Ionic Interactions at the Crude Oil-Brine-Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability

Experimental and Molecular Dynamics Simulation to Investigate Oil Adsorption and Detachment from Sandstone/Quartz Surface by Low-Salinity Surfactant Brines

In this study, we explore the impact of monovalent (NaCl) and divalent (CaCl2) brines, coupled with sodium dodecyl sulfate (SDS) surfactant at varying low concentrations, on the detachment and displacement of oil from sandstone rock surfaces. Employing the sessile drop method and molecular dynamics simulations, we scrutinize the behavior of the brine solutions. Our findings reveal that both low salinity and low-salinity surfactant solutions induce a gradual shift in rock wettability toward a more water-wet state. This wettability transformation is not instantaneous but evolves over time, as observed through meticulous molecular motion analyses. Through contact angle measurements and molecular dynamics simulations, we delve into the molecular motion at subpore and micropore scales on sandstone/quartz surfaces. The adsorption of surface-active agents from the oil to the oil-brine interface results in a reduced interfacial tension, significantly contributing to oil displacement. Notably, low salinity concentrations ranging from 1000 to 10,000 ppm exhibit the lowest contact angles within 30 min across all solutions. However, higher concentrations deviate from this declining trend, especially with divalent ions like Ca2+, which bridge polar molecules onto the rock surface, resulting in an increased oil-wetting state. This research unveils the intricate molecular motions involved in employing low-salinity surfactant solutions for oil detachment from surfaces. Furthermore, it provides valuable insights into the underlying forces driving oil detachment and wettability alteration.

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

The migration and accumulation of oil in tight sandstone reservoirs are mainly controlled by capillary force. Due to the small pore radius and complex pore structure of tight sandstone reservoirs, the capillary force is very sensitive to wettability, so wettability significantly affects oil migration and accumulation. However, the study of oil migration and accumulation in tight sandstone reservoirs often needs to combine multiple methods, the process is complex, and the research methods of wettability are not uniform, so the mechanism of wettability affecting oil migration and accumulation is not clear. Taking the tight sandstone of the Shahejie Formation in the Dongying sag, Bohai Bay Basin, as the research object, the wettability characteristics of a tight sandstone reservoir and their influence on oil migration and accumulation were analyzed by means of a pore permeability test, XRD analysis, micro-CT experiment, contact angle tests, spontaneous imbibition experiments, and physical simulation experiments on oil migration and accumulation. The results show that the reservoir is of the water-wet type, and its wettability is affected by the mineral composition. Wettability in turn affects the spontaneous imbibition characteristics by controlling the capillary force. Oil migration in tight sandstone reservoirs is characterized by non-Darcy flow, the oil is in the non-wetting phase and subject to capillary resistance. The key parameters to describe the oil migration and accumulation characteristics include the kickoff pressure gradient, the critical pressure gradient, and ultimate oil saturation. Wettability affects oil migration characteristics by controlling the capillary force. The more oil-wet the reservoir is, the more favourable it is to oil migration and oil accumulation and therefore the higher the reservoir’s ultimate oil saturation is.

CO2-Water-Rock Interactions in Carbonate Formations at the Tazhong Uplift, Tarim Basin, China

The effects of CO2-water-rock interactions on the injectivity and safety of CO2 geological storage have drawn wide attention. The geochemical reaction mechanisms in carbonate formations after CO2 injection are still controversial. To better understand the transformation of injected CO2 in carbonates and the involved geochemical reactions, we first conducted autoclave experiments reproducing the in-situ conditions of the Lianglitage Formation, Yingshan Formation, and Qiulitage Formation at the Tazhong Uplift in the Tarim Basin. We then established a batch model using TOUGHREACT-ECO2H, validated with the experimental results, to simulate the long-term CO2-water-rock interactions. It was found that the initial mineral compositions and water chemistry have important effects on the CO2-water-rock interactions in carbonate formations. The experiment results show that the dissolution of calcite and dolomite dominates in the early reaction period. However, we still observed some secondary minerals, such as ankerite, montmorillonite, calcite, and dolomite. The CO2-water-rock reactions can be more dramatic when the contents of calcite and dolomite in carbonates are closer. Moreover, the long-term simulation results show that calcite, magnesite, and hematite are the main formed secondary minerals, whereas dolomite is the major dissolved mineral. This study is helpful for a better understanding of the CO2 mineral trapping mechanism in carbonate formations.