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Carbonate hydrocarbon reservoirs are considered as potential candidates for chemically enhanced oil recovery and for CO2 geological storage. However, investigation of one main controlling parameter—wettability—is usually performed by conventional integral methods at the core-scale. Moreover, literature reports show that wettability distribution may vary at the micro-scale due to the chemical heterogeneity of the reservoir and residing fluids. These differences may profoundly affect the derivation of other reservoir parameters such as relative permeability and capillary pressure, thus rendering subsequent simulations inaccurate. Here we developed an innovative approach by comparing the wettability distribution on carbonates at micro and macro-scale by combining live-imaging of controlled condensation experiments and X-ray mapping with sessile drop technique. The wettability was quantified by measuring the differences in contact angles before and after aging in palmitic, stearic and naphthenic acids. Furthermore, the influence of organic acids on wettability was examined at micro-scale, which revealed wetting heterogeneity of the surface (i.e., mixed wettability), while corresponding macro-scale measurements indicated hydrophobic wetting properties. The thickness of the adsorbed acid layer was determined, and it was correlated with the wetting properties. These findings bring into question the applicability of macro-scale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.

As the production of hydrocarbons from the carbonate reservoir increases, there is a necessity to enhance oil recovery methods to increase recovery factors and improve the economic efficiency of field development. The knowledge of wettability's role and fluid distribution at the pore scale is required to comprehend the mechanisms for oil displacement from porous media. The X-ray computed micro-CT technology provides opportunities to study the complex fluid displacement process at the pore level. This work discusses wettability restoration in carbonate cores and its effect on fluid distribution in porous space. Wettability restoration refers to restoring the original wettability of the core after extraction. We investigate wettability change and two-phase fluid distribution at pore-scale with the help of micro-CT technique along with Amott spontaneous imbibition methods. The Amott spontaneous imbibition experiments performed on the core under ambient pressure. The micro-CT experiments conducted for steady flow core flooding experiments on harsh cleaned cores. The three-dimensional images acquired for dry core, core saturated with brine and kerosene followed by oil injection. For better visualization of the fluid-fluid and fluid-rock surface and to remove voxel artifacts, iodo-octane is mixed with oil with 10 % wt/wt. The experiments allow us to envisage the structures of fluid in each phase during the displacement of fluid in carbonate rocks with high resolution (3 μm/voxel). The novelty of this approach lies in efficiently capturing the CT images of the fluid distribution and its influence on wettability during the "core-aging" procedure and validating the results of it with the Amott imbibition wettability index. The initial wettability of harsh cleaned carbonate cores was identified as water-wet compare to mixed wettability for mild cleaned carbonates. Nevertheless, all the samples become strongly oil-wet regardless of the cleaning methods after long-term saturation with crude oil. The X-ray CT technique revealed the fast evolution of contact angle of brine corresponding the wettability changes to strong oil-wet after contact with crude oil under the reservoir conditions.

It is well known that the development of unconventional reserves is quite complicated due to the poor reservoir porosity and permeability. The use of horizontal wells with multi-stage hydraulic fracturing remains one of the promising methods in use today for the development of such reserves. Subsequently, tertiary recovery methods popularly known as enhanced oil recovery (EOR) can then be carried out. In this paper, the compositions of anionic and non-ionic surfactants, potentially suitable for use in unconventional hydrocarbon deposits as EOR agents were investigated (on the example of one of the fields of Bazhenov formation). Also, attention was devoted to the assessment of the feasibility of co-injecting the surfactant solutions with a thermal agent (subcritical water) in a hybrid thermo-chemical EOR process. During the course of the study, 35 samples of industrial surfactants (individual and blends) were investigated. The compatibility of the surfactants with brine water, their stability under reservoir conditions (T>100 °C, P=25 MPa) for more than 14 days, and the effectiveness of the surfactants in reducing the interfacial tension (IFT) at the oil-brine boundary were the key factors in choosing the most appropriate compositions for use in the hybrid EOR. The ability of surfactants to decrease the IFT was investigated using a spinning drop tensiometer while the wettability alteration effect was estimated using a drop shape analyzer. Filtration experiment on oil-saturated core sample and evaluation of surfactant adsorption on rock surface were carried out with the best compositions. The results of the study show that the colloidal systems, represented by mixtures of anionic and non-ionic surfactants, have the best performance. The main components of these surfactant compositions are sodium salts of olefin sulfonates, derivatives of sulfonic acids C15-C20, and ethoxylated alcohols C6-C12. The results of measurements imply that certain compositions alter the initial rock wettability to become more water-wet and reduce the IFT between oil and water to a value of 0.051 mN/m. The adsorption of surfactant molecules on the rock was estimated to be 4 g/kg of rock, and the ultimate oil displacement rate increased due to surfactant injection from 8 % obtained during water flooding to 40.5 %. The possibility of using surfactants within the hybrid EOR technology was proven because the best surfactant mixture showed thermal stability at temperatures above 250 °C. Thus, we can conclude about the possibility of the use of some surfactant mixtures for the development of unconventional oil fields. Also, it is possible to combine the injection of surfactant solutions with the injection of thermal fluid, leading to the generation of synthetic oil in situ, thereby improving the reservoir properties of the rock and recovery of additional oil due to the effect of surfactants. This technology can be possibly applied for the development of unconventional reserves to increase the oil recovery ratio and make the process economically viable.

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