Assessing the combined influence of fluid-rock interactions on reservoir properties and injectivity during CO2 storage in saline aquifers. (15th July 2018)

• Record Type: Journal Article
• Authors: Cui, Guodong; Wang, Yi; Rui, Zhenhua; Chen, Bailian; Ren, Shaoran; Zhang, Liang
• Is Part Of: Energy. Volume 155(2018)
• Page Start: 281
• Page End: 296
• Publication Date: 2018-07-15
• Subjects: Geologic CO2 storage -- Saline aquifers -- Salt precipitation -- Geochemical reactions -- CO2 injectivity; Power resources -- Periodicals; Power (Mechanics) -- Periodicals; Energy consumption -- Periodicals; 333.7905
• DOI: 10.1016/j.energy.2018.05.024
• Languages: English
• ISSNs: 0360-5442

Abstract

Abstract: 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. In this paper, 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. Moderate injection rates, salinities, capillary pressures, and permeabilities all lead to favorable CO2 injectivity. Highlights: Comprehensive fluid-rock interaction models were built for CO2 storage study. Flow characteristics and reservoir properties are analyzed during CO2 injection. Geochemical reactions also can be affected by the back flow of formation water. Salt precipitation in the dry-out zone front severely reduces the CO2 injectivity. Salinity, capillary force and permeability of the reservoir should not be high.