Assessing the combined influence of fluid-rock interactions on reservoir properties and injectivity during CO2 storage in saline aquifers

Cui, Guodong; Wang, Yi; Rui, Zhenhua; Chen, Bailian; Ren, Shaoran; Zhang, Liang

doi:10.1016/j.energy.2018.05.024

Assessing the combined influence of fluid-rock interactions on reservoir properties and injectivity during CO₂ storage in saline aquifers

Journal Article · Sat May 05 00:00:00 EDT 2018 · Energy

DOI:https://doi.org/10.1016/j.energy.2018.05.024· OSTI ID:1479993

Cui, Guodong ^[1]; Wang, Yi ^[1]; Rui, Zhenhua ^[2]; Chen, Bailian ^[3]; Ren, Shaoran ^[1]; Zhang, Liang ^[1]

China Univ. of Petroleum, Qingdao (China). School of Petroleum Engineering
Massachusetts Inst. of Technology (MIT), Cambridge, MA (United States). Dept. of Mechanical Engineering
Los Alamos National Lab. (LANL), Los Alamos, NM (United States)

Complex fluid-rock interactions can occur during the injection of carbon dioxide (CO₂) into saline aquifers for sequestration, which may affect CO₂ injectivity and storage capacity. A comprehensive reactive transport model is established to analyze salt precipitation, CO₂-water-rock geochemical reactions, and their effects on reservoir physical properties and injectivity. In addition, sensitivity analyses are conducted to investigate the main factors that affect fluid-rock interactions and injectivity with relevance for site selection for CO₂ storage. Results show that the back flow of formation water not only affects the salt precipitation but also affects the CO₂-water-rock geochemical reactions, resulting in salt and calcite precipitations mainly occurring in the dry-out zone. However, most of the mineral dissolution/precipitation caused by CO₂-water-rock reaction occurs in the two-phase and aqueous-phase zones, and their effect on reservoir porosity and permeability are small. A considerable amount of sodium chloride precipitates in the dry-out zone as brine is drawn by capillary action into this zone, with significant consequences for porosity, permeability and injectivity. The injection rate, salinity, capillary pressure–saturation relationships, and reservoir permeability strongly affect the distribution of salt precipitation. Finally, moderate injection rates, salinities, capillary pressures, and permeabilities all lead to favorable CO₂ injectivity.

View Accepted Manuscript (DOE)

Research Organization:: China Univ. of Petroleum, Qingdao (China); Los Alamos National Lab. (LANL), Los Alamos, NM (United States)

Sponsoring Organization:: Changjiang Scholars and Innovative Research (China); China Univ. of Petroleum (China); Fundamental Research Funds for the Central Universities (China); National Natural Science Foundation of China (NSFC); National Oil and Gas Major Projects (China); USDOE

Grant/Contract Number:: AC52-06NA25396

OSTI ID:: 1479993

Alternate ID(s):: OSTI ID: 23079689

Report Number(s):: LA-UR--18-23944

Journal Information:: Energy, Journal Name: Energy Vol. 155; ISSN 0360-5442

Publisher:: ElsevierCopyright Statement

Country of Publication:: United States

Language:: English

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Productivity Model for Water-Producing Gas Well in a Dipping Gas Reservoir With an Aquifer Considering Stress-Sensitive Effect Huang, Xiaoliang; Guo, Xiao; Zhou, Xiang Journal of Energy Resources Technology, Vol. 141, Issue 2 https://doi.org/10.1115/1.4041741	journal	November 2018
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Related Subjects

54 ENVIRONMENTAL SCIENCES
CO2 injectivity
geochemical reactions
geologic CO2 storage
saline aquifers
salt precipitation