Thermo-hydrological numerical evaluation of carbon dioxide injection efficiency for its geologic storage using a coupled reservoir-well simulation scheme

被引:3
作者
Kihm, Jung-Hwi [1 ]
Park, Jai-Yong [2 ]
Lee, Sungho [2 ,3 ]
Kim, Jun-Mo [2 ,4 ]
Yum, Byoung-Woo [5 ]
机构
[1] Jungwon Univ, Dept Renewable Energy & Resources, Goesan Gun 28024, South Korea
[2] Seoul Natl Univ, Sch Earth & Environm Sci, Seoul 08826, South Korea
[3] Geotech Consultant Ltd, Geotech Engn Res Div, Gunpo 15850, South Korea
[4] GeoLab, Seoul 08787, South Korea
[5] Korea Inst Geosci & Mineral Resources, Geol Environm Res Div, Daejeon 34132, South Korea
基金
新加坡国家研究基金会;
关键词
Carbon dioxide; Geologic storage; Reservoir rock; Injection well; Injection rate; Injectivity; Coupled reservoir-well simulation scheme; Thermo-hydrological numerical evaluation; HYDRAULIC CONDUCTIVITY; CO2; FLOW; AQUIFERS; STABILITY; PRESSURE; DISPOSAL; KETZIN; DESIGN; MEDIA;
D O I
10.1016/j.ijggc.2019.01.012
中图分类号
X [环境科学、安全科学];
学科分类号
08 ; 0830 ;
摘要
A coupled reservoir-well simulation scheme is established to analyze quantitatively multi-phase fluid flow and heat transport due to carbon dioxide (CO2) injection in a reservoir rock-injection well system and to evaluate rigorously the CO2 injection efficiency in terms of the CO2 injection rate and injectivity. Two different cases of the CO2 injection pressure and temperature at the well head are then simulated using the coupled reservoir-well simulation scheme within a multi-phase thermo-hydrological numerical model. The results of the numerical simulations show that the fluid pressure and temperature and the CO2 injection rate and injectivity in the reservoir rock-injection well system can be quantitatively evaluated using the coupled reservoir-well simulation scheme. The fluid pressure and temperature in the injection well including the well head and bottom can also be simply predicted with assumptions of the hydrostatic fluid pressure transition and the adiabatic fluid temperature transition from the well head to the well bottom using the thermodynamic equation of state (EOS) data of CO2. In addition, the CO2 injection rate and injectivity have very close relationships with the fluid pressure and temperature at the well bottom, respectively, which determine the fluid pressure difference between the injection well bottom and the far-field reservoir rock and the kinematic viscosity of CO2 at the well bottom. The CO2 injection rate increases almost linearly with the fluid pressure difference, whereas the CO2 injectivity varies unsystematically with it. Instead, the CO2 injectivity has an excellent linear relationship with the reciprocal of the kinematic viscosity (i.e., kinematic fluidity) of CO2. These results can be utilized as practical guidelines to determine optimal injection operation schemes for sustainable, safe, and efficient geologic storage of CO2.
引用
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页数:12
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