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.

It is generally accepted that reservoir wettability is one of the most important parameters in oil recovery processes. In the published literature, it is believed that the state of reservoir wettability mainly depends on the adsorption or precipitation of oxygen and nitrogen compounds present in the heavy-end fractions of crude oil. However, the establishment of reservoir wetting is a more complex process that involves chemical interactions between all phases of the reservoir: rock mineral surfaces, formation water, and surface-active components in the crude oil. In this study, dynamic adsorption tests were performed by flooding modified crude oils with a low asphaltene content through outcrop sandstone cores. Adsorption of crude oil components was analyzed by comparing base number (BN) and acid number (AN) of the effluent oil samples with the known initial BN and AN of the crude oil. The experimental results showed that crude oil bases are more active than acids toward the silicate rock mineral surfaces. Within the pore volumes flooded, it was not possible to achieve equilibrium BN values because of the continuous adsorption of basic components. Spontaneous imbibition (SI) tests showed that the core sample behaved slightly water-wet after crude oil flooding. Ion-modified smart water as an imbibition fluid in tertiary mode has previously shown potential for wettability alteration and improved oil recovery. With an increase in the amount of injected crude oil through the core, a decrease in oil recovery and a decrease in smart water-enhanced oil recovery (EOR) potential were observed. SI oil recovery results indicate reduced positive capillary forces and a change in wetting toward a less water-wet state. Thus, the chemical composition of crude oil should be considered as an important parameter for a reliable estimation of the reservoir wettability state and EOR potential by smart water injection.

Cellulose nanocrystals (CNC) has been investigated for a potential new application, enhanced oil recovery (EOR), by performing core flooding experiments with CNC dispersed in low salinity brine (CNC-LS) in outcrop sandstone cores. Experiments on 100 % water saturated cores confirmed that most of the viscosity generating CNC particles were able to travel through the cores at temperatures ranging from 60, to 120 °C. Oil recovery experiments on crude oil saturated sandstone cores showed that when CNC-LS was used in tertiary mode, the ultimate oil recovery could be increased, both at 90 and 60 °C. During tertiary CNC-LS injection, the CNC particles increased fluctuations in differential pressure, an effect that can be linked to log jamming in pore throats leading to remobilisation of oil in the pore space. The results from this work indicate that CNC dispersed in low saline brine might have a certain potential for use in enhanced oil recovery.

Both laboratory studies and field observations have confirmed increased oil recovery by low salinity water injection beyond that obtained by standard water injection. Whether extra oil is produced or not depends on certain reservoir conditions, and among them is the content of clay minerals. Kaolinite clay minerals have been reported to impact the low salinity enhanced oil recovery (EOR) potential, and they are believed to be involved in the initial wetting of sandstone reservoirs. In this work, the effect of temperature on the wetting of clay surfaces was studied. The adsorption of the polar organic base, quinoline, onto kaolinite clay minerals was investigated at ambient and high temperature (130 °C) versus pH. The experiments were performed using brines with different ionic compositions and salinities. A discussion of the effect of brine chemistry, pH, and temperature on quinoline adsorption was also included. Finally, wettability alteration processes by adsorption and desorption of polar organic molecules were used to explain the low salinity EOR effect observed in clay-containing sandstone reservoirs. The experimental results showed that the adsorption of quinoline onto kaolinite clay minerals was strongly dependent on pH at both ambient and at 130 °C. However, the adsorption at high temperature was reduced, which could affect the initial wetting of a sandstone reservoir system. The adsorption process was reversible by adjusting pH, and adsorption of quinoline was in general higher in a low salinity brine than in a high salinity brine. Thus, releasing basic polar crude oil components like quinoline from the kaolinite clay surface requires an increase in the brine pH, and not only a lowering of the salinity of the injection brine.

"Smart Water" is a modified injection brine specially designed for inducing wettability alteration to improve the oil recovery, and it can be injected in both secondary and tertiary (EOR) production phases. It is a low cost and environmentally friendly EOR technique, easily implementable in most oil reservoirs, both carbonates and sandstones. For an optimized Smart Water design, both initial reservoir wettability and the wettability alteration need to be understood. It includes surface mineralogy, brine composition and surface-active components in the crude oil. In sandstone reservoirs, the Smart Water EOR understanding is complex, involving several chemical liquid-solid interactions. The scope of this paper is to investigate how different sandstone minerals could affect initial rock wetting and wettability alteration during Smart Water injection. A set of experiments was performed to study the influence of sandstone mineralogy on the Smart Water EOR processes. The chemical interactions between brine and rock minerals in sandstone cores were tested by evaluating the produced water chemistry. Crude oil-brine-rock interactions were also tested by static adsorption tests and core floods. Oil recovery tests were performed to compare the ability of the different injection brines to enhance oil recovery from sandstone core material. Clay minerals contribute with most of the pore surface in sandstones. The experimental results have shown that adsorption of polar organic components onto the clay minerals are mostly dependent on brine pH, but also on brine composition/salinity, temperature, and type of clay minerals. For a wettability alteration to take place, initially adsorbed polar crude oil components must be desorbed from the mineral surface. Presence of feldspar minerals may affect the brine pH, and thereby affect the desorption of the polar organic components, and the reservoir wettability. Other minerals, such as evaporites, may also affect the wettability alteration process by Smart Water. As a result, detailed knowledge of the rock mineralogy is needed to be able to predict the initial rock wettability, and to evaluate the Smart Water EOR potential in a sandstone reservoir.