Characterization of two- and three-phase relative permeability of water-wet porous media through X-Ray saturation measurements

Moghadasi, Leili; Guadagnini, Alberto; Inzoli, Fabio; Bartošek, Martin; Renna, D.

doi:10.1016/j.petrol.2016.05.031

Cited by 27 publications

(22 citation statements)

References 22 publications

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“…We start by evaluating the single-(wetting) phase steadystate flow in the available pore space as a baseline for comparison. We then simulate the flow of oil (with subscript nw, nonwetting phase) and water (with subscript w, wetting phase) characterized by a density ratio γ = ρ nw /ρ w = 0.78 and by a viscosity ratio η = μ nw /μ w = 2.87, values typically encountered in two-phase core-flooding experiments [34]. Water wets the solid with a uniform contact angle of 60 • .…”

Section: A Simulation Scenariosmentioning

confidence: 99%

Pore-scale velocities in three-dimensional porous materials with trapped immiscible fluid

et al. 2019

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We study and document the influence of wetting and nonwetting trapped immiscible fluid on the probability distribution of pore-scale velocities of the flowing fluid phase. We focus on drainage and imbibition processes within a three-dimensional microcomputed tomographic image of a real rock sample. The probability distribution of velocity magnitude displays a heavier tail for trapped nonwetting than wetting fluid. This behavior is a signature of marked changes in the distribution and strength of preferential flow paths promoted by the wettability property of the trapped fluid. When the latter is wetting the host solid matrix, high-velocity areas initially present during single-phase flow conditions are mainly characterized by increased or decreased velocity magnitudes, and the velocity field remains correlated with its counterpart associated with the single-phase case. Otherwise, when the trapped fluid is nonwetting, features that are observed to prevail are appearance and disappearance of high-velocity areas and a velocity field that is less correlated to the one obtained under single-phase conditions.

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Section: A Simulation Scenariosmentioning

confidence: 99%

Pore-scale velocities in three-dimensional porous materials with trapped immiscible fluid

et al. 2019

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“…Caudle et al (1951) were among the first to highlight the impact of hysteresis effects (hereinafter denoted as HEs) on the values of relative permeability of a non-wetting phase. Occurrence of such effects for the non-wetting and the intermediate wetting phases have been documented by a set of experimental (e.g., Oak, 1990;Alizadeh and Piri, 2014a;Moghadasi et al, 2016) and theoretical (e.g., Killough, 1976;Carlson, 1981;Larsen and Skauge, 1998;Blunt, 2000;Shahverdi and Sohrabi, 2013;Kianinejad et al, 2015;Ranaee et al, 2017Ranaee et al, , 2016 studies. The main reasons underpinning the lack of reversibility of the saturation paths observed under three-phase conditions are (i) trapping of the nonwetting phase during imbibition, (ii) remobilization of the intermediate phase through a layer drainage displacement mechanism, and (iii) wettability alteration (change) during drainage and imbibition (Piri and Blunt, 2005;Van Dijke et al, 2006;Suicmez et al, 2007;Sohrabi et al, 2008).…”

Section: Introductionmentioning

confidence: 97%

“…Hysteresis effects on water can be neglected under water-wet conditions. Otherwise, they should be captured when evaluating gas and oil relative permeabilities, as documented by experimental evidences Di Carlo et al, 2000;Alizadeh and Piri, 2014b;Moghadasi et al, 2016) and theoretical analyses (Piri and Blunt, 2005;Spiteri and Juanes, 2006;Van Dijke et al, 2006;Bianchi Janetti et al, 2015). Some classical three-phase relative permeability models allow including HEs on gas relative permeability by updating model parameters at a given location in the reservoir according to the calculated changes of the saturation path.…”

Section: Introductionmentioning

confidence: 99%

Numerical Assessment Of Water Alternating Gas Practices In The Presence Of Hysteresis Effects On Relative Permeability

Ranaee¹,

Inzoli²,

Riva³

et al. 2018

Proceedings

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Water Alternating Gas (WAG) injection is one of the most successful enhanced oil recovery approaches. Properly accounting for the hysteretic effects of relative permeabilities is a critical issue encountered in numerical simulations of WAG at the mesoscale. Ranaee et al. (2015) proposed a sigmoid-based model for three-phase oil relative permeability, incorporating key physical effects taking place at the pore scale. The model can then be jointly used with the Larsen and Skauge (1998) model, accounting for gas relative permeability hysteresis, to develop a formulation for three-phase relative permeability suitable for reservoir simulation. In this study we illustrate the impact of this joint formulation on a field scale setting through a suite of numerical simulations of WAG injection targeting a reservoir model inspired to real life cases. The analysis is performed by embedding the illustrated relative permeability models in the black oil model implemented in the Matlab Reservoir Simulation Toolbox (Lie et al., 2011). We assume non-hysteretic behavior for water relative permeability under water-wet conditions and characterize it upon relying on corresponding laboratory-scale data. As a baseline, the results are compared against a scenario in the absence of three-phase relative permeability hysteresis. The computational domain is heterogeneous, the spatial distributions of porosity and absolute permeability varying across the ranges of [0.02 -0.3] and [0.1 -2600 mD], respectively. The model is set at equilibrium conditions, production being driven by three peripheral injectors and five up-dip producers. A given flow rate is assigned to each injector and a target value of liquid production rate is imposed at the producing wells. The numerically evaluated production rates constitute our target state variables. The schedule of the injectors is set to achieve a preliminary waterflooding phase followed by a WAG injection scheme. The latter is implemented by periodically switching the injected phase between water and gas for two injectors, the third injector continuously injecting water. The numerical simulations are performed through a fully implicit discretization of the equations governing the system dynamics. To minimize computational costs, we employ an algebraic multi-grid method and resort to a multi-processor high performance clustered computer system. Our results suggest that hysteretic effects are important across significant portions of the studied reservoir system. Field production responses are associated with a simultaneous increase of ultimate oil recovery and a corresponding decline of the gas-oil ratio when hysteretic effects are included in the simulations.

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“…Concurrent improvements of X‐ray microtomography combined with its nondestructive features have allowed direct visualization of pore‐scale structures and distribution of phases as inputs to computational models. A number of authors have investigated pore‐scale phases distribution using X‐ray microtomography and demonstrated the complexity of the nonwetting and wetting phase interface geometry (e.g., Armstrong et al, ; Blunt et al, ; X. Chen & DiCarlo, ; X. Chen et al, ; Gao et al, ; Garing et al, ; Moghadasi et al, ; Prodanovic et al, , ; Reynolds et al, ).…”

Section: Introductionmentioning

confidence: 99%

“…A number of authors have investigated pore-scale phases distribution using X-ray microtomography and demonstrated the complexity of the nonwetting and wetting phase interface geometry (e.g., Armstrong et al, 2014;Blunt et al, 2013;X. Chen et al, 2017;Gao et al, 2017;Garing et al, 2017;Moghadasi et al, 2016;Prodanovic et al, 2007Prodanovic et al, , 2015Reynolds et al, 2017).…”

Section: Introductionmentioning

confidence: 99%

The Impact of Pore‐Scale Flow Regimes on Upscaling of Immiscible Two‐Phase Flow in Porous Media

Picchi

Battiato

2018

Water Resources Research

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Empirical or theoretical extensions of Darcy's law for immiscible two‐phase flow have shown significant limitations in properly modeling the flow at the continuum scale. We tackle this problem by proposing a set of upscaled equations based on pore‐scale flow regimes, that is, the topology of flowing phases. The incompressible Navier‐Stokes equation is upscaled by means of multiple‐scale expansions and its closures derived from the mechanical energy balance for different flow regimes at the pore scale. We also derive the applicability conditions of the upscaled equations based on the order of magnitude of relevant dimensionless numbers, that is, Eotvos, Reynolds, capillary, Froude numbers, and the viscosity and density ratio of the system, as well as a set of closures valid for the basic flow regimes of low Eotvos number systems, that is, core‐annular and plug and drop traffic flows. We provide analytical expressions for the relative permeability of the wetting and nonwetting phases in different flow regimes and demonstrate that the effect of the flowing‐phases topology on the relative permeabilities is significant. Finally, we show that the classical two‐phase Darcy law is recovered for a limited range of operative conditions, while specific terms accounting for interfacial and wall interactions should be incorporated to accurately model ganglia or drop traffic flow.

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Characterization of two- and three-phase relative permeability of water-wet porous media through X-Ray saturation measurements

Cited by 27 publications

References 22 publications

Pore-scale velocities in three-dimensional porous materials with trapped immiscible fluid

Pore-scale velocities in three-dimensional porous materials with trapped immiscible fluid

Numerical Assessment Of Water Alternating Gas Practices In The Presence Of Hysteresis Effects On Relative Permeability

The Impact of Pore‐Scale Flow Regimes on Upscaling of Immiscible Two‐Phase Flow in Porous Media

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