Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

Beygi, Mohammad R.; Delshad, Mojdeh; Pudugramam, Sriram; Pope, Gary A.; Wheeler, Mary F.

doi:10.2118/165324-pa

Cited by 49 publications

(10 citation statements)

References 63 publications

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“…The conventional method described in the preceding paragraph has been used for decades, but it has been a difficult problem to assign physically correct identities to equilibrium phases (Yuan and Pope 2012). Particularly, the use of a fixed mass-density threshold is known to be problematic for phase labeling in a two-phase region in three-hydrocarbon-phase flow simulation (Mohanty et al 1995;Li et al 2014;Beygi et al 2014). This type of failures will be shown in cases studied in this paper.…”

Section: Formulation and Solution Methodsmentioning

confidence: 99%

“…However, the research was limited in terms of thermodynamic and flow conditions. For example, how phase mobilities affect the interphase mass transfer was not studied in detail, due to the lack of robust phase identification in EOS compositional simulation (Mohanty et al 1995;Yuan and Pope 2012;Beygi et al 2014). Phase identification is always part of the solution of a multiphase flow problem, and is usually required to assign relative permeabilities to phases in simulation.…”

Section: Introductionmentioning

confidence: 99%

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Numerical Simulation of Three-Hydrocarbon-Phase Flow with Robust Phase Identification

Xu¹,

Okuno²

2015

SPE Reservoir Simulation Symposium

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Low-temperature oil displacement by enriched-gas or carbon-dioxide (CO 2 ) can exhibit multiphase flow of three hydrocarbon phases; the oleic (L 1 ), solvent-rich liquid (L 2 ), and gaseous (V) phases. The L 2 phase can play a significant role in these oil recovery processes. Recently, oil displacement by three hydrocarbon phases was explained on the basis of interphase mass transfer on phase transitions in multiphase flow. However, systematic investigation into the complex interplay between phase behavior and mobilities has been hindered by issues in multiphase compositional flow simulation, such as incorrect phase identification.This paper presents the effect of relative permeability on oil displacement by three hydrocarbon phases. A new method for robust phase identification is developed and implemented in a 1D convective flow simulator with no volume change on mixing. The new method uses tie triangles and their normal unit vectors tabulated as part of the simulation input information. The extensions of the limiting tie triangles at the upper and lower critical endpoints (UCEP and LCEP) define three different regions in composition space; the super-UCEP, super-LCEP, and sub-CEP regions. The method can properly recognize five different two-phase regions surrounding the three-phase region; the two two-phase regions that are super-CEP, and the three different two-phase regions that originate with the corresponding edges of the three-phase region in the sub-CEP region. Multiphase behavior calculations are conducted rigorously by use of the Peng-Robinson equation of state with the van der Waals mixing rules during the flow simulation. Simulation case studies are presented with a quaternary model and the West Sak oil model with 15 components.Results show that the phase-identification method developed in this research can correctly solve for phase identities in three-hydrocarbon-phase flow simulation. The method can quantify the relative location of the current overall composition to the three-phase region in composition space. Simulation results are analyzed by use of the distance parameters that describe interphase mass transfer on multiphase transitions in oil displacement. In the case study for the West Sak oil displacement, the analysis confirms that the miscibility level of oil displacement increases with increasing methane dilution. The effect of relative permeability diminishes as the miscibility level increases owing to methane dilution. The distance parameters can properly represent the interaction of phase behavior and mobilities since they are derived from mass conservation, not only from thermodynamic conditions.

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Section: Formulation and Solution Methodsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Three-Hydrocarbon-Phase Flow with Robust Phase Identification

Xu¹,

Okuno²

2015

SPE Reservoir Simulation Symposium

View full text Add to dashboard Cite

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“…(2-2) to achieve a better match with his experimental data for two-phase flow in the presence of a third phase residual saturation. This modification was extended later by Beygi et al (2015) to reflect cycle dependency of saturation hysteresis in a three-phase flow. Fayers et al (1984) added the compositional effect to a modified Baker's model and used phase densities to ensure a smooth transition in oil-water and gas-water relative permeabilities.…”

Section: Three-phase Relative Permeability Modelsmentioning

confidence: 99%

Compositional Three-Phase Relative Permeability and Capillary Pressure Models Using Gibbs Free Energy

Neshat

Pope

2017

Day 1 Mon, February 20, 2017

Self Cite

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This paper presents new coupled three-phase relative permeability and capillary pressures models for implementation in a four-phase flow compositional EOS simulator. Identification of hydrocarbon and aqueous phases based on their molar Gibbs free energy is a key feature of the new model. Instead of using phase labels (gas/oil/solvent/aqueous) to define parameters such as relative permeability endpoints, residual saturations and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters including trapping number and hysteresis into one rigorous algorithm for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of miscible WAG and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.

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“…Relative permeability has also been examined to strongly depend on saturation history in cyclic processes, otherwise known as hysteresis. This phenomenon has been extensively investigated experimentally and numerically [14,19,[33][34][35][36]. A few three-phase relative permeability models have been proposed which incorporate hysteresis, compositional and interfacial tension (IFT) effects, these include the Jerauld model [37] which attempts to predict three-phase, gas, oil and water hysteresis as well as relative permeability dependence on composition and gas/oil IFT.…”

Section: Introductionmentioning

confidence: 99%

An Improved Approach to Estimate Three-Phase Relative Permeability Functions for Heavy-Oil Displacement Involving Instability and Compositional Effects

et al. 2017

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Simultaneous three-phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as water-alternating-gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavorable mobility ratio between heavy oil and the displacing fluid. In addition, the injection of partially dissolvable gases such as CO 2 can result in compositional effects, which can bring about a significant reduction of oil viscosity and hence can cause variations of the mobility ratio. Estimations of three-phase relative permeability under such conditions are extremely complex, and using conventional techniques for the estimation can lead to erroneous results. We used the results of four coreflood experiments, carried out on a core, to estimate two-phase and three-phase relative permeability. A new history matching methodology for laboratory experiments was used that takes into account the instability and the compositional effects in the estimation processes. The results demonstrate that a simultaneous CO 2 and water injection (CO 2 -simultaneous water and gas (SWAG)) can be adequately matched using the relative permeabilities of a secondary gas/liquid and a tertiary oil/water. In heavy oil WAG injection, the injected water follows the CO 2 path due its lower resistance as a result of the CO 2 dissolution in the oil and the resultant reduction of the oil viscosity. This is contrary to WAG injection in conventional oils, where gas and water open up separate saturations paths. It is also important to include capillary pressure (Pc), even in high permeable porous media, as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilized, leading to a more realistic simulated sweep efficiency.

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Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

Cited by 49 publications

References 63 publications

Numerical Simulation of Three-Hydrocarbon-Phase Flow with Robust Phase Identification

Numerical Simulation of Three-Hydrocarbon-Phase Flow with Robust Phase Identification

Compositional Three-Phase Relative Permeability and Capillary Pressure Models Using Gibbs Free Energy

An Improved Approach to Estimate Three-Phase Relative Permeability Functions for Heavy-Oil Displacement Involving Instability and Compositional Effects

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