The mutual effects of injected fluid and rock during imbibition in the process of low and high salinity carbonated water injection into carbonate oil reservoirs

Abstract

Abstract During water injection into oil reservoirs, interactions occur between injected water and the reservoir rock. The interactions are enhanced when dissolved carbon dioxide (CO2) is used in injectable fluid in enhanced oil recovery (EOR) process, especially in carbonate reservoirs. With the dissolution of CO2 in water, carbonic acid is formed. The formed acid reacts with the carbonate salts in the rock (calcium carbonate and magnesium carbonate) and dissolves them. The dissolution causes a change in the properties of the rock, including wettability, porosity and permeability. In this study, variations of porosity, permeability, rock mass and wettability during carbonated water imbibition were measured based on direct measurements of porosity, permeability, rock weight and contact angle. In addition, changes in the concentration of calcium, magnesium and bicarbonate ions from the dissolution of carbonate rocks in injected water were measured by sampling and titration of water. The experiments were carried out at a constant temperature and the pressure parameter was considered to be variable in order to investigate its effect on the cases discussed. The effect of base fluid salinity was investigated in two salinities equal to the initial salinity and salinity from the dilution of seawater. The carbonated water imbibition in oil-saturated plugs yields 48, 56, 69 and 75%, at pressures of 500, 1000, 1500, and 2000 psi, respectively, and low salinity resulted from the dilution of seawater as the base fluid. In addition to the dependence of changes in rock parameters on the pressure and salinity of the base fluid, the results show that porosity variations, permeability and, most importantly, wettability of the rock are so much that they can be effective in activating the process of the imbibition and increasing its power in oil production.