Impact of injection temperature and formation slope on CO2 storage capacity and form in the Ordos Basin, China

Carbon dioxide (CO2) storage capacity is the main criterion for assessing CO2 geological storage. Based on actual data from the Shiqianfeng formation in the Ordos Basin, three-dimensional (3D) models were built using the TOUGHVISUAL visualization software and simulated using the TOUGH2 integral finite difference modeling code with the ECO2N fluid property module to explore the impact of formation attributes (formation slope) and controllable factors (injection temperature) on CO2 storage capacity. A total of 16 schemes were designed, with four injection temperatures (24 ℃, 31 ℃, 38 ℃, and 45 ℃) and four formation slopes (0°, 5°, 10°, and 15°). Simulation results showed that the injection temperature and formation slope both had a significant influence on CO2 storage capacity. The impact of injection temperature on the total storage amount was more obvious than that of the impact of formation slope. A higher injection temperature resulted in a greater total storage amount. Increasing the formation slope and injection temperature increased the gas-phase, dissolved-phase, and total CO2 storage amounts in the upper left section of the injection well, but decreased them in the lower right part of the injection well. The impact of formation slope on the conversion rate from gas-phase CO2 to dissolved-phase CO2 was more obvious than the impact of injection temperature. A steeper formation slope resulted in a higher conversion rate. A smaller formation slope and a higher injection temperature should be selected to store CO2.


Introduction
CO 2 is a major greenhouse gas (Cui et al. 2018;Liu et al. 2019a, b), and the atmospheric CO 2 concentration has increased, from 316 ppm in March 1958 to 418.81 ppm in March 2022 (Costa 2019; https:// www. CO2. earth/). Climate change and the rising CO 2 concentration in the atmosphere are primarily responsible for global warming (De Silva et al. 2015), which has been one of the most critical issues in recent decades. Numerous studies have been conducted to investigate the causes of this global phenomenon and to propose prevention measures (Grimm et al. 2008;Wang et al. 2016a, b, c;Sumabat et al. 2016;Liu et al. 2019a, b). CO 2 emissions are relatively high in China, and great pressure has been placed on the Chinese government to reduce emissions (Diao 2017;Diao 2020).
CO 2 geological storage is one of the effective means to alleviate climate warming. Carbon capture and storage (CCS) can capture and inject CO 2 into deep geological formations for effective long-term storage (Lebedev et al. 2017;Al-Khdheeawi et al. 2018). CO 2 is injected into deep saline aquifers, where the storage mechanisms include stratigraphic structure, residual gas, dissolution, and mineral storage (Tang 2019;Gao 2019). The storage forms are composed of a gas phase, a dissolved phase, and a mineral phase (Zhao 2018;Yang 2019). Over a short time scale (several hundred years), the main types of storage are stratigraphic structure, residual gas, and dissolution storage, and the main existing forms are gas-phase and dissolved-phase storage.
Injectivity, storage capacity, and safety are the three major factors that determine the success of CO 2 storage in saline aquifers and must be accounted for when selecting suitable sites (Oldenburg 2008;Rutqvist 2012). CO 2 injection amount represents the injection capacity, whereas the CO 2 storage form reflects the storage capacity. CO 2 is mainly stored in the gas and dissolved phases over a short time frame (within 300 years). The gas-phase form of CO 2 is continuously transported upward under the action of buoyancy (Li and Yu 2020). CO 2 storage capacity and form are affected by many factors, such as: fault, which has a hidden danger for the CO 2 geological storage safety (Bu et al. 2016;Feng et al. 2017;Yang et al. 2018a, b;Han et al. 2019;Jing et al. 2019a, b, c). CO 2 injection conditions (pressure and temperature) were the controllable factors; larger injection pressure resulted in more CO 2 injection quantity (Wang et al. 2017); higher injection temperature resulted in the earlier CO 2 leakage ). In addition, salinity has a significant influence on CO 2 migration and the relative amount of mobile, residual, and dissolved CO 2 (Alkhdheeawi et al. 2018;Kumar et al. 2020), and organic acids also affect the geological CO 2 geological storage (Ali et al., 2019a(Ali et al., , b, 2020(Ali et al., , 2021. Formation slope is common in CO 2 geological storage sites, which directly affects formation pressure and temperature distribution, thus, resulting in different CO 2 geological storage capacities and forms. Many numerical models with different dip angles have been studied to quantify the effect of dip angle on CO 2 geological storage. Pruess and Nordbotten (2011) studied the migration characteristics of CO 2 Halo in a constant 1.5° dip angle formation, and the results showed that reservoir dip angle and permeability had great impact on the effectiveness of CO 2 geological storage. Ren (2018) studied the effect of formation dip angles (0°, 5° and 25°) on local capillary trapping. This study suggests, if small injection rates have to be employed, it would be better to choose a horizontal saline aquifer to enhance LCT (local capillary trapping). Han and Kim (2018) studied the effect of dipping caprock (2 to 10°) on the relationship between the migration distance of the CO 2 plume front and time, which was found to follow a linear trend. Wang et al. (2016a) studied the impacts of dip angle on CO 2 geological storage, and the research showed that the greater the formation slope, the more unfavorable it is for CO 2 storage. (Jing 2016;Jing et al. 2019a, b, c) discussed the effects of salinity and faults on CO 2 storage safety in different sloping formations, and the study showed that the greater the formation slope, the worse the CO 2 storage safety.
Temperature can affect CO 2 density, storage amount, and capacity. Injection temperature is a controllable factor that affects CO 2 geological storage. Through numerical simulation and experiment, predecessors discussed the influence of temperature (including CO 2 injection temperature, wellbore temperature, and reservoir temperature) on CO 2 storage capacity and migration. For example: Zhao and Cheng (2015) evaluated the effects of injection temperature on CO 2 storage in deep saline aquifers, which may have a considerable impact on the pressure build up near the injection well. Wu et al. 2017) showed that the wellbore temperature can determine the safety and effectiveness of CO 2 geological storage projects. Zhao and Cheng (2017) found that temperature may have a remarkable impact on salt precipitation during CO 2 injection. Vilarrasa et al. (2017) found that the temperature effect may impact the effective stress, which may further affect CO 2 injectivity. Gao et al. (2018) reported 13 terrestrial heat flow points to clarify the spatial variability of the present-day geothermal field across the Ordos Basin and its implications. Liu et al. (2019a) simulated four samples at temperatures of 32-80 ℃ by conducting experiments and found that increasing temperatures can lead to incremental changes in the main characteristics, specific surface area and total pore volume. Lei et al. (2020) showed that the temperaturechange zone traveled more slowly than the CO 2 plume. To avoid the formation of CO 2 hydrate in the subsurface, the injection temperature should be relatively high. Therefore, the impact of injection temperature on CO 2 geological storage can not be ignored.
CO 2 geological storage is affected by many factors, which is very complex; however, the previous research was basically a single factor idealized model (such as  carried out research on dip angle. The injection temperature had been studied by Zhao and Cheng (2015)). However, there was little research on the composite influence process of injection temperature and formation dip angle. In this paper, the formation dip angle and injection temperature were effectively combined to make the simulation results more practical. Therefore, the Shiqianfeng formation in the CCS demonstration project area of Ordos Basin was taken as the research object, and 3D models were constructed to evaluate the impacts of injection temperature and formation slope on CO 2 storage capacity and form. The objective was to select the most favorable injection temperature and formation slope for CO 2 geological storage. The study results provide relevant theoretical data for actual CO 2 geological storage engineering.

Geologic setting
The Ordos Basin situated in the western part of the North China block with 470 × 10 9 m 3 of proven natural gas resources, which is the second largest sedimentary basin in China (Li et al. 2019Yu et al. 2018;Luo et al. 2020). And it is one of the largest urban agglomerations and possibly the most important industrial center in middle China (Liu et al. 2019a, b). The basin can be divided into six tectonic units: the Weibei uplift in the south, the Yimeng uplift in the north, the Jinxi fold belt in the east, the Western Edge thrust belt in the west, the Tianhuan depression and the Yishan slope in the center (Wang and Guo 2019;Wang et al. 2016a, b, c) (Fig. 1). Fig. 1 Map showing the location of the CO 2 geological storage site in the Ordos Basin (Yang 2014;Wang and Guo 2019 The Shenhua Group implemented the first full-chain carbon capture and storage (CCS) demonstration project in the Ordos Basin (Wu 2013;Guo et al. 2015;Diao et al. 2020;Li et al. 2016a, b). Project is located in the eastern section of the northern Yishan Slope in the Chenjia village, Ulan Mulun Town, Ejin Horo Banner, Ordos City, Inner Mongolia Autonomous Region, China (110.05° E, 39.33° N) (Xie et al. 2015;Zhang et al. 2016;Wan et al. 2017).
The strata in the CCS demonstration area of Ordos are from Majiagou Formation of Lower Ordovician of Paleozoic to Quaternary of Cenozoic (Li et al. 2016a, b;Yang et al. 2018a, b). The main caprocks are the lower Triassic, the middle Zhifang formation, and the upper Yanchang formation. The cumulative thickness of the cover can reach 1133 m. The main reservoirs include Liujiagou formation, Shiqianfeng formation, Shihezi formation, and Shanxi formation ( Fig. 2) (Yang 2014).

Initial and boundary condition
According to previous experience (Jing 2016;Wang et al. 2016a, b, c;2017), through actual formation tests and calculations using the hydrostatic pressure balance method, initial pressure distribution data in the formation were obtained (Eq. 1). Initial temperature distribution data in the formation were obtained from actual monitoring and calculated by linear interpolation using the relation between temperature and depth (Eq. 2). The initial salinity was set to the actual water sample test result, which was 3% (by mass fraction) (Guo et al. 2014).
where P is pressure (Pa) of formation, z is depth (m), t 0 is starting time of injected CO 2 (s), g is acceleration of gravity, ρ w is water density.
Due to the thick caprock covering, the upper and lower boundaries of the model were assumed to be a zero-flow boundary. Based on previous numerical simulations of CO 2 geological storage (Wang et al. 2016a, b, c;2017;Yang et al. 2018a, b), the lateral boundary of the model was set to the first boundary.

Simulation tool and grid subdivision
Subdivision software-TOUGHVISUAL can be used for efficient and simple mesh generation. When the regular mesh is subdivided, the mesh is generated by setting the number and length of the mesh in the X, Y, Z directions (Yang et al. 2012(Yang et al. , 2013(Yang et al. , 2018a. Simulation software-TOUGH2-ECO2N is a fluid property module for the TOUGH2 simulator (Version 2.0), which was designed for applications of CO 2 geological storage in saline aquifers and describes the non-isothermal multiphase flow in a porous media system with H 2 O, NaCl, and CO 2 . That reproduces fluid properties largely within experimental error for the temperature, and pressure conditions of interest (10 ℃ ≤ T ≤ 110 ℃; P ≤ 600 bar). (Pruess et al. 1999;Pruess 2005;Pruess and Spycher 2007;Zhang et al. 2008;Yang et al. 2018a, b).
Based on drilling, seismic, and geophysical data (Guo et al. 2014), the models were constructed using non-equidistant rectangular mesh generation (i.e., the closer to the injection well, the denser was the grid generation). The unit closest to the injection well had a minimum grid resolution of 2 m, whereas the unit farthest from the injection well had a maximum grid resolution of 312 m. To avoid the effects of the lateral boundary, the x, y, and z directions were set to 10 km, 10 km, and 291 m (the actual formation thickness) respectively. According to the collection of logging and geophysical data and considering the porosity and permeability parameters of the Shiqianfeng formation, the strata were generalized in the vertical  Li et al. 2016a, b;Li et al. 2017) direction. The vertical direction was divided into 50 layers (17 of which were reservoir caprock). The total number of unit grid cells was 238,050 (69 × 69 × 50) (Fig. 3). The injection well was located at the center of the simulation model.

Model parameters
According to the characteristics of the Shiqianfeng formation and data from actual exploration (the porosity and permeability parameters) (Table 1), the simulated formation was divided into 17 reservoir caprock layers (Rock 1-Rock 17) (Fig. 4).
The mathematical model is established according to the conservation of mass and energy. The specific equation (Yang, 2014; Temitope and Gupta 2019) is as follows:  where S is saturation, ρ is density (kg m−3), X is mass fraction, k is permeability, μ is viscosity (kg m−1 s−1), P is pressure (bar), g is acceleration of gravity (m s−2), U is internal energy (J kg−1), Ф is porosity, λ is thermal conductivity (W m−1 K−1), T is temperature (℃), q is source sink phase, and h is heat.

Simulation schemes design
The actual slope of the Shiqianfeng formation is 1-3°, and the maximum slope of the ECBM project in Shanxi Qinshui Basin is 15°. According to previous experience (Wang et al. 2017), to explore the impact of variation in slopes on CO 2 storage capacity, four formation slopes (0°, 5°, 10°, and 15°) were selected.
Exhaust gas from industrial plants is a major CO 2 source. The first local air standard for thermal power plants to limit flue-gas emission temperature was implemented on July 1, 2018, in Tianjin, China. This air pollutant emission standard for thermal power plants requires a temperature ≤ 48 ℃ from April to October and ≤ 45 ℃ from November to March. According to CO 2 injection data, the real injection temperature of the Shiqianfeng formation was 31 ℃. To explore the impact of temperature on CO 2 injection, injection temperatures of 24 ℃, 31 ℃, 38 ℃, and 45 ℃ were investigated.
Sixteen schemes in total were designed. The constant pressure injection mode was assumed. The injection pressure was 1.3 times the hydrostatic pressure, the injection time was 20 years, and the simulation time was 300 years.

Simulation results and discussion
Formation temperature and pressure distribution Formation temperature CO 2 was then injected into the well, and injection temperature affected the temperature distribution near the injection well, whereas the formation slope affected the formation temperature distribution. Figure 5 shows the formation temperature distribution in a 15° sloping formation with a 24 ℃ CO 2 injection temperature for 20 years. The vertical distribution (YZ plane) was asymmetrical. The formation temperature and pressure in the following were vertical distribution (YZ plane) in the 35th grid layer. Figure 6 shows that the higher the injection temperature, the higher the formation temperature near the injection well in a formation with a constant slope of 15° under CO 2 injection for 20 years. The formation temperature near the injection well was stable under CO 2 migration for 300 years (Fig. 7).
Due to the impact of the temperature of the injected CO 2 , the formation temperature near the injection well was different in the injection stage. However, there was no external impact after cessation of injection, and the pressure near the injection well dissipated gradually.
A steeper formation slope resulted in a greater difference in the temperature distribution in the formation with a 24 ℃ injection temperature at a CO 2 injection for 20 years (Fig. 8).
Due to the effect of burial depth, the steeper the formation slope, the lower the formation temperature in the upper left section of the injection well, but the higher the formation temperature in the lower right section. Because of the continuous effect of the pressure to inject CO 2 , the formation temperature near the injection well presented an unstable distribution during injection. There was no effect of external conditions after injection ceased, and the formation temperature presented a stable distribution under CO 2 migration for 300 years (Fig. 9).

Formation pressure
Formation pressure was affected by the attributes of the formation itself (formation slope) and by external conditions The simulation results showed that the formation dip angle and injection temperature had certain effects on the spatial distribution of formation pressure. Figure 10 shows that the formation pressure distribution was basically the same in the constantly sloping (15°) formation at different injection temperatures under CO 2 injection for 20 years. Due to the impact of external pressure, the formation pressure near the injection well was non-uniform during the injection process. Different injection temperatures therefore resulted in slightly different formation pressures near the injection well. The higher the injection temperature, the higher the formation pressure, because at higher temperatures, the volume of CO 2 expands. However, the formation pressure distribution was significantly different in formations sloping at different degrees with a constant injection temperature (Fig. 11). The pressure increased at greater burial depths. An increase in slope resulted in a greater difference in burial depth between the upper left and lower right sections of the injection well, which was in line with observed data.  The pressure gradually dissipated after CO 2 injection ceased. The formation pressure then reached a stable state under CO 2 migration for 300 years (280 years after injection ceased) (Figs. 12 and 13).

CO 2 storage amount
Formation slope and injection temperature affect the distribution of formation pressure and temperature. Variations in formation pressure and temperature have a direct impact on the amount and form of CO 2 storage. Figure 14 shows that the gas-phase, dissolved-phase, and total CO 2 storage amounts in the whole formation increased with longer CO 2 injection time. The effect of formation slope on CO 2 storage amount was less than that of injection temperature. Figure 14c shows that the higher the injection temperature, the greater the total CO 2 storage amount. At higher temperatures, CO 2 density decreases, and CO 2 mass is the product of density and volume. When the injection temperature was 24 ℃, 31 ℃, and 38 ℃ in a horizontal (0°) formation, the total storage amount of the whole formation accounted for 96.210%, 97.582%, and 98.838% of the  Formation temperature distribution at different slope formations with 24 ℃ injection temperature under CO 2 migration for 300 years injection temperature (45 ℃), respectively. Because of the difference between the formation and injection temperatures in the injection stage, the injection amounts were different. There was no CO 2 input after the initial injection was stopped, and the total storage amount remained constant. Figure 14a and b show that the gas-phase CO 2 storage amount decreased at longer migration times, whereas the dissolved phase increased after injection ceased. This occurred because gas phase CO 2 was constantly dissolving in water to become part of the dissolved phase, which was in line with observed data. When the injection temperature was 24 ℃, 31 ℃, 38 ℃, and 45 ℃, the gasphase CO 2 storage amounts were 1.036, 1.052, 1.065, and 1.077 × 10 9 kg, respectively, in the 15° sloping formation under CO 2 migration for 300 years. The corresponding dissolved-phase CO 2 storage amounts were 5.118, 5.184, 5.250, and 5.322 × 10 8 kg, respectively. When the formation slope was 0°, 5°, 10°, and 15°, the gas-phase storage amounts were 1.176, 1.134, 1.077, and 1.036 × 10 9 kg, respectively, in the 24 ℃ injection temperature formation, and the dissolved-phase storage amounts were 3.722, 4.139, 4.713, and 5.118 × 10 8 kg, respectively. A steeper formation slope resulted in less gas-phase CO 2 and more dissolved-phase CO 2 in the whole formation. Because the steeper formation slope resulted in lower formation pressure in the upper left section of the injection well and Formation pressure distribution at different slopes with 24 ℃ injection temperature under CO 2 injection for 20 years higher formation pressure in the lower right section, and because the greater the buoyancy of CO 2 , the more the gas-phase CO 2 migrates to the upper left section, more space is provided for CO 2 to dissolve, where in the gasphase CO 2 continuously moves. The higher the injection temperature, the larger the CO 2 storage capacity for both the gas and dissolved phases. This occurs because the higher the temperature, the lower the CO 2 viscosity, and the easier it becomes for CO 2 to diffuse in storage. In other words, higher temperatures are conducive to CO 2 dissolution. Figure 15 shows the change curves of gas-phase, dissolved-phase, and total CO 2 storage amounts with time in the upper left and lower right sections of the injection well. The gas-phase, dissolved-phase, and total storage amounts increased with CO 2 injection time. Due to differences in formation slope and injection temperature, the gas-phase, dissolved-phase, and total CO 2 storage amounts were different after injection ceased. When CO 2 was allowed to migrate for 300 years, the gas-phase, dissolved-phase, and total CO 2 storage amounts were highest in the upper left section of the injection well with a 15° slope and 45 ℃ injection temperature, at 8.579, 3.745, and 12.324 × 10 8 kg, respectively. The gas-phase, dissolved-phase, and total CO 2 storage amounts were highest in the lower right section of the injection well that was horizontal (0°) with a 45 ℃  injection temperature, at 6.103, 1.9177, and 8.021 × 10 8 kg, respectively. Figure 15a and b show that the gas-phase storage amount decreased slightly in the upper left section of the horizontal formation, increased gradually in the 5° sloping formation, and first increased and then decreased in the 10° and 15° sloping formations. The transition from an increase to a decrease in the 10° sloping formation occurred later than in the 15° sloping formation. The buoyancy of CO 2 was relatively less in smaller sloping (0° and 5°) formations than in larger sloping (10° and 15°) formations, and CO 2 migrated continuously to the upper left section. Because there was no further external CO 2 input after injection ceased, CO 2 moved to the upper left section via by buoyancy, and the gas-phase CO 2 storage amount was continuously reduced in the lower right section of the formation. The larger the sloping formation, the greater the buoyancy of CO 2 , the farther CO 2 migrated to   Due to the continuous dissolution of gas-phase CO 2 in water into the dissolved phase, the amount of dissolvedphase CO 2 increased after injection ceased ( Fig. 15c and d). Because steeper formation slopes provided more dissolution space, the amount of dissolved-phase CO 2 was larger. The higher the injection temperature, the more the solubility of CO 2 changed with temperature. The amount of dissolvedphase CO 2 in the upper left section of the formation was larger than in the lower right part. Figure 15e and f show that the change in the total CO 2 storage amount was consistent with that of gas-phase CO 2 ( Fig. 15a and b). Figure 16 shows that formation slope had no obvious effect on the total CO 2 injection amount in the whole formation under CO 2 injection for 20 years (For example, the total CO 2 injection amount was the smallest (1.60873 × 10 9 kg) in 15° sloping formation with 45 ℃ injection temperature for 20 years. While the maximum injection amount was 1.60891 × 10 9 kg in 0° formation, the difference of 20 years was only 1.8 × 10 5 kg), although injection temperature had a significant effect on the total injection amount. The higher the injection temperature, the larger the total CO 2 injection amount, which was the same effect as shown in Fig. 14c. In other words, high injection temperature was helpful for CO 2 injection. Figures 17 and 18 show the changes in gas-phase and dissolved-phase CO 2 with formation slope and injection temperature in the whole formation under CO 2 migration for 20, 50, 150, and 300 years. The gas-phase storage amount was significantly larger than that of the dissolved phase. At longer migration times, due to continuous dissolution of gas-phase CO 2 , the gas-phase storage amount decreased gradually, but the dissolved-phase storage amount increased. Because of constant CO 2 input in the injection stage, the gas-phase CO 2 storage amount increased with increasing formation slope and injection temperature under CO 2 injection for 20 years (Fig. 17c). The gas-phase CO 2 storage amount decreased with increasing formation slope, and increased with increasing injection temperature under CO 2 migration for 50, 150, and 300 years ( Fig. 17b-d). Because there was no external CO 2 input during migration after injection ceased, the original gas-phase CO 2 was continuously dissolved. Longer migration times resulted in smaller gasphase CO 2 amounts. A steeper formation slope provided a larger dissolution space for CO 2 , and therefore more CO 2 was dissolved from the gas phase. Because of the impact of injection temperature during injection, more CO 2 was injected. The effect of injection temperature on CO 2 storage was more significant than that of formation slope.
The dissolved phase CO 2 storage amount decreased with increasing formation slope, but increased with increasing injection temperature under CO 2 injection for 20 years. The injection amount was highest (1.34005 × 10 9 ) in the sloping (15°) formation with a 45 ℃ injection temperature and increased at steeper formation slopes and higher injection temperatures under CO 2 migration for 50, 150, and 300 years. The impact of formation slope on the dissolvedphase storage amount was more significant than that of injection temperature. Figure 19 shows that gas-phase (Fig. 19a), dissolvedphase (Fig. 19c), and total ( Fig. 19e) CO 2 storage amounts increased with increasing formation slope and injection temperature in the upper left section of the injection well. Gasphase, dissolved-phase, and total CO 2 storage amounts were highest in a 15° sloping formation with a 45 ℃ injection temperature. Gas-phase (Fig. 19b), dissolved-phase (Fig. 19d), and total (Fig. 19f) CO 2 storage amounts decreased with increasing formation slope, and increased with increasing injection temperature in the lower right section. When the injection temperature was 45 ℃, the CO 2 storage amount was highest in the horizontal (0°) formation.
The variation laws of gas-phase, dissolved-phase, and total CO 2 storage amounts under CO 2 migration for 300 years were consistent with those under CO 2 injection for 20 years (Fig. 20). The differences in storage amount were most obvious between the upper left and lower right sections of the injection well. However, the effect of formation slope on CO 2 storage amount was greater than that of injection temperature.
To further clarify the impact of injection temperature and formation slope on storage capacity, the layer (a sub reservoir in the whole formation) with the largest porosity and permeability parameters (Rock 4) was selected for analysis. Figure 21 shows that a high injection temperature was favorable for CO 2 injection in the Rock 4 reservoir.  A higher injection temperature and shallower formation slope resulted in a greater total CO 2 storage amount in the migration stage after injection ceased. The total CO 2 storage amount was highest in Rock 4 with an injection temperature of 45 ℃ and formation slope of 0°, at 4.540 × 10 8 kg.
The impact of injection temperature on total CO 2 storage amount was obviously greater than that of formation slope.

CO 2 storage form
Different storage forms affect CO 2 geological storage capacity, whereas injection temperature and formation slope affect the CO 2 storage form. Figure 22 shows that the different percentages of gasphase CO 2 storage amounts between CO 2 injection for 20 years and migration for 50, 150, and 300 years accounted for the total storage amount in different sloping formations with a 24 ℃ injection temperature. The longer the CO 2 migration time, the larger the gas-phase CO 2 storage amount. A steeper formation slope resulted in a higher gas-phase CO 2 storage amount (more gas-phase CO 2 was converted into dissolved-phase CO 2 ). In other words, a large formation slope was conducive to the dissolution of gas-phase CO 2 . This was the case because the steeper the formation slope, the greater the impact of buoyancy on CO 2 , and the longer the distance of CO 2 upward migration, thus, giving

Fig. 19
Variation in the gas-phase, dissolved-phase, and total CO 2 storage amounts in the upper left and lower right sections of the injection well across different injection temperatures and formation slopes under CO 2 injection for 20 years enough space for CO 2 dissolution. On a 300-year time scale, CO 2 was mainly affected by structural trap and dissolution mechanisms, and its main storage forms were the gas-phase and dissolved-phase states. Due to differences in formation pressure, the steeper the formation slope, the higher the gas-phase CO 2 storage amount (Fig. 23). This indicated that a steep formation slope was conducive to the transformation of the gas phase into the dissolved phase. The conversion of gas-phase CO 2 was 7.273%, 9.975%, 13.705%, and 16.352%, respectively, in 0°, 5°, 10°, and 15° formations with a 24 ℃ injection temperature under CO 2 injection for 20 years and migration for 300 years. However, the injection temperature had no significant influence on the ratio of gas-phase CO 2 to dissolved-phase CO 2 . Figure 24 shows that higher injection temperature and shallower slope resulted in a larger ratio of total storage amount in the Rock 4 reservoir relative to the whole formation. This indicated that higher temperatures and shallower slopes were conducive to CO 2 storage. The proportion increased with increasing CO 2 injection time, but the rate of increase slowed down from CO 2 migration for 20 years to migration for 50 years and tended to become stable after 50 years. Under an injection temperature of 45 ℃ in a horizontal (0°) formation, the highest percentage was 28.215% under CO 2 migration for 300 years. Clearly, high porosity and permeability parameters were conducive to CO 2 storage, which was in line with observed data. Moreover, the impact of injection temperature on CO 2 storage was greater than

Fig. 20
Variation of the gas-phase, dissolved-gas, and total CO 2 storage amounts in the upper left and lower right parts of the injection well with injection temperature and formation slope under CO 2 migration for 300 years that of formation slope in the higher-porosity and higherpermeability layer, which was consistent with the results mentioned earlier in this paper.

Conclusion
CO 2 storage capacity is the key to evaluating CO 2 geological storage. The geological structure of the formation and its controllable factors affect CO 2 storage capacity. According to actual data from the Shiqianfeng formation in the Ordos Basin, 16 schemes of injection temperature (24 ℃, 31 ℃, 38 ℃, and 45 ℃) and formation slope (0°, 5°, 10°, and 15°) were developed to evaluate the impact of formation slope and injection temperature on CO 2 storage capacity. Through simulation and analysis, the following conclusions were obtained:

Fig. 24
Ratios of total CO 2 storage amount between Rock 4 (a sub reservoir in the whole formation) and the whole formation (1) The impact of injection temperature on total CO 2 storage amount was more obvious than that of the impact of formation slope. The higher the injection temperature, the larger the total CO 2 storage amount and the larger the CO 2 storage capacity.
(2) The gas-phase, dissolved-phase, and total CO 2 storage amounts increased with increasing formation slope and injection temperature in the upper left section of the injection well, but decreased with increasing formation slope, and increased with increasing injection temperature in the lower right section of the injection well. (3) The formation pressure and temperature distribution were obviously affected by formation slope. A steeper formation slope resulted in lower formation pressure and temperature in the upper left section of the injection well and higher formation pressure and temperature in the lower right section of the injection well. The injection temperature had a strong impact on the temperature distribution near the injection well during CO 2 injection. (4) The effect of formation slope on the conversion rate of gas phase CO 2 to dissolved-phase CO 2 was more obvious than that of the effect of injection temperature. A steeper formation slope resulted in a higher conversion rate.
In conclusion, a higher injection temperature and shallower formation slope were found to contribute to CO 2 storage, specifically to a greater storage capacity. For greater CO 2 geological storage, a higher injection temperature and shallower slope should be selected.
Author contribution Yanlin Yang: writing-original draft, methodology, software, funding acquisition. JingJing: conceptualization, data curation, drawing processing. Zhonghua Tang: writing-review and editing, software. Data availability There is no statement of availability of data and materials.

Declarations
Ethics approval and consent to participate Not applicable.

Competing interests
The authors declare no competing interests.