Relative Permeability of Near-Miscible Fluids in Compositional Simulators

Alzayer, A.; Voskov, Denis

doi:10.1007/s11242-017-0950-9

Cited by 13 publications

(6 citation statements)

References 27 publications

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“…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%

“…The limitation of the method is that it needs to perform experiments which are time-consuming and costly. Alzayer et al (2018) adopted the Gibbs free energy to determine the interpolation parameter, which required a complex calculation process. Coats pointed out that the treatment given here was not based on any theory or experimental evidence.…”

Section: Relative Permeability Of Gas/oil Systemmentioning

confidence: 99%

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%

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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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“…Besides the critical gas saturation S gc , the associated liquidgas relative permeabilities are perhaps even more important parameters, in particular for dynamic modelling [8,9,56]. Because of all the complications already discussed, experimental measurements of relative permeability by applying pressure gradients causing flow are problematic, as this starts interfering with pore scale flow regimes.…”

Section: Relative Permeabilitymentioning

confidence: 99%

Capillarity and phase-mobility of a hydrocarbon gas–liquid system

Gao

Georgiadis

Brussee

et al. 2021

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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When oil fields fall during their lifetime below the bubble point gas comes out of solution. The key questions are at which saturation the gas becomes mobile (“critical gas saturation”) and what the gas mobility is, because mobile gas reduces the production of oil significantly. The traditional view is that the gas phase becomes mobile once gas bubbles grow or expand to a size where they connect and form a percolating path. For typical 3D porous media the saturation corresponding to this percolation limit is on the order of 20%. However, significant literature report on gas mobility below lower limits of percolation thresholds i.e. below 0.1%. A direct experimental insight for that is lacking because laboratory measurements are notoriously difficult since the formation of gas bubbles below the bubble point includes thermodynamic and kinetic aspects, and the pressure decline rates achievable in laboratory experiments are orders of magnitude higher than the decline rates in the field. Here we study the nucleation and transport of gas coming out of solution in-situ in 3D rock using X-ray computed micro tomography which allows direct visualization of the nucleation kinetics and connectivity of gas. We use either propane or a propane–decane mixture as model system and conduct pressure depletion in absence of flow finding that – consistent with the literature – observation of the bubble point in the porous medium is decreased and becomes pressure decline rate dependent because of the bubble nucleation kinetics. That occurs in single-component systems and in hydrocarbon mixtures. Pressure depletion in absence of flow results in critical gas saturations between 20 and 30% which is consistent with typical percolation thresholds in 3D porous structures. That does not explain experimentally observed critical gas saturations significantly below 20%. Also, the respective pore level fluid occupancy where pores are filled with either gas or liquid phase but not partially with both as in normal 2-phase immiscible systems rather diminishes connectivity of gas and liquid phases. This observation indicates that likely other mechanisms play a role in establishing gas mobility at saturations significantly below 20%. Experiments under flow conditions, where gas is injected near the bubble point suggest that diffusion may significantly contribute to the transport of gas and may even be the dominant transport mechanism at field relevant flow rates. The consequence of diffusive transport are compositional gradients where locally the composition is such gas nucleation may occur. That would lead to a disconnected but mobile gas distribution ahead of the convective front. Furthermore, diffusive exchange leads to ripening and anti-ripening effects which influences the distribution for which we see evidence in pressure depletion experiments but not so much at low rate gas injection. Respective relative permeability computed from the imaged fluid distributions using a lattice Boltzmann approach show distinctly different behavior between pressure depletion and flowing conditions. These findings suggest that capillarity in a gas–liquid hydrocarbon mixture is far more complex than in a 2-phase immiscible system. Capillarity is coupled to phase behavior thermodynamics and kinetics on a fast time scale and diffusion-dominated mechanisms such as ripening and anti-ripening effects at a slow time scale. While the consequences for the current experimental and field modelling approaches are not yet fully clear, this shows that more research is needed to fully understand these effects and their implications.

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“…This assumption is physically unreal and may have undesirable consequences when the correlation is used in simulations. The other limitations of this method have been studied by Al-Zayer (2015). He explained that although scaling of residual saturations and relative permeability endpoints might be used as possible solutions, there are not physical reasons for some of these treatments.…”

Section: Evaluation Of Relative Permeability Using Trapping Numbermentioning

confidence: 99%

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

Neshat

Pope

2017

Day 1 Mon, February 20, 2017

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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 of Near-Miscible Fluids in Compositional Simulators

Abstract: Important noteTo cite this publication, please use the final published version (if applicable). Please check the document version above.

Cited by 13 publications

References 27 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

Capillarity and phase-mobility of a hydrocarbon gas–liquid system

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

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