A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation

Hustad, Odd Steve; Browning, David John

doi:10.2118/125429-pa

Cited by 31 publications

(10 citation statements)

References 18 publications

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“…The model further revised by many researchers and widely used in commercial simulators, such as Eclipse and CMG (Al-Nuaimi et al, 2018;Coats, 1980;GeoQuest, 2014;Hustad and Browning, 2010). This is a simple and practical approach to evaluate the effect of miscibility on the relative permeability.…”

Section: Relative Permeability Of Gas/oil Systemmentioning

confidence: 99%

“…Compared with the traditional way, the technique showed good results and the overall numerical error was reduced. The interpolation parameter is the function of IFT in these models (Al-Nuaimi et al, 2018;Alzayer et al, 2018;Hustad and Browning, 2010;Mott et al, 2000). Mott et al and Al-Nuaimi et al established empirical formulas to determine the interpolation parameter by fitting the experimental data (Al-Nuaimi et al, 2018;Mott et al, 2000).…”

Section: Relative Permeability Of Gas/oil Systemmentioning

confidence: 99%

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Analytical solution of Buckley-Leverett equation for gas flooding including the effect of miscibility with constant-pressure boundary

Chen

et al. 2019

Energy Exploration & Exploitation

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This paper presents an analytical solution of Buckley-Leverett equation for gas flooding with constant-pressure boundary including the effect of miscibility on the viscosity and relative permeability. First, a relative permeability model and a viscosity model with consideration of miscibility are used to describe the variations of relative permeability and viscosity of oil and gas. Then, based on the fractional-flow theory, the Buckley-Leverett equation for gas flooding with constantpressure boundary including the effect of miscibility is constructed and solved analytically. From the analytical solution, the saturation and pressure profiles, the total volumetric flux and the breakthrough time are determined. To verify the theory, the analytical solution is compared with the numerical solution. The comparison shows that the analytical solution is in reasonable agreement with numerical solution. Through the study on the influential factors, it can be concluded that total volumetric flux is increasing with the increases of permeability and pressure and decrease of gas viscosity. The increase of total volumetric flux accelerates breakthrough of the injected gas. Furthermore, with the pressure increase, there are remarkable reduction in residual oil saturation and improvement of relative permeability, resulting in higher gas saturation and oil displacement efficiency. The analytical solution presented in this paper provides guidance on analyzing the distribution of saturation and pressure profiles, predicting the gas production and oil recovery efficiency of oil well.

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Section: Relative Permeability Of Gas/oil Systemmentioning

confidence: 99%

Section: Relative Permeability Of Gas/oil Systemmentioning

confidence: 99%

Analytical solution of Buckley-Leverett equation for gas flooding including the effect of miscibility with constant-pressure boundary

Chen

et al. 2019

Energy Exploration & Exploitation

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“…A more sophisticated computation of three-phase capillary pressures and relative permeabilities, including hysteresis effects, was proposed in Hustad and Browning (2010).…”

Section: Mixed Fe Methods For Fluxes and Pressuresmentioning

confidence: 99%

Three-Phase Compositional Modeling With Capillarity in Heterogeneous and Fractured Media

Moortgat

Firoozabadi

2013

SPE Journal

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We model for the first time capillarity in fully compositional three-phase flow, with higher-order finite-element (FE) methods. Capillary pressure gradients may be an important driving force, particularly in layered or fractured porous media, which exhibit sharp discontinuities in permeability. We introduce a simple local computation of the capillary pressure gradients, propose a fractional-flow formulation in terms of the total flux, and resolve complications arising from gravity and capillarity in the upwinding of phase fluxes. Fractures are modeled with the crossflow equilibrium concept, which allows large timesteps and includes all physical interactions between fractures and matrix blocks. The pressure and flux fields are discretized by the mixed hybrid finite-element method, and mass transport is approximated by a higher-order local discontinuous Galerkin (DG) method. Numerical-dispersion and grid-orientation effects are significantly reduced, which allows computations on coarser grids and with larger timesteps. The main advantages in the context of this work are the accurate pressure gradients and fluxes at the interface between regions of different permeabilities. The phase compositions are computed with state-of-the-art phase-splitting algorithms and stability analyses to guarantee the global minimum of Gibbs free energy. Accurate compositional simulation motivates the use of an implicitpressure/explicit-composition (IMPEC) scheme, and we discuss the associated Courant-Friedrichs-Lewy (CFL) condition on the timesteps. We present various numerical examples on both core-and large-scale, illustrating the capillary end effect, capillary-driven crossflow in layered media, and the importance of capillarity in fractured media for three-phase flow.

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“…Tight/shale reservoirs are featured with nanoscale pores. It is well-established that the confined space in those nanopores introduces large capillary pressure which can pose a significant impact on the phase behavior and flow dynamics of reservoir fluids. − Experimental works and theoretical approaches to describe the vapor–liquid two-phase equilibrium in a confined space are thereby developed to grasp an understanding of the reservoir-fluid phase behavior inside nanopores. − …”

Section: Introductionmentioning

confidence: 99%

Phase-Behavior Modeling of Hydrocarbon Fluids in Nanopores Using PR-EOS Coupled with a Modified Young–Laplace Equation

Sun

2020

ACS Omega

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The effect of capillary pressure on the vapor–liquid two-phase equilibrium calculation has been extensively studied for the past two decades. However, the calculation accuracy is often weakened by the false assumptions and inherent flaws present in the modeling process. In this work, a modified Young–Laplace equation proposed by Tan and Piri [Tan, S.; Piri, M. Equation-of-State Modeling of Confined-Fluid Phase Equilibria in Nanopores. Fluid Phase Equilibr. 2015, 393, 48–63.] is coupled with volume-translated Peng–Robinson equation of state to study the effect of capillary pressure on the two-phase equilibrium calculation in confined nanopores. In order to successfully apply the modified Young–Laplace equation during the vapor–liquid equilibrium calculation process, this study models the tuning parameter λ in the modified Young–Laplace equation (as proposed by Tan and Piri for perturbed-chain statistical associating fluid theory equation of state) for several pure hydrocarbons and their mixtures by matching experimental data collected from the literature. The tuning parameter λ can be expressed as a unique function for each pure substance or mixture. It is found that the tuning parameter λ shows a quadratic polynomial relationship with temperature, and the value of λ is always less than one. The λ can become negative under certain circumstances, which adjusts the capillary pressure to a lower value. It increases with an increasing pore radius; this is different from the results obtained by Tan and Piri which showed that the tuning parameter λ decreases with an increasing pore radius. The above rules apply to the tuning parameter λ obtained for both pure substances and mixtures. Using the two-phase equilibrium calculation coupled with the modified Young–Laplace equation, the calculated vapor pressures for pure substances and two-phase boundaries for mixtures match very well with the experimental data. Implementation of the modified Young–Laplace equation greatly improves the accuracy of the two-phase equilibrium calculation considering the capillarity effect. Such a modeling strategy could be integrated into a reservoir simulator to conduct more accurate flow simulations for tight/shale reservoirs.

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A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation

Cited by 31 publications

References 18 publications

Analytical solution of Buckley-Leverett equation for gas flooding including the effect of miscibility with constant-pressure boundary

Analytical solution of Buckley-Leverett equation for gas flooding including the effect of miscibility with constant-pressure boundary

Three-Phase Compositional Modeling With Capillarity in Heterogeneous and Fractured Media

Phase-Behavior Modeling of Hydrocarbon Fluids in Nanopores Using PR-EOS Coupled with a Modified Young–Laplace Equation

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