Single- and Two-Phase Flow in Natural Fractures

Rossen, W.R.; Kumar, Animesh

doi:10.2523/24915-ms

Cited by 13 publications

(11 citation statements)

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“…The pores occupied by one phase are not available for the flow of the other. In a smooth parallel-plate fracture, such as the one in our experiments, the capillary phase occupancy criterion is not applicable (11) , because of the uniform size of the aperture. Under the test conditions, the maximum capillary pressure is 1.25 kPa for the fracture of 45 mm aperture.…”

Section: Resultsmentioning

confidence: 99%

“…The friction factor, φ, in Equation (10) (11) where C and n are constants determined from experiment. For laminar flow n=1 ( 7 ) , Re m is the mean Renolds number for twophase flow, which is defined by, (12) where µ m is the mean viscosity defined by (10) : ......................................................................(13) In the case of laminar flow (Re m < 1 , 0 0 0 ( 6 ) ), substituting Equation (11) and (12) into Equation (10) It is noted that the deduction of the above Equation (14) is based on n=1.…”

Section: Homogeneous Single-phase Approachmentioning

confidence: 99%

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Steady State Immiscible Oil And Water Flow In a Smooth-walled Fracture

Pan

Wong

Maini

1998

Journal of Canadian Petroleum Technology

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Steady state immiscible oil/water flow experiments were conducted in horizontal smooth-walled fractures. The effects of fracture aperture, injection rate and injection method on the immiscible flow characteristics were investigated. The experimental data were analysed using a porous medium approach and an equivalent homogeneous single-phase method. The pressure gradients predicted by the latter are in good agreement with those measured in the experiments. Contrary to the well-known Romm's relative permeability versus saturation correlation, the experimental data indicated that the sum of the relative permeabilitiesis less than one over a range of saturation, which is attributed to the effect of phase interference on the immiscible flow. The effect of phase interference is more significant in the case of well mixed oil/water flow than otherwise. The results also indicate that the fracture aperture does not have a significant influence on the relative permeabilities of oil and water flow in smooth-walled fractures. Introduction Investigation of fluid flow in porous and fractured media is of practical importance in areas such as the recovery of oil and gas, the isolation and remediation of nuclear and toxic wastes in geological formation, and the exploitation of geothermal energy. In these applications, fluid flow in fractured media is often dominated by the highly permeable pathways provided by rock fractures, either natural or induced. Understanding the mechanics, which govern the multiphase flow in fractures, will certainly help to improve the energy recovery efficiency and optimize the waste isolation and remediation process. It is well known that the flow of multiphase fluids in a porous medium is generally governed by the saturation of the pore space occupied by the percolating fluids. Pores occupied by one phase are not available for the flow of the other, which implies that each phase interferes with the flow of the other. At steady state, only the portion that forms a continuous path contributes to the fluid production, whereas the discontinuous portion is considered to be immobile. The phase interference is attributed to the capillary forces developed at the contact zones of the fluid phases in the pore channels. The smaller the size of the pores, the more significant will be the effect of capillary forces. To quantify the interference between different fluids, relative permeability functions are introduced and defined as: Equation 1 (available in full paper) where ki is the effective permeability to phase i, k is the absolute permeability of the medium, and kri is the relative permeability to phase i. Numerous experimental studies have shown that the relative permeabilities of multiphase flow in porous media are strong functions of phase saturation and phase saturation is governed by capillary forces. It is postulated that phase interference also exists in multiphase flow in fractures. However, the mechanisms governing the phase interference in a fracture is not well understood. The physics of fluid flow in a fracture is different from that in a homogeneous porous medium. Unlike the three-dimensional nature of flow in a porous medium, fluid flow in a fracture occurs in a two-dimensional variable aperture plane.

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Section: Resultsmentioning

confidence: 99%

Section: Homogeneous Single-phase Approachmentioning

confidence: 99%

Steady State Immiscible Oil And Water Flow In a Smooth-walled Fracture

Pan

Wong

Maini

1998

Journal of Canadian Petroleum Technology

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“…Numerous models have been proposed to correlate specific saturation-dependent properties, namely relative permeability and capillary pressure curves, with fluid saturation (Brooks & Corey, 1966;Burdine, 1953;Corey, 1954;Kühn, 2004;Pan et al, 1996;Purcell, 1949;Pyrak-Nolte et al, 1988;Romm, 1966;Rossen & Kumar, 1992;Van Genuchten, 1980;Yang et al, 2013). Brooks and Corey's (1966) equations, which define capillary pressure and relative permeability curve as a power-law function of wetting phase saturation, may be the most popular.…”

Section: Two-phase Flowmentioning

confidence: 99%

Consecutive Experimental Determination of Stress‐Dependent Fluid Flow Properties of Berea Sandstone and Implications for Two‐Phase Flow Modeling

Haghi

Talman

Chalaturnyk

2020

Water Resources Research

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In this study, changes in the hydrodynamic properties of Berea sandstone at a constant temperature of 40°C are reported as effective confining stress is increased to 30 MPa. Through a novel consecutive approach, porosity, absolute permeability, drainage relative permeability, and drainage capillary pressure were shown to systematically change with effective stress. The relative permeability measurements were taken using a steady-state method for the N 2 /water fluid pair. A second method, in which a saturated core with the wetting phase was flushed with the non-wetting phase at an increasing flow rate, was used to determine the drainage capillary pressure. Core saturation was determined using a gas separation unit and mass-balance considerations. This study revealed a decrease in porosity and absolute permeability, from 13.16% and 58 mD to 12.24% and 36 mD, respectively, with the increase in effective confining stress. In terms of relative permeability curves, this study showed a systematic decrease in irreducible wetting phase saturation from 0.44 to 0.24 as effective stress increased; this could be interpreted in core-scale as a progressive tendency of the initially water-wet Berea sandstone to the gas phase. The capillary pressure curve also presented an upward shift in response to increased effective stress. These changes in the hydrodynamic rock properties with stress suggest that scaling flow parameters of porous media under effective stress conditions may be required to accurately predict flow behavior under conditions of changing stress.

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“…Both fractured specimens exhibit skewed bell-shaped distributions. Fractures typically have high frequencies of low aperture values and low frequency of large aperture values (Gale 1987;Pruess and Tsang 1990;Rossen and Kumar 1992;Walters et al 1998). The sandstone specimen displays higher arithmetic and geometric means than the shale specimen.…”

Section: Resultsmentioning

confidence: 98%

Single-Phase (Brine) and Two-Phase (DNAPL–Brine) Flows in Induced Fractures

2011

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This study reports an investigation on the characteristics of single-phase (brine) and two-phase (DNAPL-brine) flows in induced fractures. The fracture aperture and fluid phase distributions were determined using X-ray computer tomography. In the single-phase flow tests, the pressure gradient across the induced fractures increases linearly with increasing flow rate. However, models based on the measured aperture do not yield a consistent match with the experimental data because the effect of pressure losses due to aperture variation and undulation are not taken into account. In the two-phase flow tests, the measured phase distributions reveal that the flow pattern is dominated by a dispersed or mixed flow in which either DNAPL or brine phase is discontinuous. The channel flow pattern, in which DNAPL and brine phases are continuous in the fracture and well represented by the widely used Romm's relative permeability relationship was not observed in this study. In contrast, a Lockhart-Martinelli-type correlation developed for gas-liquid flow in pipes was found to match the pressure gradient and phase saturation results obtained from the laboratory tests.

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Single- and Two-Phase Flow in Natural Fractures

Cited by 13 publications

References 0 publications

Steady State Immiscible Oil And Water Flow In a Smooth-walled Fracture

Steady State Immiscible Oil And Water Flow In a Smooth-walled Fracture

Consecutive Experimental Determination of Stress‐Dependent Fluid Flow Properties of Berea Sandstone and Implications for Two‐Phase Flow Modeling

Single-Phase (Brine) and Two-Phase (DNAPL–Brine) Flows in Induced Fractures

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