Solid/CO2 and solid/water interfacial tensions as a function of pressure, temperature, salinity and mineral type: Implications for CO2-wettability and CO2 geo-storage

Wettability of CO2/brine/mineral systems plays a significant role in the underground geological storage of CO2 as it governs the fluid flow and distribution mechanism within the porous medium. Technically, wettability is influenced by CO2 pressure, the temperature of the storage formation, formation water salinity and the type of mineral under investigation. Although a growing number of studies report wettability data for CO2/water/mineral systems, yet the factors responsible for wettability variation with pressure and temperature remain unclear. In this work, we used the concept of surface energy to explain dependency of wettability on pressure, temperature and salinity. Neumann's equation of state approach was used to compute solid/CO2 and solid/water interfacial energies using reliable contact angle and CO2/brine interfacial tension data from the literature at a wide range of operating conditions for quartz, water-wet mica, oil-wet mica and high, medium and low-rank coals. Moreover, the all-important question that why different minerals offer different wettability to CO2/water systems at the same pressure and temperature of investigation is addressed by comparing the interfacial energies of the minerals. We found that for all minerals solid/CO2 interfacial energy decreased with pressure and increased with temperature, and solid/water interfacial energy decreased with temperature except for quartz for which solid/water interfacial energy increased with temperature. Furthermore, the solid/CO2 interfacial energy was lowest for the oil-wet mica surface and highest for quartz which is due to higher hydrophobicity of oil-wet mica surface. The results of the study lead to a better understanding of the wetting phenomenon at the CO2/brine/mineral interface and thus contribute towards the better evaluation of geological CO2-storage processes

Genetic algorithm-based pore network extraction from micro-computed tomography images

A genetic-based pore network extraction method from micro-computed tomography (micro-CT) images is proposed in this paper. Several variables such as the number, radius and location of pores, the coordination number, as well as the radius and length of the throats are used herein as the optimization parameters. Two approaches to generate the pore network structure are presented. Unlike previous algorithms, the presented approaches are directly based on minimizing the error between the extracted network and the real porous medium. This leads to the generation of more accurate results while reducing required computational memories. Two different objective functions are used in building the network. In the first approach, only the difference between the real micro-CT images of the porous medium and the sliced images from the generated network is selected as the objective function which is minimized via a genetic algorithm (GA). In order to further improve the structure and behavior of the generated network, making it more representative of the real porous medium, a second optimization has been used in which the contrast between the experimental and the predicted values of the network permeability is minimized via GA. We present two case studies for two different complex geological porous media, Clashach sandstone and Indiana limestone. We compare porosity and permeability predicted by the GA generated networks with experimental values and find an excellent match

Ringtail Disorder observed in Cotton Rats (Sigmodon hispidus)

This is the first description of ringtail syndrome in cotton rats (Sigmodon hispidus). The disorder was sporadically observed in a laboratory reared breeding colony. Incidence of tail lesions decreased after standardization of environmental humidityin the laboratory animal facility

Wettability alteration of oil-wet carbonate by silica nanofluid

Changing oil-wet surfaces toward higher water wettability is of key importance in subsurface engineering applications. This includes petroleum recovery from fractured limestone reservoirs, which are typically mixed or oil-wet, resulting in poor productivity as conventional waterflooding techniques are inefficient. A wettability change toward more water-wet would significantly improve oil displacement efficiency, and thus productivity. Another area where such a wettability shift would be highly beneficial is carbon geo-sequestration, where compressed CO2 is pumped underground for storage. It has recently been identified that more water-wet formations can store more CO2. We thus examined how silica based nanofluids can induce such a wettability shift on oil-wet and mixed-wet calcite substrates. We found that silica nanoparticles have an ability to alter the wettability of such calcite surfaces. Nanoparticle concentration and brine salinity had a significant effect on the wettability alteration efficiency, and an optimum salinity was identified, analogous to that one found for surfactant formulations. Mechanistically, most nanoparticles irreversibly adhered to the oil-wet calcite surface (as substantiated by SEM–EDS and AFM measurements). We conclude that such nanofluid formulations can be very effective as enhanced hydrocarbon recovery agents and can potentially be used for improving the efficiency of CO2 geo-storage

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

Hypothesis: Nanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO2-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO2-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO2 geo-storage. Experiments: Pendant drop method was used to measure CO2/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell. Findings: CO2/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO2/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO2/nanofluid γ. Hence, CO2/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO2 storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid. The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects

Comparison of residual oil cluster size distribution, morphology and saturation in oil-wet and water-wet sandstone

We imaged an oil-wet sandstone at residual oil saturation (Sor) conditions using X-ray micro-tomography with a nominal voxel size of (9 μm)3 and monochromatic light from a synchrotron source. The sandstone was rendered oil-wet by ageing with a North Sea crude oil to represent a typical wettability encountered in hydrocarbon reservoirs. We measured a significantly lower Sor for the oil-wet core (18.8%) than for an analogue water-wet core (35%). We analysed the residual oil cluster size distribution and find consistency with percolation theory that predicts a power-law cluster size distribution. We measure a power-law exponent τ = 2.12 for the oil-wet core which is higher than τ for the water-wet system (τ = 2.05), indicating fewer large clusters in the oil-wet case. The clusters are rough and sheet-like consistent with connectivity established through layers in the pore space and occupancy of the smaller pores; in contrast the clusters for water-wet media occupy the centres of the larger pores. These results imply less trapping of oil, but with a greater surface area for dissolution. In carbon storage applications, this suggests that in CO2-wet systems, capillary trapping is less significant, but that there is a large surface area for dissolution and reaction

Nanoparticles influence on wetting behaviour of fractured limestone formation

Nanoparticles have gained considerable interest in recent times for oil recovery purposes owing to significant capabilities in wettability alteration of reservoir rocks. Wettability is a key factor controlling displacement efficiency and ultimate recovery of oil. The present study investigates the influence of zirconium (IV) oxide (ZrO2) and nickel (II) oxide (NiO) nanoparticles on the wetting preference of fractured (oil-wet) limestone formations. Wettability was assessed through SEM, AFM and contact angle. The potentials of the nanoparticles to alter oil-wet calcite substrates water wet, was experimentally tested at low nanoparticle concentrations (0.004–0.05 wt%). Quite similar behaviour was observed for both nanoparticles at the same particle concentration; while ZrO2 demonstrated a better efficiency by altering strongly oil-wet (water contact angle θ=152°) calcite substrates into a strongly water-wet (θ=44°) state, NiO changed wettability to an intermediate-wet condition (θ=86°) at 0.05 wt% nanoparticle concentration. We conclude that ZrO2 is very efficient in terms of inducing strong water-wettability; and ZrO2 based nanofluids have a high potential as EOR agents

Permeability evolution in sandstone due to injection of CO2-saturated brine or supercritical CO2 at reservoir conditions

We measured the change in permeability of two selected sandstones (Berea, Fonteinebleau) due to injection of CO2-saturated (“live”) brine, unsaturated (“dead”) brine or supercritical (sc) CO2 at reservoir conditions. We found that the permeability did not significantly change in a clean sandstone consisting of pure quartz (Fonteinemebleau) due to live or dead brine injection, although permeability changed due to scCO2 injection by ~23%. The permeability in the Berea sandstone, however, changed due to live or dead brine injection, by up to 35%; this permeability reduction in Berea sandstone was likely caused by fines release and subsequent pore throat plugging as the damage was more significant at higher injection rates. We expect that this phenomenon – i.e. rock permeability reduction due to CO2 injection into the formation – can have a significant and detrimental influence on CO2 injectivity, which would be reduced accordingly

Live imaging of micro and macro wettability variations of carbonate oil reservoirs for enhanced oil recovery and CO/ trapping/storage

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

In situ wettability investigation of aging of sandstone surface in alkane via x-ray microtomography

© 2020 by the authors. Licensee MDPI, Basel, Switzerland. Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations