4.1. Base Case of Supercritical CO2 Injection
The basic problem of interest is that CO
2 is injected at the bottom of the formation (
Figure 8). CO
2 is injected at a fixed injection rate of 4500 m
3/day under a standard surface gas rate with a maximum bottom-hole pressure of 44,500 kPa for the first 20 years. The initial well bottom-hole pressure was about 27.4 MPa, and the bottom-hole pressure rose to about 29.6 MPa after 20 years of continuous injection. The migration of supercritical CO
2 was carried out until 2150 (100 years). After the well shut-in, the well bottom-hole pressure decreased slowly. The bottom-hole pressure was about 29.4 kPa at the end of the simulation, higher than the initial value (
Figure 9). The cumulative mass of the CO
2 injection was 6.83 × 10
4 t.
Figure 10 shows the spatial mobility and distribution of CO
2 saturation over time. Due to the density difference between the supercritical CO
2 and the aqueous phase, the low-viscosity CO
2 tends to migrate to the top of the geological formation. The highest concentration areas of CO
2 saturation are observed in the convex topography near the injection well. After the well shut-in, CO
2 continues to migrate to the anticline due to structural trapping (1 January 2060). After that, the CO
2 plume continues to move forward due to the accumulation of excess CO
2 in the anticline. At the end of the simulation period (1 January 2150), most of the CO
2 plume was still trapped at the top of the anticline in the Wei-2 formation.
The CO
2 mole changes at various simulation times are plotted in
Figure 11. At the beginning of the CO
2 injection, the supercritical CO
2 is injected and mixed with the initial water in the formation, forming a dissolved aqueous phase. The supercritical CO
2 continues to increase to a maximum value of 1.32 × 10
9 moles in 2050. Due to the existence of initial water in the formation, the CO
2 aqueous ions and dissolved CO
2 measure 5.04 × 10
8 and 0.575 × 10
8 moles in 2030, respectively. At the end of the simulation, the CO
2 aqueous ions and dissolved CO
2 measure 6.8 × 10
8 and 4.0 × 10
8 moles in 2050. The dissolved-CO
2 curve shows an increasing trend during geological carbon storage. During the CO
2 injection period, the amount of CO
2 dissolved in the aqueous phase is more than that of trapped CO
2. There is a sharp increase in trapped CO
2 after the well shut-in, mainly due to CO
2 being trapped by the anticline.
Figure 12 and
Figure 13 show the mineral moles changes in anorthite, calcite, and kaolinite.
Figure 14 shows the ion mole changes at the end of the simulation. It can be observed that the kaolinite is precipitated in the aqueous phase, while the anorthite is dissolved. Calcite is initially in the dissolved state, gradually converting to a precipitated state due to the continued geochemical reactions in the late storage period. The mole changes for anorthite, calcite, and kaolinite are −2.79 × 10
7, 2.07 × 10
7, and 7.85 × 10
5 at the end of the simulation, respectively. As CO
2 is dissolved in the aqueous phase, there is a decrease in PH in the CO
2 migration areas (
Figure 15). The porosity variation was insignificant at the end of the simulation (
Figure 16). Anorthite, a calcium-rich mineral, is dissolved to provide Ca
2+ and Al
3+ in the aqueous phase due to the formation of carbonic acid. Ca
2+ and Al
3+ contribute to the precipitation of calcite and kaolinite with time. The mineral change in calcite is more than that of kaolinite precipitation. The precipitation of calcite consumed more Ca
2+ compared with Al
3+ consumed by kaolinite precipitation. The mole changes in Al
3+ is more obvious than that in Ca
2+ 100 years after the injection period.
For the CO
2 injection, the CO
2 moles of different trapping mechanisms are illustrated in
Figure 17. The trapping mechanisms of the structural, residual gas, solubility, ions, and minerals are considered in CO
2 storage amounts in the reservoir (
Figure 18). During the CO
2 injection period, the storage contributions of structural and solubility trapping decrease with time, and the trapping contribution of residual gas is nearly fixed as a constant. When the injection well was shut down (1 January 2050), 72% of the primary 1.5512 × 10
9 moles of injected CO
2 was trapped by structural trapping. The storage contributions of residual gas, solubility, ionic, and mineral trapping are 13.38%, 11.55%, 3.07%, and 0%, respectively. After the injection well was shut down, the contribution of structural trapping decreased from 72% to 28.39% with time. At the end of the simulation, 28.39%, 36.83%, 22.08%, 11.36%, and 1.34% of the injected CO
2 was stored by structural, residual gas, solubility, ionic, and mineral trapping, respectively.
4.2. Modified Case of Supercritical CO2 + Water Injection
Improving carbon storage efficiency, the case is modified by adding a water injection to the CO
2 storage model. The water perforation location is above the CO
2 perforation location (
Figure 19). Water is injected at a fixed injection rate of 25 m
3/day under a standard surface water rate for the first 10 years, and supercritical CO
2 is injected for 20 years continuously.
Figure 20 shows the spatial distribution of CO
2 saturation after a simulation time of 100 years. It is observed that most of CO
2 plume was trapped on the top of the anticline in the Wei-2 formation, without migrating out of the anticline (2150-01-01).
Figure 21 illustrates the CO
2 mole changes at various simulation times for CO
2 and water injection. The CO
2 aqueous ions and dissolved CO
2 measure 7.06 × 10
8 and 4.5 × 10
8 moles in 2150, respectively.
Figure 22 displays the evolution of anorthite, calcite, and kaolinite mole changes at various simulation times for the CO
2 and water injections. The mole changes for anorthite, calcite, and kaolinite are −3.23 × 10
7, 2.51 × 10
7, and 9.3 × 10
5 after well shut down after 100 years, respectively.
For supercritical CO
2 plus water injection, the moles of different trapping mechanisms are illustrated in
Figure 23, and the trapping contributions of different mechanisms are illustrated in
Figure 24. During the CO
2 and water injection period, the storage contribution of structural trapping displays an initial decrease (10 years) and then shows an increasing trend (10 years) with time. When the injection well was shut down, 60.38% of the moles of injected CO
2 was trapped by structural trapping. The trapping contributions of residual gas, solubility, ionic, and mineral trapping are 19.16%, 16.28%, 4.18%, and 0%, respectively. One-hundred years after the injection well was shut down, the contribution of structural trapping decreased from 72% to 19.05% with time. At the end of the simulation (120 years), 19.05%, 40.95%, 25.33%, 13.05%, and 1.62% of the injected CO
2 was stored by structural, residual gas, solubility, ionic, and mineral trapping, respectively.
4.3. Comparisons of CO2 Injection and CO2 + Water Injection
Compared with CO
2 injection, the storage contribution of structural trapping decreases from 28.39% to 19.05% for CO
2 and water injection. It can be seen from
Figure 25 that the storage contributions of residual gas, solubility, ionic, and mineral trapping increases at the end of the simulation for the modified case. The percentage increase in the storage contributions of residual gas, solubility, ionic, and mineral trapping due to water injection are 4.12%, 3.25%, 1.69%, and 0.28%. It is concluded that injecting water above the location of CO
2 injection is an effective method to improve the storage efficiency of residual gas, solubility, ionic, and mineral trapping, and provides an effective reference for CO
2 storage. Structural trapping was the maximum storage contribution when the well was shut down. At the end of the simulation, the residual gas trapping is the maximum storage contribution for CO
2 storage.
Water injection enhances storage efficiency mainly for the following reasons:
- (1)
The injection of water can improve the mobility of carbon dioxide within the reservoir, promoting its uniform distribution and further enhancing storage effectiveness.
- (2)
By creating a water layer through injection, a barrier can be formed to some extent, reducing the risk of carbon dioxide leaking to the surface or into other strata.
- (3)
Additionally, water injection can increase the pressure in the underground reservoir, helping to drive carbon dioxide into deeper pore spaces, thereby improving the efficiency of CO2 storage.