Steady‐state supercritical <scp>CO</scp><sub>2</sub> and brine relative permeability in <scp>B</scp>erea sandstone at different temperature and pressure conditions

Chen, Xiongyu; Gao, Shuang; Kianinejad, Amir; DiCarlo, David A.

doi:10.1002/2017wr020810

Cited by 20 publications

(4 citation statements)

References 42 publications

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“…From the top to bottom (flow direction), oil saturation in fracture increased from 7% to 67% for Exp A and from 5% to 36% for Exp B. Increase of wetting phase saturation with flow direction was also observed in previous experiments due to capillary continuity toward the outlet. − In comparison, fracture oil saturation after gas C injection in Exp C was 3% without vertical variations. The reason for lower S org in fracture and less vertical variations for Exp C is due to gas C having the lowest IFT and capillary pressure.…”

Section: Resultssupporting

confidence: 65%

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

Chen

Mohanty

2021

Energy Fuels

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This work studies oil displacement by gas and foam in a fractured lowpermeability oil-wet carbonate rock. In the three experiments conducted, gas is a methane−ethane mixture whose ethane mole fractions are 0.25, 0.50, and 0.65 (nearmiscible), respectively. We use calibrated in situ μCT to quantify oil saturation evolution in the fracture and the matrix and observe pore-scale displacements. As the ethane mole fraction in gas increases, gas−oil interfacial tension (IFT) and capillary pressure decrease and residual oil in the fracture pores after gas injection retreats from pore to throat and then to grain contact. With decreasing IFT, residual oil saturation after gas (S org ) decreases from 24% to 15% and to 3% in the fracture and decreases from 76% to 60% and to 12% in the matrix, respectively. Higher S or in the matrix is due to the matrix permeability being orders of magnitude lower than the fracture permeability. During foam flow, foam ruptures in the fracture pores and at the fracture−matrix interface when foam contacts oil or enters pores less than half of the foam bubble size (100−150 μm). As a result, gas is delivered into the matrix; gas pressure released from ruptured bubbles mobilizes oil, decreasing S or after foam to at most 56%, 23%, and 6%, respectively for the three experiments. Particularly, matrix oil saturation after gas and foam is radially uniform for the near-miscible gas but increases radially from the fracture−matrix interface for gases with higher IFT. This suggests oil displacement by near-miscible gas and foam benefits from the synergy of low-IFT capillary invasion and mass transfer across gas−oil interfaces.

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Section: Resultssupporting

confidence: 65%

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

Chen

Mohanty

2021

Energy Fuels

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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%

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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“…Changes in the overburden or pore pressure can alter pore structure and fluid distribution, impacting relative permeability [23][24][25][26]. Temperature affects fluid viscosity and interfacial tension, thus influencing fluid flow and relative permeability in the reservoir [27][28][29][30][31][32].…”

Section: Introductionmentioning

confidence: 99%

Effect of Displacement Pressure Gradient on Oil–Water Relative Permeability: Experiment, Correction Method, and Numerical Simulation

Wu,

Zhang,

Liu

et al. 2024

Processes

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Relative permeability is a fundamental parameter affecting reservoir development performance analysis. During the development of oil and gas fields, the displacement pressure gradient changes with time and space. This paper studies the effect of displacement pressure gradient on relative permeability. The oil–water relative permeability curves of a Bohai Oilfield under different displacement pressure gradients are obtained through experimental analysis. Based on the experimental data, a correction model of the permeability curve is established by regression of the Willhite model parameters. The correction model is introduced into the black oil numerical simulation, and the production performance and remaining oil are compared and analyzed. The results show that the displacement pressure gradient can have an obvious impact on the relative permeability curve. As the displacement pressure gradient increases, the two-phase span of the relative permeability curve increases, the oil displacement efficiency increases, and the water relative permeability increases. The relative permeability curves under different displacement pressure gradients can be accurately characterized by the Willhite model. The consideration of the displacement pressure gradient has an obvious impact on numerical simulation results. The conventional method of using a fixed relative permeability curve cannot truly reflect the production performance and the remaining oil distribution. This paper proposes a set of realization methods including obtaining laws from experiments, utilizing the empirical model to correct, and simulating to characterize reservoir changes.

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Steady‐state supercritical CO₂ and brine relative permeability in Berea sandstone at different temperature and pressure conditions

Cited by 20 publications

References 42 publications

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

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

Effect of Displacement Pressure Gradient on Oil–Water Relative Permeability: Experiment, Correction Method, and Numerical Simulation

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Steady‐state supercritical CO2 and brine relative permeability in Berea sandstone at different temperature and pressure conditions

Cited by 20 publications

References 42 publications

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

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

Effect of Displacement Pressure Gradient on Oil–Water Relative Permeability: Experiment, Correction Method, and Numerical Simulation

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Steady‐state supercritical CO₂ and brine relative permeability in Berea sandstone at different temperature and pressure conditions