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Liquid CO2 behaviour during water displacement in a sandstone core sample

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https://www.sciencedirect.com/science/article/pii/S187551001830533X
Original languageEnglish
Pages (from-to)259-274
Number of pages16
JournalJournal of Natural Gas Science and Engineering
Volume62
Early online date7 Dec 2018
DOIs
Publication statusPublished - Feb 2019

Abstract

CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a potential strategy to reduce CO2 concentration in the atmosphere, enhance hydrocarbon
production, or extract geothermal heat. CO2 injection is considerably influenced by the interfacial interactions, capillary forces and viscous forces. Any change in the subsurface conditions of pressure, temperature, and salinity is likely to have an impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have an influence on the injection, migration, displacement, and CO2 storage capacity. In this study, unsteady-state immiscible experimental investigations have been performed to explore the impact of fluid pressure, temperature, salinity (brine concentration and valency) and injection rate on the dynamic pressure evolution and displacement efficiency when CO2 as a liquid phase is injected into a water-saturated sandstone core sample. This study also highlights the impact of capillary forces and viscous forces on the two-phase flow properties and shows when capillary forces or viscous forces are dominant. The results reveal a moderate to considerable impact for the fluid pressure, temperature, injection rate, and salinity on the differential pressure profile, water recovery (WR), endpoint CO2 relative permeability (KrCO2), and cumulative produced volumes. Overall, increasing fluid pressure, CO2 injection rate and salinity (brine concentration and valency) cause an increase in the differential pressure profile; the highest increase occurred with the injection rate. In general, increasing temperature caused a reduction in the differential pressure profile. The WR is in range of around 61.6–69.3% while the KrCO2 is in range of 0.112–0.203, depending on the parameters investigated. Increasing fluid pressure and injection rate caused an increase in the WR; the highest increase occurred with the injection rate. On the other hand, increasing temperature and salinity caused a decrease in the WR; the highest reduction occurred with salinity. Nevertheless, the increase in fluid pressure, temperature, injection rate and salinity led to a reduction in the KrCO2; the highest reduction occurred with increasing temperature whilst the lowest occurred with increasing fluid pressure. The cumulative produced volumes decreased with fluid pressure and salinity but showed no noticeable change with temperature and injection rate. The capillary forces have less impact on the differential pressure profiles than viscous forces when fluid pressure, temperature and injection rate increase but the capillary forces show more impact as salinity increase.

    Research areas

  • 2-PHASE RELATIVE PERMEABILITY, BRINE SATURATED SANDSTONE, SUPERCRITICAL CO2, POROUS-MEDIA, CAPILLARY-PRESSURE, MULTIPHASE FLOW, CO2/WATER DISPLACEMENT, TEMPERATURE CONDITIONS, WETTABILITY ALTERATION, INTERFACIAL-TENSION

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