Ahmed Barifcani

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.

Residual trapping of supercritical CO2 in oil-wet sandstone

Residual trapping, a key CO2 geo-storage mechanism during the first decades of a sequestration project, immobilizes micrometre sized CO2 bubbles in the pore network of the rock. This mechanism has been proven to work in clean sandstones and carbonates; however, this mechanism has not been proven for the economically most important storage sites into which CO2 will be initially injected at industrial scale, namely oil reservoirs. The key difference is that oil reservoirs are typically oil-wet or intermediate-wet, and it is clear that associated pore-scale capillary forces are different. And this difference in capillary forces clearly reduces the capillary trapping capacity (residual trapping) as we demonstrate here. For an oil-wet rock (water contact angle θ=130°) residual CO2 saturation SCO2,r (≈8%) was approximately halved when compared to a strongly water-wet rock (θ=0°; SCO2,r≈15%). Consequently, residual trapping is less efficient in oil-wet reservoirs.

Impact of pressure and temperature on CO2-brine-mica contact angles and CO2-brine interfacial tension: Implications for carbon geo-sequestration

Precise characterization of wettability of CO2-brine-rock system and CO2-brine interfacial tension at reservoir conditions is essential as they influence capillary sealing efficiency of caprocks, which in turn, impacts the structural and residual trapping during CO2 geo-sequestration. In this context, we have experimentally measured advancing and receding contact angles for brine-CO2-mica system (surface roughness ∼12nm) at different pressures (0.1MPa, 5MPa, 7MPa, 10MPa, 15MPa, 20MPa), temperatures (308K, 323K, and 343K), and salinities (0wt%, 5wt%, 10wt%, 20wt% and 30wt% NaCl). For the same experimental matrix, CO2-brine interfacial tensions have also been measured using the pendant drop technique. The results indicate that both advancing and receding contact angles increase with pressure and salinity, but decrease with temperature. On the contrary, CO2-brine interfacial tension decrease with pressure and increase with temperature. At 20MPa and 308K, the advancing angle is measured to be ∼110°, indicating CO2-wetting. The results have been compared with various published literature data and probable factors responsible for deviations have been highlighted. Finally we demonstrate the implications of measured data by evaluating CO2 storage heights under various operating conditions. We conclude that for a given storage depth, reservoirs with lower pressures and high temperatures can store larger volumes and thus exhibit better sealing efficiency.

Swelling‐induced changes in coal microstructure due to supercritical CO2 injection

Enhanced coalbed methane recovery and CO2 geo-storage in coal seams are severely limited by permeability decrease caused by CO2 injection and associated coal matrix swelling. Typically it is assumed that matrix swelling leads to coal cleat closure and as a consequence, permeability is reduced. However, this assumption has not yet been directly observed. Using a novel in-situ reservoir condition x-ray micro computed tomography flooding apparatus, for the first time we observed such micro cleat closure induced by supercritical CO2 flooding in-situ. Furthermore, fracturing of the mineral phase (embedded in the coal) was observed; this fracturing was induced by the internal swelling stress. We conclude that coal permeability is drastically reduced by cleat closure, which again is caused by coal matrix swelling; which again is caused by flooding with supercritical CO2.

Dependence of quartz wettability on fluid density

Wettability is one of the most important parameters in multiphase flow through porous rocks. However, experimental measurements or theoretical predictions are difficult and open to large uncertainty. In this work we demonstrate that gas densities (which are much simpler to determine than wettability and typically well known) correlate remarkably well with wettability. This insight can significantly improve wettability predictions, thus derisking subsurface operations (e.g., CO2 geostorage or hydrocarbon recovery), and significantly enhance fundamental understanding of natural geological processes.

Oil-Water Interfacial Tensions of Silica Nanoparticle-Surfactant Formulations

Abstract The implementation of nanotechnology in all industries is one of most significant research fields. Nanoparticles have shown a promising application in subsurface fields. On the other hand, various surfactants have been used in the oil industry to reduce oil/water interfacial tension and also widely used to stabilize the nano-suspensions. The primary objective of this study was to investigate the improvements of surfactants ability in term of interfacial tension (γ) reduction utilizing addition of silicon dioxide nanoparticles at different temperatures and salinity. The pendant drop technique has been used to measure γ and electrical conductivity has been used to measure the critical micelle concentration (CMC). The synergistic effects of surfactant-nanoparticles, salt-nanoparticles, and surfactant-salt-nanoparticles on γ reduction and the critical micelle concentration of the surfactants have been investigated. Extensive series of experiments for γ and CMC measurements were performed. The optimum condition for each formulation is shown. We conclude that nanoparticles-surfactant can significantly reduce γ if correctly formulated.

Wettability alteration of oil-wet limestone using surfactant-nanoparticle formulation

Wettability remains a prime factor that controls fluid displacement at pore-scale with substantial impact on multi-phase flow in the subsurface. As the rock surface becomes hydrophobic, any oleic phase present is tightly stored in the rock matrix and produced (hydrocarbon recovery) or cleaned up (soil-decontamination) by standard waterflooding methods. Although surface active agents such as surfactants have been used for several decades for changing the wetting states of such rocks, an aspect that has been barely premeditated is the simultaneous blends of surfactants and nanoparticles. This study thus, systematically reports the behaviour of surfactants augmented nanoparticles on wettability alteration. Contact angle, spontaneous imbibition, and mechanistic approaches were adopted to assess the technical feasibility of the newly formulated wetting agents, tested over wide-ranging conditions to ascertain efficient wetting propensities. The contact angle measurement is in good agreement with the morphological and topographical studies and spontaneous imbibition. The wetting trends for the formulated systems indicate advancing and receding water contact angle decreased with increase in nanoparticle concentration and temperature, and the spontaneous water imbibition test also showed faster water-imbibing tendencies for nanoparticle-surfactant exposed cores. Thus, the new formulated nanoparticle-surfactant systems were considered suitable for enhancing oil recovery and soil-decontamination, particularly in fractured hydrophobic reservoirs.

Impact of fines and rock wettability on reservoir formation damage

ABSTRACT Pore throat plugging of porous rock by fine particles causes formation damage, and thus has attracted attention in various areas such as petroleum engineering, hydrology and geothermal energy production. Despite significant efforts, the detailed pore‐scale mechanisms leading to formation damage and the associated permeability reduction are not well understood. We thus investigated plugging mechanisms and characteristics with a combination of ex situ (i.e., coreflooding measurements and scanning electron microscopy imaging) and in situ (i.e., nuclear magnetic resonance and μCT) methods, with a particular focus on the effect of wettability. The corefloods indicated that permeability drops rapidly when fines are injected; mechanistically thin pore throats are plugged first, followed by filling of adjacent pore bodies with the fine material (as evidenced by the nuclear magnetic resonance and μCT experiments, which can measure the pore size distribution evolution with fines injection). Furthermore, it is clear that wettability plays a major role: if fines and rock wettability are identical, plugging is significantly accelerated; wettability also controls the 3D distribution of the fines in the pore space. Furthermore we note that the deposited fines were tightly packed, apparently due to strong adhesion forces.

Influence of shale‐total organic content on CO2 geo‐storage potential

Shale CO2-wettability is a key factor which determines the structural trapping capacity of a caprock. However, the influence of shale-TOC on wettability (and thus on storage potential) has not been evaluated despite the fact that naturally occurring shale formations can vary dramatically in TOC, and that even minute TOC strongly affects storage capacities and containment security. Thus there is a serious lack of understanding in terms of how shale, with varying organic content, performs in a CO2 geo-storage context. We demonstrate here that CO2-wettability scales with shale-TOC at storage conditions; and we propose that if TOC is low, shale is suitable as a caprock in conventional structural trapping scenarios, while if TOC is ultrahigh to medium, the shale itself is suitable as a storage medium (via adsorption trapping after CO2 injection through fractured horizontal wells).

Stabilising nanofluids in saline environments

Nanofluids (i.e. nanoparticles dispersed in a fluid) have tremendous potential in a broad range of applications, including pharmacy, medicine, water treatment, soil decontamination, or oil recovery and CO2 geo-sequestration. In these applications nanofluid stability plays a key role, and typically robust stability is required. However, the fluids in these applications are saline, and no stability data is available for such salt-containing fluids. We thus measured and quantified nanofluid stability for a wide range of nanofluid formulations, as a function of salinity, nanoparticle content and various additives, and we investigated how this stability can be improved. Zeta sizer and dynamic light scattering (DLS) principles were used to investigate zeta potential and particle size distribution of nanoparticle-surfactant formulations. Also scanning electron microscopy was used to examine the physicochemical aspects of the suspension. We found that the salt drastically reduced nanofluid stability (because of the screening effect on the repulsive forces between the nanoparticles), while addition of anionic surfactant improved stability. Cationic surfactants again deteriorated stability. Mechanisms for the different behaviour of the different formulations were identified and are discussed here. We thus conclude that for achieving maximum nanofluid stability, anionic surfactant should be added.