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Potential assessment of CO2 geological storage based on injection scenario simulation: A case study in eastern Junggar Basin
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Abstract: Carbon Capture and Storage (CCS) is one of the effective means to deal with global warming, and saline aquifer storage is considered to be the most promising storage method. Junggar Basin, located in the northern part of Xinjiang and with a large distribution area of saline aquifer, is an effective carbon storage site. Based on well logging data and 2D seismic data, a 3D heterogeneous geological model of the Cretaceous Donggou Formation reservoir near D7 well was constructed, and dynamic simulations under two scenarios of single-well injection and multi-well injection were carried out to explore the storage potential and CO2 storage mechanism of deep saline aquifer with real geological conditions in this study. The results show that within 100 km2 of the saline aquifer of Donggou Formation in the vicinity of D7 well, the theoretical static CO2 storage is 71.967 × 106 tons (P50)
① , and the maximum dynamic CO2 storage is 145.295 × 106 tons (Case2). The heterogeneity of saline aquifer has a great influence on the spatial distribution of CO2 in the reservoir. The multi-well injection scenario is conducive to the efficient utilization of reservoir space and safer for storage. Based on the results from theoretical static calculation and the dynamic simulation, the effective coefficient of CO2 storage in deep saline aquifer in the eastern part of Xinjiang is recommended to be 4.9%. This study can be applied to the engineering practice of CO2 sequestration in the deep saline aquifer in Xinjiang.-
Key words:
- CO2 geological storage /
- Deep saline aquifer /
- Potential assessment /
- Injection scenarios /
- Numerical simulation /
- Junggar Basin
注释: -
Figure 1. Location map of the study area and the distribution of the 2D seismic profile (Mi et al. 2018)
Figure 2. Stratigraphic histogram of Cretaceous Donggou Formation (Modified from Yang (2019))
Figure 5. Geological models of the study area (the left is porosity model, and the right is permeability model) (Modified after Wen et al. 2019)
Figure 6. 3D geological model and well location distribution (Case 1 on the left, Case 2 on the right)
Figure 7. Variation of CO2 in the reservoir over time (Case 1 on the left, Case 2 on the right)
Figure 8. The reservoir pressure and well bottom-hole pressures over time (Case1 on the left, Case2 on the right)
Figure 9. The 3D distribution of gaseous CO2 at 300 years (Case1 on the left and Case2 on the right)
Figure 10. The 3D distribution of gaseous CO2 at 300 years (Case1 on the left and Case2 on the right)
Figure 11. The distribution of CO2 in dissolved phase in 300 years (Case1 on the left and Case2 on the right)
Figure 12. The distribution of CO2 in dissolved phase at 300 years (3D) (Case1 on the left and Case2 on the right)
Figure 13. The distribution of residual trapping CO2 at 300 years (Case1 on the left and Case2 on the right)
Figure 14. Water density distribution in the reservoir at 300 years (Case1 on the left and Case2 on the right)
Figure 15. Pressure distribution in the reservoir at 300 years (Case 1 on the left side and Case 2 on the right)
Table 1. Recommended values for
$ {E_{{\text{saline}}}} $ (DOE-NETL, 2010; Bachu, 2015)Lithology P10/% P50/% P90/% Clasolite 1.2 2.4 4.1 Dolomite 2.0 2.7 3.6 Limestone 1.3 2.0 2.8 
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Table 2. CO2 sequestration capacity based on static modelling result
P10 P50 P90 Total volume of rocks(m3) 3.255 1×1010 3.255 1×1010 3.255 1×1010 Storage volume (m3) 4.327×109 4.327×109 4.327×109 Formation temperature (℃) 66 66 66 Formation pressure (MPa) 20.6 20.6 20.6 CO2 density (kg/m3) 693 693 693 Storage capacity (million tons) 35.98 71.97 122.94
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Table 3. The total amount of CO2 injection and its occurrence forms
CO2 Storage Amounts in Reservoir Case Million tons Percentage/% Total injection Case1 84.414 100.00 Supercritical gas 73.234 86.76 Residual trapping gas 19.813 23.47 Dissolved gas in water 11.180 13.24 Total trapping gas 31.063 36.71 Total injection Case 2 84.414 100.00 Supercritical gas 68.437 81.07 Residual trapping gas 22.063 26.14 Dissolved gas in water 15.977 18.93 Total trapping gas 38.077 45.07 Notes：The proportions of CO2 in different phases to the total injection volume in the saline aquifer are given in the table. In both scenarios, the total amount of CO2 injection is the same, and total trapping gas mainly consists of residual trapping gas + dissolved gas in saline water. The proportion of total trapping gas in Case 1 is 8.36% lower than that in Case 2, which is equivalent to 7.057 million tons of CO2. The injection mode of Case 2 has more advantages in this regard, but the storage capacity of the two scenarios is the same.
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Table 4. Maximum dynamic storage potential of CO2 in Case 1 and Case 2
Case Total injection/Million tons Injection duration/yr Storage efficiency/% Case1 135.919 81 4.5 Case2 145.295 95 4.9
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