energy storage in caverns (CAES-C) has been verified as an effective technique. To further improve the energy storage efficiency and save costs, compressed air energy storage in aquifers (CAES-A) and compressed carbon dioxide energy storage in aquifers (CCES-A) were proposed successively. However, the operation performances of CCES-A, especially the hydrodynamic and thermodynamic properties of its underground components (the wellborereservoir system), are not clear. Here we introduce a coupled wellbore and reservoir model, T2WELLECO2N, initially used for geologic carbon sequestration simulation, for simulating the dynamics of CO2 injection and production through wellbore in both the construction and operation stages of CCES-A. The temperature, pressure, CO2 saturation and transfer, energy efficiency, maximum system cycle times, total stress change induced by CO2 injection in aquifer, and sensitivity analysis of permeability in the wellbore-reservoir system of the designed CCES-A are comprehensively studied. The simulation results show that during the operation stage the CO2 is supercritical and fluctuates in both wellbore and aquifer where the CO2 saturation decreases and CO2 bubble generally moves to the central and lower parts of the target aquifer rather than the outside direction. The system itself effectively alleviates the loss of CO2 mass from the side walls of the aquifer. The fact that the cold CO2 zone in the aquifer can continuously receive energy by heat transfer from the surroundings helps the energy efficiency of the CCES-A system gradually increase, and even reach 1.1. The system cycle times exceed 1000 days when the aquifer permeability is larger than 5.0
1013 m2, indicating that CCES-A needs less time to reconstruct the cushion gas compared with CAES-A and can lower the operating cost accordingly. © 2019 Elsevier Ltd. All rights reserved.

Keywords: Compressed CO2 energy storage Aquifer Energy efficiency Thermodynamic process Numerical study

1. Introduction The use of fossil energy considerably helps the world achieve the miraculous economic growth and technological progress since the Industrial Revolution. However, it also inevitably brings us the problems of huge reduction of natural energy resources and serious environmental pollution. Many countries and companies are putting more efforts into developing renewable energies (wind energy, solar energy, geothermal energy, hydro energy, bioenergy, etc.) to solve energy insufficiency and environmental pollution. As

* Corresponding author. E-mail addresses: [email protected] (Y. Li), [email protected] (Y. Li).

the fastest growing energy sources, wind and solar energies, however, exhibit their undesirable intermittence and fluctuation, which strongly influences the grid safety and stability during power production [1]. As a remedy, the energy storage technology is usually combined with the intermittent renewable energy sources to ensure that the electric energy can be stably supplied to the grid [2]. Compressed air energy storage (CAES) and pumped hydro energy storage have been verified as two effective massive energy storage techniques, while both of these technologies have their own limitations [3]. The pumped hydro energy storage should be built in some specific mountain areas with two reservoirs of different heights to store sufficient water. It not only causes a high

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cost and long-term project construction period, but also requires high-quality engineering geological conditions. There are in general two types of compressed air energy storage. One is built on the ground with one or several steel tanks storing high-pressure compressed air, and the other is built in rock caverns, depleted hydrocarbon reservoirs, or deep aquifers with aquitard(s) upon it [4,5]. The thermodynamic behavior, energy efficiency, economic and exergy analyses of CAES and CAES-C (compressed air energy storage in caverns) have been studied by many researchers [6e10]. However, due to the high cost and relatively high risk of the traditional surficial CAES, which needs a considerable number of steel tanks and occupies too much ground space, some underground caverns or tunnels are built to store the high-pressure compressed air to reduce the risk of explosion [4]. Considering the complexity of the geological conditions of the underground storages, a number of feasibility and operational studies were performed on some representative projects (e.g. Huntorf and McIntosh) [4,11], and on other unsuccessful cases as well [12]. The key factors that decide the success of the cavern/tunnel energy storage are sealing degree, thermodynamic efficiency, and the stability and deformation of the surrounding rock [13e15]. Some unexpected situations (e.g. geological discontinuities) could greatly enhance the construction cost, or even lead to project interruption [12]. In addition, the high costs of cavern excavation and sealing operation also reduce the economic effectiveness, and the number of suitable depleted hydrocarbon reservoirs is limited. Therefore, some experts attempted to use porous aquifers to replace steel tanks and caverns/tunnels to store compressed air [16]. The porous media compressed air energy storage (PM-CAES) uses a vertical well to inject/extract compressed air into/out of deep aquifers, so only a relatively impermeable formation (aquitard) upon it is needed [17]. The construction cost of PM-CAES can be clearly reduced, compared with the cavern-based projects. A specific simulator, T2well-EOS3, was developed to verify the feasibility and high effectiveness of this novel energy storage method, and the hydrodynamic and thermodynamic performances, as well as the energy productivity of the wellbore-reservoir system during operation were well studied [18]. Subsequently, carbon dioxide was designed as the injected cushion gas before the cyclic utilization of compressed air to reduce the air mass and pressure dissipation, and further to improve the system cycle times and energy efficiency [19]. Numerical studies showed that the energy efficiency of the wellbore-reservoir compressed air system depends on the permeability, porosity, depth and the temperature of the aquifers, and the importance of these parameters to the compressed air energy storage process in aquifers was also verified and analyzed [20,21]. Increasing the energy storage density to a great extent can lower the cost of power generation in CAES. Since the energy storage density of compressed CO2 is far greater than that of the air, using CO2 as the working fluid can strongly improve the energy efficiency and dramatically reduce the required storage volume of the container/reservoir by several or even a dozen times, as has been verified by previous studies [22,23]. As mentioned above, CAES can be applied in some specific aquifers, and at the same time, large scale geological carbon dioxide sequestration (GCS) has been widely promoted to reduce global warming [24]. Considering the merits of these two advanced techniques (CAES and GCS), researchers proposed a new energy storage conception, compressed carbon dioxide energy storage in aquifers (CCES-A), to further improve the round-trip energy efficiency and reduce costs [25,26]. The thermodynamic analyses of both compressed supercritical and transcritical CO2 energy storages in such a system, which only focus on the energy loss between the surficial power plant and the underground aquifer system, have been conducted using theoretical exergy analysis models [25,26]. However, the energy efficiency, and

hydrodynamic and thermodynamic behavior of the aquiferwellbore system (the underground part of CCES-A) have not been particularly studied so far. This paper is the first to use numerical methods to reveal the complete picture of the hydrodynamic and thermodynamic properties of compressed carbon dioxide energy storage in aquifers. In this system, the parameters of energy storage and production are designed similar to those in the Huntorf power station (a cavernbased compressed air energy storage) [4]. The initial CO2 bubble generation, periodic variations of pressure and temperature during the CO2 injection and production, energy efficiency of the wellborereservoir system, effective system cycle times, total injection/ production-induced stress change, and the effects of permeability on the system are comprehensively studied. Some interesting and surprising phenomena are found in this system, whose operation performance is far superior to those in both cavern-based and aquifer-based compressed air energy storages. 2. Methods 2.1. Concept model of CCES-A The CCES-A system has ground and underground parts. In this study, we focus on the underground part, while the above-ground part (for power generation and CO2 compression) is similar to that in CCES or CAES/CAES-A [16,25]. The concept model of the underground part of CCES-A is shown in Fig. 1. Similar to the compressed air energy storage in aquifer, the compressed CO2 energy storage in aquifer also uses an injection/production well extending from ground surface into deep aquifer to perform energy and mass storage. Above and below the target aquifer, two relatively

Fig. 1. The concept model of CCES-A.

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impermeable aquitards exist to prevent mass and heat losses.

Fk ¼  l 2.2. Basic theory of CCES-A The basic mass and energy balance equation of the multiphase multi-component flow in the wellbore-reservoir system can be expressed as [27e29].

d dt

ð

M k dVn ¼

ð

Fk $ndGn þ

Gn

Vn

ð

qk dVn

(1)

Vn

The integration is over an arbitrary subdomain Vn of the flow system under study, which is bounded by the closed surface Gn. The quantity M appearing in the accumulation term (left hand side) represents mass or energy per volume, with k ¼ 1, …, NK labeling the mass components (water, CO2, solutes, …), and k ¼ NKþ1 the heat component. F denotes mass or heat flux, q denotes sinks and sources and n is a normal vector on surface element dGn, pointing inward into Vn. The general form of the mass accumulation term is

X Sb rb X kb

Mk ¼ 4

(2)

Fk ¼

X X kb rb ub

(3)

   u2b vT 1 X v  Аrb Sb ub hb þ þ gz cos q  q’ vz A vz 2

(7)

b

where Fk is the mass or energy transport term along the borehole due to advective processes, with superscript k representing the index for the components: k ¼ 1 (H2O), 2 (CO2), and 3 (energy, taken as internal and kinetic energy here), l here is the areaaveraged thermal conductivity of the wellbore (both phases of the fluids and possible solid portion), z is the along-wellbore coordinate, A is the well cross section, ub is the average velocity vector of phase b within the wellbore, q is the incline angle of the wellbore, and q’ is the heat loss/gain per unit length of the wellbore. Energy accumulation in wellbore can be expressed as:

Mk ¼

X b



rb Sb Ub þ

u2b 2

 þ gz cos q

(8)

where Mk is the accumulation term of the component k. Phase velocity in wellbore can be expressed as:

uG ¼ C0

b

where the total mass of component k is obtained by summing over the fluid phases b (¼ liquid, gas, NAPL). 4 is the porosity (¼1 in wellbore), Sb is the saturation of phase b, rb is the density of phase b, and X kb is the mass fraction of component k present in phase b (b ¼ G for gas; b ¼ L for liquid). Advective mass flux is a sum over phases

3

uL ¼

rm r um þ *L ud r*m rm

ð1  SG C0 Þrm SG rG um  ud * ð1  SG Þrm ð1  SG Þr*m

(9)

where uG is the gas velocity, C0 is the profile parameter to account for the effect of local gas saturation and velocity profiles over the pipe cross-section, rm is the density of the gas-liquid mixture, r*m is the profile-adjusted average density, um is the mixture velocity (velocity of mass center), ud is the drift velocity of gas, and uL is the liquid velocity.

b

2.3. Modeling methods

where ub is the velocity (volume flux) in phase b. Energy flux in the rock can be expressed as

X Fk ¼  lVT þ hb rb ub

(4)

b

where l is the thermal conductivity of the rock, T is the temperature, and hb is the specific enthalpy in phase b. Energy accumulation in the rock can be expressed as

M kþ1 ¼ ð1  fÞrR CR T þ f

X b

rb Sb Ub

(5)

where f is the porosity of the rock, rR and CR are the grain density and specific heat of the rock respectively, and Ub is the specific internal energy in phase b. Phase velocity in the rock can be expressed as

ub ¼  k

krb

mb

ðVPb  rb gÞ

(6)

where k is the absolute permeability, krb is the relative permeability to phase b, mb is the viscosity, Pb is the fluid pressure in phase b, and g is the gravitational acceleration. Transport along the wellbore is governed in general by the processes of advection, diffusion and dispersion, and is also subject to other processes such as the exchange with the formation at feed or thief zones. The total advective mass transport term for component k can be written in one-dimension as

2.3.1. T2Well/ECO2N simulator In this study, the T2well/ECO2N simulator was used to simulate the multi-component (CO2-water or CO2-water-NaCl) multiphase flows and their thermodynamic behavior in wellbore and formations. The reliability of the ECO2N module for describing the thermodynamic properties of CO2 at high pressure and supercritical condition has been verified by many studies [30e36]. T2well/ ECO2N was developed from TOUGH2-ECO2N, in which TOUGH2 is a numerical simulator for non-isothermal flows of multicomponent, multiphase fluids in three-dimensional porous and fractured media, and ECO2N is a fluid property module for the TOUGH2 simulator designed for applications in geologic sequestration of CO2 in saline aquifers and enhanced geothermal reservoirs. To further accurately simulate the dynamics of CO2 injection and leakage through wellbores, which is not well dealt with by the TOUGH2-ECO2N simulator, Pan et al. (2014) developed a coupled wellbore and reservoir model (T2well/ECO2N) [29]. This simulator integrates a wellbore-reservoir system by assigning the wellbore and reservoir to two different sub-domains in which flows are controlled by appropriate physical laws. In the reservoir, the flow process is described by a standard multiphase Darcy flow approach. In the wellbores, the Drift-Flux model and related conservation equations are used to describe transient two-phase non-isothermal wellbore flow of CO2-water mixtures. The mass and thermal energy balance equations are solved numerically by a finite difference scheme with the wellbore heat transmission to the surrounding rock handled either semi-analytically or numerically. The momentum balance equation for the flow in the wellbore is solved

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numerically with a semi-explicit scheme. 2.3.2. Numerical model To study the hydrodynamic and thermodynamic properties of the CCES-A system, a symmetric mesh is established (see Fig. 2), in which the target aquifer is located 1600 m deep with a thickness of 150 m, and the relatively impermeable overlaying and underlying layers are both 100 m thick. The diameter of the operation well is 0.53 m, the same size as that in the Huntorf CAES plant. The wellbore is located in the center of the horizontal profile, and the length and width of the profile are both 200 m, as shown in Fig. 2(a). Since the CO2 under the production design (will be given in section 2.3.3) transports no more than 100 m away from the wellbore within 400 days based on trial calculation, the range of such a profile is designed to reduce the computational cost. The wellbore bottom is at 1690 m (see Fig. 2(b)). The permeability and porosity of the sand aquifer are 1.0
1012 m2 and 0.3, respectively. All layers are flatlying and isotropic. As seen in Fig. 2, the total number of grid nodes is 19860. The grid around the wellbore is refined to enhance the accuracy, while the grid of the outer region is gradually coarsened to save computational cost. 2.3.3. Production design Before the daily cycle operation, a large amount of CO2 (with a rate of 10 kg/s for 100 days) is injected to form a cushion zone around the wellbore in the target aquifer. After that, the daily cycle operation can be performed. The daily cycle operation is similar to that for the Huntorf plant, but the same total injection and production are assumed for convenient analysis based on the previous studies [4,16,21]. The detailed daily cycle operation involves 4 stages: first, the compressed CO2 is injected with a rate of 54 kg/s for 12 h, followed by a 4.5 h shut-in; then the CO2 is produced with a rate of 216 kg/s for 3 h for electricity generation, followed by another 4.5 h shut-in. The CO2 flow rates of injection and production of a daily cycle operation are shown in Fig. 3. The consumed CO2 in the designed CCES-A system, consisting of 86,400 tons for cushion bubble and 2332 tons for daily recyclable circulation operation, can be easily obtained from nearby coal-fired plants. As for the first carbon capture and storage (CCS) project in China, the Shenhua Ordos CCS project, the cumulative mass of the injected CO2 reached 300,000 tons in December 2015, and the CO2 was

Fig. 3. The CO2 flow rates of injection and production of a daily cycle operation.

captured directly from coal liquefaction plants nearby [24]. The large amount of CO2 consumed can also alleviate global warming. The recyclable daily-used CO2 can be temporarily stored in ground chambers or shallow aquifers (designed as the two saline-aquifer reservoirs by Liu et al. (2016)) [25], which will be studied in the future.

2.3.4. Initial and boundary conditions The initial conditions of the simulation are as follows: the initial water saturation is 1.0 in all grid cells; the water pressure is 0.1 MPa (standard atmospheric pressure) at ground surface and is distributed with the hydrostatic pressure gradient below the ground; the temperature is 15  C at ground surface and increases with the gradient of 30  C/km. The lateral boundaries of the model are set to allow fluids (water and CO2) to flow in and out freely. The top and bottom boundaries are set to be closed so that no fluid or heat

Fig. 2. The grid of the numerical model: (a) horizontal profile, (b) vertical profile.

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Y. Li et al. / Renewable Energy xxx (xxxx) xxx Table 1 Parameters used in this study. Parameters

Values Aquifers

Rock grain density Thickness Permeability Porosity Pore compressibility Thermal conductivity Rock grain specific heat Relative permeability model Capillary pressure model index l of VG Model Residual liquid saturation Residual gas saturation Entry pressure Maximal capillary pressure

Units Aquitards

2600 2600 150 100 12 1.0
10 2.0
1018 0.3 0.01 4.5
1010 5.0
1010 2.51 2.51 920 920 van Genuchten-Mualem model van Genuchten function 0.60 0.457 0.05 0.3 0.05 0.00 0.2 19.61 64 10

kg/m3 m m2 Pa1 W/(m$ C) J/(kg$ C)

KPa MPa

transfers through them. The wellbore sidewall attached to aquitards 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. The wellhead is the position where CO2 is injected and produced, and the specific entropy of the injected CO2 is fixed as a constant. The parameters of all layers used in the numerical simulation are listed in Table 1. The proposed model was simulated by T2WELL/ECO2N (a standalone version) using a desktop computer with an Intel Core i7 8700k processor and 16 GB DDR4 memory. Under the conditions considered for the model including the designed mesh, initial and boundary conditions and the cyclic scheme, the computation times of CO2 bubble formation and cyclic operation were about 12 h and 24 h, respectively. 3. Results and discussion 3.1. Hydrodynamic and thermodynamic properties 3.1.1. Initial CO2 bubble Fig. 4 shows the saturation of the CO2 after 100 days of injection.

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The in-situ water is driven away from the wellbore by CO2, and the zone around the wellbore is nearly saturated with CO2, leaving only a small amount of residual water (less than 5%) in the rocks. With the CO2 bubble spreading away for about 90 m, the CO2 saturation decreases. Since the density of CO2 (supercritical here) is lower than that of the water and the initial water pressure increases with depth, the CO2 bubble exhibits an inverted triangle distribution in the upper part of the aquifer. The lower part of the aquifer is still saturated with water. 3.1.2. Hydrodynamic properties of the system 3.1.2.1. Wellhead pressure. Fig. 5(a)-(f) show the cyclic change in the wellhead pressure in 300 days of operation. The wellhead pressure fluctuates with the daily operations (see Fig. 5(a)e(e)). In a 24-h daily operation, because of the large amount of CO2 injected from the wellhead during the 12-h injection stage, the wellhead pressure first rises rapidly and then remains at a high level. The relative permeability of the aquifer increases slowly if the increment of the capillary does not reach its entry pressure. Then the pressure declines quickly and remains at a normal level within the first 4.5-h shut-in stage. After that, it dramatically drops to the lowest level with the 3-h CO2 production for power generation, followed by a climbing back within the second 4.5-h shut-in stage before another cycle (see Fig. 5(f)). During this period the highest pressure of each day slowly increases from 15.3 to 15.7 MPa, while the lowest pressure of each day first drops from 14.2 to 12.6 MPa and then climbs up slightly to 12.7 MPa. The reason is that the temperature of the injected compressed CO2 is relatively cooler than that of the target aquifer and its surroundings, and the heat may continuously flow into the CO2 bubble. 3.1.2.2. Target aquifer pressure. Fig. 6(a)-(h) show the pressure distributions of the target aquifer after injection and production on the 1st, 100th, 200th, and 300th days, respectively. In the injection stage, pressure build-up concentrates around the wellbore as a result of the large amount of CO2 injection, and the flotage resulting from the density difference between supercritical CO2 and water makes the pressure distribution in the aquifer spike-shaped. The upper part of the aquifer is a relatively high-pressure zone. In the production stage, since the CO2 is produced from the aquifer

Fig. 4. Saturation of the initial CO2 bubble in the target aquifer.

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Fig. 5. The change in the wellhead pressure with daily operations: (a) 0e20 d, (b) 80e100 d, (c) 100e120 d, (d) 200e220 d, (e) 280e300 d, (f) the 300th day.

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Fig. 6. Pressure distributions of the target aquifer during the operation: (a) after injection (the 1st day), (b) after production (the 1st day), (c) after injection (the 100th day), (d) after production (the 100th day), (e) after injection (the 200th day), (f) after production (the 200th day), (g) after injection (the 300th day), (h) after production (the 300th day).

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Fig. 7. The change in the wellhead temperature during the operation: (a) 0e20 d, (b) 80e100 d, (c) 100e120 d, (d) 200e220 d, (e) 280e300 d, (f) the 300th day.

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Fig. 8. Temperature distributions of the target aquifer during the operation (unit:  C): (a) after injection (the 1st day), (b) after production (the 1st day), (c) after injection (the 100th day), (d) after production (at 100th day), (e) after injection (the 200th day), (f) after production (the 200th day), (g) after injection (the 300th day), (h) after production (the 300th day).

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through the wellbore, the pressure around the wellbore drops. The high-pressure and high-concentration CO2 in the upper part of the aquifer tends to move out, which leads to an inverted spike shape for the pressure distribution after production. At this time, the upper part of the aquifer turns into a relatively low-pressure zone. 3.1.3. Thermal properties of the system 3.1.3.1. Wellhead temperature. Fig. 7(a)-(f) show the cyclic change in the wellhead temperature in 300 days of operation. The wellhead temperature varies with the wellhead daily operations (see Figs. 7(a)e(e)). In a 24-h daily operation, with the large amount of cold compressed CO2 injected into the wellbore in the 12-h injection stage, the wellhead temperature drops quickly and then stabilizes at a low level. What follows in the first 4.5-h shut-in stage is another decline resulting from the shut-down of the transient injection pressure (mainly because of the change in the CO2 thermodynamic property, i.e. the PVT properties of CO2) and the subsequent increase due to environmental heating (See Fig. 7(f)). After that, it dramatically drops to the lowest level (also caused by the change in the CO2 thermodynamic property) and then rises within the 3-h CO2 production, followed by a surging to the highest level and then a small-scale drop within the second 4.5-h shut-in

stage before another cycle. Compared with the pressure change at the wellhead, the temperature change shows the same pattern but a more complex tendency, due to the fact that the CO2 thermodynamic properties are very sensitive right after opening and closing of the wellhead. During this period, the lowest temperature of each day first drops from 43.5  C to 43  C, while the highest slowly increases from 46.3  C to 47.2  C, for the reason that the temperature of the injected compressed CO2 is relatively cooler than that of the target aquifer and its outside environment, and the heat can continuously flow into the CO2 bubble system. 3.1.3.2. Target aquifer temperature. Fig. 8(a)-(h) exhibit the temperature distributions of the target aquifer after injection and production on the 1st, 100th, 200th, and 300th days, respectively. When the cold supercritical CO2 is injected into the aquifer, the temperature around the wellbore in the upper part of the aquifer drops quickly, and when CO2 is produced, it starts to rise. An interesting observation is that the temperature around the bottom hole is higher than the two sides and it continuously increases. A possible explanation is that the cold CO2 zone tends to accumulate in the upper part of the aquifer and the thermal gradient in the whole aquifer increases; therefore the heat transformation and

Fig. 9. The CO2 saturation on the 1st day: (a) after injection, (b) after the first shut-in, (c) after production, (d) after the second shut-in.

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convection among the cold area, the area around the bottom hole and the lower part are enhanced. 3.1.4. CO2 saturation The functions of forming the initial CO2 bubble in the target aquifer are to displace the innate water, to maintain relatively high operation pressure, and to ensure a sufficient amount of CO2 mass for production during the daily operation. The CO2 transportation far away from the wellbore is a significant factor that needs to be considered. Figs. 9 and 10 demonstrate the CO2 saturations on the 1st and 300th days during the operation. The region of variation of the CO2 saturation on the 1st day is mainly around the wellbore, and the range of variation of the concentration is relatively small before and after the production, because the CO2 bubble just accumulates in the upper part of the aquifer and the pressure and saturation of the CO2 around the wellbore are relatively large. The relative permeability of the aquifer far away from the wellbore is lower than the high CO2 saturation area around the wellbore, and the CO2 therefore tends to move to the central and lower parts of the aquifer rather than the outside direction from the 1st to the 300th day, which is beneficial to the system safety. However, the CO2 saturation around the wellbore decreases from close to 1 to

11

0.45 after 300 days. If the CO2 saturation further decreased to a lower level with the operation proceeding, there could be no sufficient CO2 cushion to support the pressure and avoid water production. Additional CO2 needs to be injected to reconstruct the CO2 bubble or the rate of injection needs to be adjusted so that it is larger than the production rate. The loss of cushion mass is an important problem in both CAES-A and CCES-A, but the advantage of CCES-A is that the loss of CO2 can help achieve the goal of CO2 storage. 3.2. Energy efficiency Fig. 11 displays the energy flow rates at the wellhead during the operation. When energy flows into the system, the rate is positive; otherwise it is negative. The change in energy flow rate is consistent with the daily operations. In the first 12-h injection, it remains a constant value, because of the constant injection rate and temperature. When the wellhead is shut in, the energy flow rate drops to zero. During the production period, the absolute value of the energy flow rate slowly decreases with the pressure decreasing around the wellbore. The energy efficiency of the wellbore and reservoir system is a

Fig. 10. The CO2 saturation on the 300th day: (a) after injection, (b) after the first shut-in, (c) after production, (d) after the second shut-in.

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Fig. 11. Energy flow rates at the wellhead, (a) 0e10 d, (b) 290e300 d, (c) the 1st day, (d) the 300th day.

Fig. 12. Energy efficiency of the system: (a) 0-10d, (b) 0-300d.

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Fig. 13. Impacts of the aquifer parameters and wellbore screen length on the energy efficiency: (a) aquifer depth, (b) aquifer thickness, (c) aquifer porosity, (d) aquifer permeability, and (e) wellbore screen length.

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main concern for the CCES-A system. It can be defined as the ratio of the energy produced to the energy injected through the wellhead in one cycle ignoring the ground system [20]:

. Eefficiency ¼ Eproduction Einjection

(10)

Fig. 12 presents the energy efficiency during the first 10 days and the whole 300 days of operation. As shown in Fig. 12(a), the energy efficiency is about 0.978 on the first day and it continuously increases as the operation proceeds. The energy efficiency of CCES-A exceeds 1 only after 10 cycles, and reaches around 1.1 in about 300 days (Fig. 12(b)). The behavior is significantly different compared to CAES-A, in which the energy efficiency begins only at 0.95 and increases to no more than 1.03 in about 300 days [17,20]. The reason is that the injected CO2 is colder than the aquifer and the heat can transfer from the surroundings to the CO2 zone with the operation continuing. It can be inferred that the geothermal energy is extracted with the CO2 and it may be more obvious in CCES-A than in CAES-A due to the larger heat capacity and colder temperature of the supercritical CO2. Previous study showed that the parameters of aquifers and wellbore have strong impacts on the compressed air energy storage system [17]. We investigated the aquifer depth, thickness, porosity, permeability, and wellbore screen length through sensitivity analysis to study their impacts on the energy efficiency (Fig. 13). The result in Fig. 13(a) shows that the energy efficiency increases with increased aquifer depth, due to the higher surrounding temperature. The thicknesses of 60, 90, 120 and 150 m are considered to study the impact of aquifer thickness on the energy efficiency. Fig. 13(b) shows that at the beginning, the energy efficiency in the 60 m case is the highest, while it drops with the operation cycle proceeding. CO2 in the thin aquifer transports farther away from the wellbore, and the longer wellbore in the thicker aquifer can accumulate more CO2 mass around it. The energy efficiencies of the 90, 120 and 150 m cases increase all the time, and the 90 m case provides the best performance. Fig. 13(c) shows that in general the

larger the porosity is, the higher the energy efficiency becomes. It can be explained by the fact that the smaller CO2 plume with larger porosity can decrease the losses of effective gas and pressure and result in the higher energy efficiency. Fig. 13(d) indicates that the permeability has optimal values of 1.0
1012 m2 and 1.0
1013 m2 in the designed scheme. Higher permeability can increase the losses of gas and pressure, and lower permeability can decrease the deliverability. Fig. 13(e) shows the impact of wellbore screen length on the system energy efficiency. The case where the bottom hole is located in the middle of the aquifer (wellbore screen length equals to 90 m) has a better performance. 3.3. System cycle times In the cycle process, if there is not another CO2 injection to restore the cushion gas bubble, an insufficient amount of CO2 production and outlet pressure will occur owing to CO2 spreading away from the wellbore. System cycle times (SCT) is defined as the sustainable times with a given CO2 bubble. Aquifer permeability has a strong influence on the performance of CCES-A including energy efficiency (as mentioned in Section 3.2), SCT, stress, hydrodynamic and thermodynamic properties (to be discussed in Sections 3.4 and 3.5). In this section, we design five cases to discuss the impact of permeability on SCT. The different permeabilities and SCT of five cases are listed in Table 2. When the permeability is larger than 5.0
1013 m2, the SCT can achieve more than 1000. However, if the permeability is relatively small (e.g. smaller than 1.0
1013 m2), the SCT drops to below 100. The results show that a threshold value of permeability exists for SCT in CCES-A and the value can guide the site selection. To investigate the cause of the small SCT associated with lower permeabilities (1.0
1013, 5.0
1014), the pressure distributions at the end of cycle with lower permeabilities are presented in Fig. 14. When the aquifer pressure around the wellbore decreases to about 9.0 MPa, the relatively low fluid pore pressure cannot drive the CO2 out as needed by the production (216 kg/s), and therefore

Table 2 System cycle times of the operation with different permeabilities. Permeability of the target aquifer (m2) SCT

5.0
1012 >1000

1.0
1012 >1000

5.0
1013 >1000

1.0
1013 91

5.0
1014 60

Fig. 14. The pressure distributions at the end of cycle with different permeabilities: (a) k ¼ 1.0
1013 m2, (b) k ¼ 5.0
1014 m2.

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Fig. 15. Total stress increments in the aquifer on the 50th day: (a) injection, k ¼ 1.0
1012 m2, (b) production, k ¼ 1.0
1012 m2, (c) injection, k ¼ 1.0
1013 m2, (d) production, k ¼ 1.0
1013 m2, (e) injection, k ¼ 5.0
1014 m2, (f) production, k ¼ 5.0
1014 m2.

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Fig. 16. Variations of the wellhead pressure and temperature within 50 cycles: (a) pressure, k ¼ 1.0
1012 m2, (b) temperature, k ¼ 1.0
1012 m2, (c) pressure, k ¼ 1.0
1013 m2, (d) temperature, k ¼ 1.0
1013 m2, (e) pressure, k ¼ 5.0
1014 m2, (f) temperature, k ¼ 5.0
1014 m2.

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Fig. 17. Aquifer pressures on the 50th day: (a) injection, k ¼ 1.0
1012 m2, (b) production, k ¼ 1.0
1012 m2, (c) injection, k ¼ 1.0
1013 m2, (d) production, k ¼ 1.0
1013 m2, (e) injection, k ¼ 5.0
1014 m2, (f) production, k ¼ 5.0
1014 m2.

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Fig. 18. Aquifer temperatures on the 50th day (unit:  C): (a) injection, k ¼ 1.0
1012 m2, (b) production, k ¼ 1.0
1012 m2, (c) injection, k ¼ 1.0
1013 m2, (d) production, k ¼ 1.0
1013 m2, (e) injection, k ¼ 5.0
1014 m2, (f) production, k ¼ 5.0
1014 m2.

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Table 3 Comparison of CAES-A and CCES-A with the same mesh and parameters. Characteristics

CCES-A

CAES-A

Units

Diffusion range of initial bubble Wellhead pressure range of daily circulation Wellhead temperature range of daily circulation Aquifer pressure range of daily circulation Aquifer temperature range of daily circulation Diffusion range after 200 days Round-trip energy efficiency

~85.0 13.63e15.50 36.61e44.18 14.65e17.34 37.60e56.96 ~165.0 95%e105%

~220.0 14.63e16.52 53.95e63.26 15.24e17.34 49.95e63 ~597.0 80%e90%

m MPa  C MPa  C m /

the cycle terminates. 3.4. Total stress change In many geological carbon dioxide storage projects, the large amount of cold CO2 injected into the aquifer can induce formation fracturing [24], which mainly results from increased injection pressure and increased thermal stress due to rapidly dropping temperature. The total stress increment should also be investigated in a CCES-A system. The total stress increment Ds can be expressed as the sum of injection pressure and the cooling-induced thermal stress:

Ds ¼ DPþbEDT/(1-2n)

(11)

in which DP is the pressure increase, 3b is the (volumetric) thermal expansion coefficient, DT is the temperature increase, E is the Young’s modulus, and n is the Poisson’s ratio. Fig. 15 presents the total stress increments in the target aquifer with different permeabilities (1.0
1012, 1.0
1013, 5.0
1014 m2). The total stress increment around the wellbore is larger than that in the region far away from the wellbore, because the fluid pressure and temperature decrease with the increasing distance to the wellbore. The aquifer with a lower permeability has a higher total stress increment, because it is relatively more difficult for the fluid to dissipate. The maximum total stress change reaches about 17.0 MPa, and excessive stress change may lead to rock fracturing. In particular, the rock fracturing that occurs near the caprock may damage the sealing performance of the system and lead to CO2 leakage. Therefore, the flow rate and injection temperature at the wellhead should be controlled during the operation. 3.5. Impact of permeability on hydrodynamic and thermodynamic properties As illustrated in Section 3.3, aquifer permeability has a strong influence on SCT. It can also influence the hydrodynamic and thermodynamic properties of a wellbore-reservoir system, and further affect the site selection of CCES-A. Therefore, a sensitivity analysis of permeability is conducted to study its influence on pressure and temperature in both the wellbore and reservoir. The variations of the wellhead pressure and temperature with different permeabilities (1.0
1012, 1.0
1013, 5.0
1014 m2) during 50 days of operation are shown in Figs. 16(a)e(f). The aquifer with a higher permeability (1.0
1012 m2) has lower wellhead pressure fluctuation ranges (14.2e15.4 MPa in the first cycle and 12.9e15.6 MPa in the last cycle) and lower wellhead temperature fluctuation ranges (43.5e46.2  C in the first cycle and 43e46.7  C in the last cycle). On the contrary, the aquifer with a lower permeability (5.0
1014 m2) has higher wellhead pressure fluctuation ranges (9e17.5 MPa in the first cycle and 7.7e17.9 MPa in the last cycle) and higher wellhead temperature fluctuation ranges (36.4e48  C in the first cycle and 31.7e47.4  C in the last

cycle). The large pressure and temperature variations in the wellbore cannot rapidly spread through the low permeability aquifer, in which case the energy storage operation cannot proceed for long. Figs. 17 and 18 show the pressure and temperature distributions of the target aquifer with different permeabilities on the 50th day. It can be inferred that the low permeability case limits the CO2 flow in the aquifer, and a higher injection pressure and lower production pressure have to be adopted to achieve the desirable CO2 rate. The pressure change can strongly impact the temperature variation based on the gas thermodynamic law. While the permeability is large, the enhanced CO2 flow reduces the pressure and temperature variations. The large amount of cold CO2 injected can lead to high pressure build-up in a low permeability aquifer, and can further cause the caprock and target aquifer to crack, leading to undesirable results for the stability of CCES-A. As a result, choosing an aquifer with a suitable permeability is a decisive factor for the CCES-A site selection. 4. Discussion From the simulation results, some advantages of CCES-A over CAES-A have been found, and the most impressive one is the system cycle times. In some cases (i.e. the permeability is larger than 5.0
1013 m2), the system cycle times can be more than 1000 days (or further exceeding 3 years) [17]. It indicates that CCES-A needs less time to reconstruct the cushion gas compared with CAES-A, and eventually reduces the operating cost. Considering that the energy of some renewable resources (e.g. solar energy and hydro power) is usually seasonal, there is an urgent need for the interseasonal energy storage to be developed to further deal with the inter-seasonal fluctuations in electricity production and meet the demands in regional or national energy [5]. In addition, the storage volume needed in CCES-A is much smaller than that in the compressed air energy storage, because the energy storage density of supercritical CO2 is larger than that of the air. To further assess the performance of CCES-A, a comparative study between CCES-A and CAES-A was conducted. The aquifer and wellbore parameters are the same as those in the previous study in this paper. The only difference is that the horizontal range of the mesh in the comparative study is 3000
3000 m, because the air transport range is farther than that of the CO2. The initial bubble diffusion range, wellhead pressure and temperature, aquifer pressure and temperature, the gas diffusion range after 200 days, and the energy efficiency are listed in Table 3. The diffusion range of the working fluid in CCES-A is less than that of the CAES-A, not only when the initial bubble just forms, but also after 200 days of operation, and it is verified again that CCES-A needs less space to store the compressed fluid. The working fluid temperature of CCES-A is lower than the environment, while that of the CAES-A is higher than the environment. The round-trip energy efficiency of the CCES-A is higher than that of the CAES-A. These two merits of CCES-A render the inter-seasonal CCES-A technique with a large number of wells and suitable producing rates a preferable choice.

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Due to the difficulty to find an ideal geological condition with a natural low-permeability structure for the CO2 cushion, researchers developed an artificial low-permeability barrier for the CASE-A system to further improve the airtightness and maintain a high operation pressure of the storage [20]. A specific grout should be injected through the wellbore before CO2 to form the barrier. This technique can also be used in a CCES-A system, and we will study the influence of the barrier to improve the performance (especially the energy efficiency, circulation and stress) of the CCES-A system in the future. Another area for further study involves the long-time chemical reactions. The salinity of the aquifer is not considered in this work. Considering the aquifers in many areas of the world are saline aquifers and CO2 can react with saline water and rock matrix found in many CCS sites, the mechanism will be studied to reveal how the products of reaction alter the permeability of the aquifer or wellbore perforation structures, and further change the performance of the whole CCES-A system. 5. Conclusions This work focuses on the newly developed compressed carbon dioxide energy storage in aquifers (CCES-A). For the first time, the hydrodynamic and thermodynamic properties, energy efficiency, circulation, stress change of the CCES-A system are studied comprehensively through numerical simulation. In the simulation, 8640 tons of CO2 (with a rate of 10 kg/s for 100 days) was injected before the cycle operation to form the CO2 bubble to displace innate water, and to ensure the relatively high operation pressure and sufficient CO2 mass for production. In the daily operation, CO2 was injected with the rate of 54 kg/s for 12 h and released with the rate of 216 kg/s for energy generation for 3 h, each followed by a 4.5-h shut-in. In the 300-day simulation, the temperatures and pressures in both the wellbore and the aquifer varied periodically with the operation proceeding. The lowest temperature and pressure of the wellbore-aquifer system were about 43  C and 13 MPa, respectively. Therefore, the CO2 during the operation was at supercritical state, with a high fluidity and energy storage density. Although the CO2 saturation decreased during the operation, benefiting from the density of supercritical CO2 lower than water and the relative permeability of outside parts lower than central and lower parts, the CO2 bubble generally moved to the central and lower parts of the target aquifer rather than the outside direction. The system itself effectively alleviated the CO2 mass loss from the two sides of the aquifer. Due to the floating effect of CO2 and geothermal effects of the surroundings, the cold CO2 zone could continuously receive energy by heat transfer. Therefore, with the operation proceeding, the energy efficiency of the CCES-A system gradually increased, and even reached 1.1. Moreover, the system cycle times exceeded 1000 days when the aquifer permeability was larger than 5.0
1013 m2. These performances of the CCES-A system are better than the compressed air energy storage. Therefore, the wellbore-reservoir system of CCES-A is relatively stable and can reduce the operation cost dramatically. Aquifer permeability is a very important factor for the performance assessment and site selection of CCES-A, and the operation pressure, temperature, energy efficiency, system cycle times and stress change during the operation are all related to aquifer permeability. When the aquifer permeability was lower than 1.0
1013 m2, the system cycle times decreased to only 91 days. Specifically, the 90 m-thick aquifer had the best performance among our designed schemes. With the aquifer permeability decreasing, the stress change induced by the injection of cold CO2 can increase dramatically, which may damage the reservoir

formation and lead to leakage risk and system instability. Such a phenomenon has also been detected in some CCS projects. Author contribution Li Yi (the first author): Conceptualization, Methodology, Software, Writing - Original Draft. Yu Hao: Investigation, Visualization. Li Yi (the corresponding author): Software, Resources, Conceptualization. Liu Yaning: Investigation, Writing - Review & Editing. Zhang Guijin: Formal analysis, Validation. Tang Dong: Formal analysis, Methodology. Jiang Zhongming: Formal analysis. Declaration of competing interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgement The financial supports from the National Natural Science Foundation of China (Nos. 51509022, 51778070) are gratefully acknowledged. The first author would like to thank the financial support from the program of China Scholarship Council (CSC). References [1] D. Elliott, A balancing act for renewables, Nat. Energy 1 (1) (2016) 15003. [2] B. Zakeri, S. Syri, Electrical energy storage systems: a comparative life cycle cost analysis, Renew. Sustain. Energy Rev. 42 (2015) 569e596. [3] M. Budt, D. Wolf, R. Span, J. Yan, A review on compressed air energy storage: basic principles, past milestones and recent developments, Appl. Energy 170 (2016) 250e268. [4] M. Raju, S.K. Khaitan, Modeling and simulation of compressed air storage in caverns: a case study of the Huntorf plant, Appl. Energy 89 (1) (2012) 474e481. [5] J. Mouli-Castillo, M. Wilkinson, D. Mignard, C. McDermott, R.S. Haszeldine, Z.K. Shipton, Inter-seasonal compressed-air energy storage using saline aquifers, Nat. Energy (2019) 1. [6] H. Safaei, D.W. Keith, Compressed air energy storage with waste heat export: an Alberta case study, Energy Convers. Manag. 78 (2014) 114e124. [7] Y.M. Kim, J.H. Lee, S.J. Kim, D. Favrat, Potential and evolution of compressed air energy storage: energy and exergy analyses, Entropy 14 (8) (2012) 1501e1521. [8] L. Szablowski, P. Krawczyk, K. Badyda, S. Karellas, E. Kakaras, W. Bujalski, Energy and exergy analysis of adiabatic compressed air energy storage system, Energy 138 (2017) 12e18. [9] H. Guo, Y. Xu, H. Chen, X. Zhou, Thermodynamic characteristics of a novel supercritical compressed air energy storage system, Energy Convers. Manag. 115 (2016) 167e177. [10] Z. Wang, W. Xiong, D.S.K. Ting, R. Carriveau, Z. Wang, Conventional and advanced exergy analyses of an underwater compressed air energy storage system, Appl. Energy 180 (2016) 810e822. [11] R. Kushnir, A. Dayan, A. Ullmann, Temperature and pressure variations within compressed air energy storage caverns, Int. J. Heat Mass Transf. 55 (2012) 5616e5630. [12] R.H. Schulte, N. Critelli, K. Holst, G. Huff, Lessons from Iowa: Development of a 270 Megawatt Compressed Air Energy Storage Project in Midwest Independent System Operator, Sandia National Laboratories, Albuquerque, 2012. [13] H.M. Kim, J. Rutqvist, H. Kim, D. Park, D.W. Ryu, E.S. Park, Failure monitoring and leakage detection for underground storage of compressed air energy in lined rock caverns, Rock Mech. Rock Eng. 49 (2) (2016) 573e584. [14] P. Perazzelli, G. Anagnostou, Design issues for compressed air energy storage in sealed underground cavities, J. Rock Mech. Geotech. Eng. 8 (3) (2016) 314e328. [15] J. Rutqvist, H.M. Kim, D.W. Ryu, J.H. Synn, W.K. Song, Modeling of coupled thermodynamic and geomechanical performance of underground compressed air energy storage in lined rock caverns, Int. J. Rock Mech. Min. 52 (2012) 71e81. [16] C. Guo, L. Pan, K. Zhang, C.M. Oldenburg, C. Li, Y. Li, Comparison of compressed air energy storage process in aquifers and caverns based on the Huntorf CAES plant, Appl. Energy 181 (2016) 342e356. [17] C. Guo, K. Zhang, C. Li, X. Wang, Modelling studies for influence factors of gas bubble in compressed air energy storage in aquifers, Energy 107 (2016) 48e59. [18] C.M. Oldenburg, L. Pan, Porous media compressed-air energy storage (PM-

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