Impact of mineralogy and wettability on pore-scale displacement of NAPLs in heterogeneous porous media

Arshadi, Maziar; Gesho, Masakazu; Qin, Tianzhu; Goual, Lamia; Piri, Mohammad

doi:10.1016/j.jconhyd.2020.103599

Cited by 24 publications

(9 citation statements)

References 60 publications

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“…Multiphase flow through porous media has a crucial importance in applications as diverse as groundwater resources [1][2][3], geothermal fields [4], chemical transport [5][6][7], gas diffusion in fuel cells [8], oil recovery [9], environmental remediation [10], and CO 2 sequestration [11]. The most important macroscopic parameters that describe multiphase flow through porous media are capillary pressure (P c ) and relative permeability (k r ) [9,12].…”

Section: Introductionmentioning

confidence: 99%

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

et al. 2020

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A pore-network model is an upscaled representation of the pore space and fluid displacement, which is used to simulate two-phase flow through porous media. We use the results of pore-scale imaging experiments to calibrate and validate our simulations, and specifically to find the pore-scale distribution of wettability. We employ energy balance to estimate an average, thermodynamic, contact angle in the model, which is used as the initial estimate of contact angle. We then adjust the contact angle of each pore to match the observed fluid configurations in the experiment as a nonlinear inverse problem. The proposed algorithm is implemented on two sets of steady state micro-computed-tomography experiments for water-wet and mixed-wet Bentheimer sandstone. As a result of the optimization, the pore-by-pore error between the model and experiment is decreased to less than that observed between repeat experiments on the same rock sample. After calibration and matching, the model predictions for capillary pressure and relative permeability are in good agreement with the experiments. The proposed algorithm leads to a distribution of contact angle around the thermodynamic contact angle. We show that the contact angle is spatially correlated over around 4 pore lengths, while larger pores tend to be more oil-wet. Using randomly assigned distributions of contact angle in the model results in poor predictions of relative permeability and capillary pressure, particularly for the mixed-wet case.

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Section: Introductionmentioning

confidence: 99%

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

et al. 2020

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“…Yet, to the best of our knowledge, they have never been used in the past to study carbonaceous nanoparticles under HPHT conditions. Computation of saturation profiles and in-situ wettability distributions could be further utilized to inform the development of novel nanomaterials with enhanced EOR performance 36 – 38 .…”

Section: Introductionmentioning

confidence: 99%

Pore-scale experimental investigation of oil recovery enhancement in oil-wet carbonates using carbonaceous nanofluids

Zhang

Mohamed

Goual

et al. 2020

Sci Rep

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This study investigates the pore-scale displacement mechanisms of crude oil in aged carbonate rocks using novel engineered carbon nanosheets (E-CNS) derived from sub-bituminous coal. The nanosheets, synthesized by a simple top-down technique, were stable in brine without any additional chemicals. Owing to their amphiphilic nature and nano-size, they exhibited dual properties of surfactants and nanoparticles and reduced the oil/brine interfacial tension (IFT) from 14.6 to 5.5 mN/m. X-ray micro-computed tomography coupled with miniature core-flooding was used to evaluate their ability to enhance oil recovery. Pore-scale displacement mechanisms were investigated using in-situ contact angle measurements, oil ganglia distribution analysis, and three-dimensional visualization of fluid occupancy maps in pores of different sizes. Analysis of these maps at the end of various flooding stages revealed that the nanofluid invaded into medium and small pores that were inaccessible to base brine. IFT reduction was identified as the main displacement mechanism responsible for oil recovery during 1 to 8 pore volumes (PVs) of nanofluid injection. Subsequently, wettability alteration was the dominant mechanism during the injection of 8 and 32 PVs, decreasing the average contact angle from 134° (oil wet) to 85° (neutral wet). In-situ saturation data reveals that flooding with only 0.1 wt% of E-CNS in brine resulted in incremental oil production of 20%, highlighting the significant potential of this nanofluid as a recovery agent.

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“…The wettability of reservoir rocks has important consequences for fluid flow in geological systems, with relevant applications including carbon sequestration, recovery of oil and gas, and management of water resources (Arshadi et al, 2020; Benson & Cole, 2008; Kovscek & Cakici, 2005; Spiteri et al, 2008). Wettability refers to the relative preference of one fluid over another to coat the rock surface, which is commonly characterized by the contact angle at the liquid‐solid interface (Anderson, 1986).…”

Section: Introductionmentioning

confidence: 99%

Influence of Clay Wettability Alteration on Relative Permeability

Fan

McClure

Armstrong

et al. 2020

Geophysical Research Letters

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Understanding the wettability of porous materials is important to model fluid flow in the subsurface. One of the critical factors that influences wetting in real reservoirs is the composition of geologic materials. The wetting properties for clay minerals can have a particularly strong impact on flow and transport. In this work, we analyze the chemical composition of a Mt. Simon sandstone core to resolve the microscopic structure of clay regions and assess how alterations to the local wetting properties influence multiphase transport based on core flooding experiments and relative permeability simulations. We show that whichever fluid has greater affinity toward clay minerals will tend to accumulate within these high surface area regions, leading to dramatic shifts in the relative permeability. This work establishes the essential importance of the mineral composition and associated wetting properties in the modeling of flow and transport in reservoir-scale systems. Plain Language Summary Surface interactions between fluid and solid materials have important consequences for underground fluid flow. Wettability refers to the relative preference for one fluid to coat the solid surface when multiple fluids are present. Exposure to different fluids can dramatically alter the wettability for mineral surfaces in geological systems, which can have a significant effect on multiphase flow in geological reservoirs. We show that alteration of the wetting properties for clay regions can dramatically alter the behavior for water and CO 2 to flow through reservoir rocks. The underlying causes for these effects are understood by examining microscopic fluid configurations obtained based on the composition of geologic materials. A deeper comprehension of CO 2 flow and transport behavior in a reservoir rock with high mineralogical heterogeneities will aid the CO 2 storage capacity prediction and reduce CO 2 leakage potential.

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Impact of mineralogy and wettability on pore-scale displacement of NAPLs in heterogeneous porous media

Cited by 24 publications

References 60 publications

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

Pore-scale experimental investigation of oil recovery enhancement in oil-wet carbonates using carbonaceous nanofluids

Influence of Clay Wettability Alteration on Relative Permeability

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