The processes of establishing and altering reservoir wettability are still subjects of discussion due to the complexity of the underlying crude oil−brine−rock interactions. This study was aimed at investigating the interrelationship between acidic and basic crude oil components and wetting tendencies on core samples of various mineralogies. Core flooding tests with light crude oils were performed to determine whether acidic or basic polar organic components (POC) showed the highest surface reactivity, adsorbing more readily onto the rock surfaces. The influence of this adsorption on wettability and capillary forces was then identified by performing spontaneous imbibition tests. The core materials used were a rather pure Stevns Klint outcrop chalk, a silica-containing Aalborg outcrop chalk, and an outcrop sandstone with silica minerals of quartz, clays, and feldspars. The results of this work showed a correlation between core mineralogy and the type of predominantly adsorbing POC. Pure chalk showed preference for organic acid adsorption over base adsorption, while the sandstone showed opposite preference. Because of the presence of negatively charged silica minerals, the silica-containing chalk showed increased affinity toward basic components and reduced affinity toward the acids compared to that observed for pure chalk. Oil recovery tests by spontaneous imbibition showed that for all cores, the adsorption of oil components significantly reduced water wetness. Thus, the types of minerals that make up the rock surface have a profound influence on the adsorption of POC and on the generation of wettability, and this should be kept in mind when using crude oil to restore core material wettability in the laboratory.

Despite it more than 500 papers being published on low-salinity (LS) water injection into sandstone oil reservoirs to enhance oil recovery, very few field applications of this enhanced oil recovery (EOR) technique are known. Laboratory investigations of LS water floods under tertiary conditions have shown varying results, and especially, the response time for establishing a new bank of oil in the porous medium has been too slow for application in the field. Usually, many pore volumes (PVs) of LS brine must be injected to obtain an increase in recovery of 5–10% of original oil in place (OOIP). Provided that the initial reservoir conditions for observing LS EOR effects are present, a close connection between the imposed pH gradient and additional oil recovery has been experimentally verified. To improve the chemical understanding of the LS EOR mechanism, it appeared important to study the development of the pH gradient because the HS brine is displaced by the LS brine. Therefore, the relationship between the LS EOR effect, pH gradient development, and heterogeneity in the pore size distribution of the porous medium was addressed in this paper. The experimental work covered both tertiary and secondary LS core flooding. The outcrop core material used had consistent composition and contained 8.2 wt % illite and 32.0 wt % albite, which both can contribute to the pH gradient under LS flooding conditions. In comparison to secondary oil recovery by injection of formation water (FW), ∼40% of OOIP, the secondary oil recovery using LS brine produced an additional 24% of OOIP. Tertiary injection of LS brine increased the recovery by about 10% of OOIP, after a secondary flood by FW. Injection of a tertiary low-salinity polymer (LSP) solution after secondary flooding with LS brine increased the ultimate recovery from 65 to about 86% of OOIP. In both cases, the response time for the LS EOR effect was discussed in terms of imposed pH gradient and heterogeneity in the pore size distribution. The results showed that oil recovery was closely linked to an increasing pH gradient. The response time to develop the pH gradient and a new bank of oil that could be produced seemed to be related to the pore size distribution; i.e., it took a longer time to develop a pH gradient and to displace the oil from the smaller pores than from the larger pores.

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