Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems:Critical parametric analysis and future outlook

Arif, Muhammad; Abu-Khamsin, Sidqi A.; Iglauer, Stefan

doi:10.1016/j.cis.2019.03.009

Cited by 173 publications

(112 citation statements)

References 132 publications

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“…[12][13][14][15][16][17][18] The experimental results are consistent, in that the calcite system is strongly water-wet (0 • <θ<75 • ), but there is significant scatter in the reported contact angles, ranging from ∼2 • to 60 • . 7,19 This is not surprising because organic material and adsorbed ions can dramatically change the wettability of mineral surfaces 20,21 and calcite is know to be very attractive to organic material even in very dilute solutions. 22 AFM data and simulation results suggest this to result from adsorption on the ordered water layers that are adsorbed on the calcite surface, rather than direct binding.…”

Section: Introductionmentioning

confidence: 99%

Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects

et al. 2019

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Assessment of the risks and environmental impacts of carbon geosequestration requires knowledge about the wetting behavior of mineral surfaces in the presence of CO2 and the pore fluids. In this context, the interfacial tension (IFT) between CO2 and the aqueous fluid and the contact angle, θ, with the pore mineral surfaces are the two key parameters that control the capillary pressure in the pores of the candidate host rock. Knowledge of these two parameters and their dependence on the local conditions of pressure, temperature, and salinity is essential for the correct prediction of structural and residual trapping. We have performed classical molecular dynamics simulations to predict the CO2–water IFT and the CO2–water–calcite contact angle. The IFT results are consistent with previous simulations, where simple point charge water models have been shown to underestimate the water surface tension, thus affecting the simulated IFT values. When combined with the EPM2 CO2 model, the SPC/Fw water model indeed underestimates the IFT in the low-pressure region at all temperatures studied. On the other hand, at high pressure and low temperature, the IFT is overestimated by ∼5 mN/m. Literature data regarding the CO2/water/calcite contact angle on calcite are contradictory. Using our new set of force field parameters, we performed NVT simulations at 323 K and 20 MPa to calculate the contact angle of a water droplet on the calcite {10.4} surface in a CO2 atmosphere. We performed simulations for both spherical and cylindrical droplet configurations for different initial radii to study the size dependence of the water contact angle on calcite in the presence of CO2. Our results suggest that the contact angle of a cylindrical droplet, is independent of droplet size, for droplets with a radius of 50 Å or more. On the contrary, spherical droplets make a contact angle that is strongly influenced by their size. At the largest size explored in this study, both spherical and cylindrical droplets converge to the same contact angle, 38°, indicating that calcite is strongly wetted by water.

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Section: Introductionmentioning

confidence: 99%

Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects

et al. 2019

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“…During the first decades of CO 2 storage, a possibility of CO 2 leakage may occur, when the capillary threshold pressure is reached; this may lower the structural trapping capacity and the overall efficiency of CO 2 sequestration [46,47,98]. Although shales display ultra-low permeability, they might still have a possibility of CO 2 breakthrough depending on the presented minerals [42,48].…”

Section: Surface Wettabilitymentioning

confidence: 99%

A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales

et al. 2020

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Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.

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“…Low-salinity waterflooding is one such process that causes wettability modification and leads to higher oil recovery [28]; several mechanisms have been proposed to explain the effect, although there has been no consensus [29][30][31][32][33][34]. Wettability modification will also occur in rock-oil-CO 2 systems [35], due to the fact that CO 2 reduces the viscosity of crude oil [36] and leads to asphaltene precipitation [37,38] during the oil-CO 2 interaction. Thus, wettability should be expected to evolve during subsurface engineering endeavors involving perturbations of pore fluid composition, rather than being a simple fixed parameter for a given reservoir rock type.…”

Section: Variability and Evolution Of Wettability During Ccus/eor In mentioning

confidence: 99%

Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

et al. 2019

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The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

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Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems:Critical parametric analysis and future outlook

Cited by 173 publications

References 132 publications

Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects

Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects

A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales

Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

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Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems:Critical parametric analysis and future outlook

Cited by 173 publications

References 132 publications

Wetting Properties of the CO2–Water–Calcite System via Molecular Simulations: Shape and Size Effects

Wetting Properties of the CO2–Water–Calcite System via Molecular Simulations: Shape and Size Effects

A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales

Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

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Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects

Wetting Properties of the CO₂–Water–Calcite System via Molecular Simulations: Shape and Size Effects