Numerical study of CO2 geological storage combined with saline water recovery and optimization of injection-production schemes in eastern Junggar Basin of China

CO2 geological storage (CGS) proved to be an enormously significant mid-to-long-term solution for mitigating and even nullifying the net greenhouse gas emissions, and CO2-enhanced water recovery (CO2-EWR) technology may improve the efficiency of CO2 injection and saline water production with potential economic value as a means of storing CO2 and supplying cooling water to power plants. The strata with dip-angle are common in nature, because of the effects of geological structure and diagenesis. It is of great significance to study the influence of the dip-angle on the efficiency and safety of CO2-EWR. Based upon the typical formation parameters of the China Geological Survey CO2-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of dip-angle on the enhanced efficiency of CO2 storage and saline production, considering geochemical reactions. Numerical simulation results show that the dip-angle has a regular influence on the formation pressure field, the CO2 transport distance in the reservoir and the CO2 sealing capacity, and the influence of dip-angle strata on the total storage amount of CO2 changed in a non-monotone mode compared with the CO2 geological storage in horizontal strata at the same injection condition. The effect of water chemical characteristics on the migration of CO2 in different phases and the transformations of major sequestered carbon minerals were determined from the resulting mechanism. Because non-horizontal strata are predominant in deep saline aquifers in nature, regardless of the influence of formation dip, CO2 leakage risks in geological storage will be greatly underestimated, and the stratum dip angle must be considered in research related to CO2 geological storage. Overall, the results of analysis provide a guide and reference for the CO2-EWR site selection.

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Numerical Study of CO2 Geological Storage in Saline Aquifers without the Risk of Leakage

Energies ◽

10.3390/en13205259 ◽

2020 ◽

Vol 13 (20) ◽

pp. 5259

Author(s):

Yuan-Heng Li ◽

Chien-Hao Shen ◽

Cheng-Yueh Wu ◽

Bieng-Zih Hsieh

Keyword(s):

Supercritical Co2 ◽

Numerical Study ◽

Simulation Method ◽

Co2 Injection ◽

Geological Storage ◽

Co2 Leakage ◽

Co2 Geological Storage ◽

Index Method ◽

Deep Saline Aquifer ◽

Supercritical Co2 Injection

The purpose of this study is to reduce the risk of leakage of CO2 geological storage by injecting the dissolved CO2 solution instead of the supercritical CO2 injection. The reservoir simulation method is used in this study to evaluate the contributions of the different trapping mechanisms, and the safety index method is used to evaluate the risk of CO2 leakage. The function of the dissolved CO2 solution injection is performed by a case study of a deep saline aquifer. Two scenarios are designed in this study: the traditional supercritical CO2 injection and the dissolved CO2 solution injection. The contributions of different trapping mechanisms, plume migrations, and the risk of leakage are evaluated and compared. The simulation results show that the risk of leakage via a natural pathway can be decreased by the approach of injecting dissolved CO2 solution instead of supercritical CO2. The amount of the CO2 retained by the safe trapping mechanisms in the dissolved CO2 solution injection scenario is greater than that in the supercritical CO2 scenario. The process of CO2 mineralization in the dissolved CO2 solution injection scenario is also much faster than that in the supercritical CO2 scenario. Changing the injection fluid from supercritical CO2 to a dissolved CO2 solution can significantly increase the safety of the CO2 geological storage. The risk of CO2 leakage from a reservoir can be eliminated because the injected CO2 can be trapped totally by safe trapping mechanisms.

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A Study on the CO2-Enhanced Water Recovery Efficiency and Reservoir Pressure Control Strategies

Geofluids ◽

10.1155/2019/6053756 ◽

2019 ◽

Vol 2019 ◽

pp. 1-17 ◽

Cited By ~ 2

Author(s):

Zhijie Yang ◽

Tianfu Xu ◽

Fugang Wang ◽

Yujie Diao ◽

Xufeng Li ◽

...

Keyword(s):

Saline Water ◽

Control Strategies ◽

Production Capacity ◽

Junggar Basin ◽

Pressure Control ◽

Reservoir Pressure ◽

Water Recovery ◽

Water Production ◽

Well Spacing ◽

Production Wells

CO2 geological storage (CGS) proved to be an effective way to mitigate greenhouse gas emissions, and CO2-enhanced water recovery (CO2-EWR) technology may improve the efficiency of CO2 injection and saline water production with potential economic value as a means of storing CO2 and supplying cooling water to power plants. Moreover, the continuous injection of CO2 may cause a sharp increase for pressure in the reservoir system, so it is important to determine reasonable reservoir pressure control strategies to ensure the safety of the CGS project. Based upon the typical formation parameters of the China Geological Survey CO2-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of the number of production wells and the well spacing on the enhanced efficiency of CO2 storage and saline production. The optimal key parameters that control reservoir pressure evolution over time are determined. The numerical results show that a smaller spacing between injection and production wells and a larger number of production wells can enhance not only the CO2 injection capacity but also the saline water production capacity. The effect of the number of production wells on the injection capacity and production capacity is more significant than that of well spacing, and the simulation scenario with 2 production wells, one injection well, and a well spacing of 2 km is more reasonable in the demonstration project of Junggar Basin. CO2-EWR technology can effectively control the evolution of the reservoir pressure and offset the sharp increase in reservoir pressure caused by CO2 injection and the sharp decrease of reservoir pressure caused by saline production. The main controlling factors of pressure evolution at a certain spatial point in a reservoir change with time. The monitoring pressure drops at the beginning and is controlled by the extraction of water. Subsequently, the injection of CO2 plays a dominant role in the increase of reservoir pressure. Overall, the results of analysis provide a guide and reference for the CO2-EWR site selection, as well as the practical placement of wells.

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