Network Modeling of Gas Trapping and Mobility in Foam Enhanced Oil Recovery

Balan, Huseyin Onur; Balhoff, Matthew T.; Nguyen, Quoc P.; Rossen, W.R.

doi:10.1021/ef2006707

Cited by 43 publications

(19 citation statements)

References 81 publications

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“…(v) Real porous media are of course not bundles of capillaries and it is obvious that this model is not the most realistic one and is therefore unable to take into account nonlinear opening up of pores especially in the vicinity of the yield pressure gradient (Balhoff et al 2012). This is a result of a complex percolation pattern only predictable by solving the pore-level physics (Balan et al 2011). The use of more complex models for porous media such as pore networks would imply the necessity of knowing more details regarding the pore geometry and connectivity (coordination number, pore body-to-pore throat aspect ratio, etc.).…”

Section: Discussionmentioning

confidence: 99%

Toward a New Method of Porosimetry: Principles and Experiments

et al. 2014

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Current experimental methods used to determine pore size distributions (PSD) of porous media present several drawbacks such as toxicity of the employed fluids (e.g., mercury porosimetry). The theoretical basis of a new method to obtain the PSD by injecting yield stress fluids through porous media and measuring the flow rate Q at several pressure gradients ∇ P was proposed in the literature. On the basis of these theoretical considerations, an intuitive approach to obtain PSD from Q(∇ P) is presented in this work. It relies on considering the extra increment of Q when ∇ P is increased, as a consequence of the pores of smaller radius newly incorporated to the flow. This procedure is first tested and validated on numerically generated experiments. Then, it is applied to exploit data coming from laboratory experiments and the obtained PSD show good agreement with the PSD deduced from mercury porosimetry.

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Section: Discussionmentioning

confidence: 99%

Toward a New Method of Porosimetry: Principles and Experiments

et al. 2014

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“…Furthermore, in previous studies, the yield stress behavior of stationary lamellae was studied on the pore-scale level (5,18,19,20). Some authors also considered yield stress as a fixed parameter depending on the ratio of surface tension to pore throat, considering the porous media as a bundle of capillary tubes (21,22). Others (23,24,25) presented foam in low permeability consolidated porous media as a yield stress fluid, which was also described by a threshold pressure (26).…”

Section: Introductionmentioning

confidence: 99%

Experimental Study of Non-Newtonian Behavior of Foam Flow in Highly Permeable Porous Media

Omirbekov

Davarzani

Ahmadi-Sénichault

2020

Ind. Eng. Chem. Res.

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Foam-flow behavior in highly permeable porous media is still unclear. Two types of pre-generated foam using porous columns respectively filled with fine sand and 1 mm glass beads were studied in different packs of glass beads with monodisperse bead size. Foam generated in fine sand had a sharp displacing front. However, the foam pre-generated using 1 mm glass beads had a transition zone front. We found that the transition foam-quality regime was independent of the porous medium grain size only when the bubbles are smaller than the pores. The apparent viscosity of foam was found to follow the Herschel-Bulkley model if the foam bubble sizes were smaller than the pore sizes. When the bubbles were the same size as the pores, the foam behaved like a Newtonian fluid at low flowrates and, by increasing flowrates, exhibited shear-thinning fluid behavior. Furthermore, the apparent foam viscosity was found to increase with permeability.

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“… 38 It has been demonstrated that the solubility of methane in crude oil is much greater than the solubility of nitrogen in crude oil, which means that after the methane bubble bursts, part of the methane is inefficiently displaced and part of the methane is trapped in the formation. 39 However, part of the methane gas easily dissolves in the crude oil under high pressures, forming foam oil, which causes the density and viscosity of the crude oil to decrease. This facilitates the flow of crude oil during the displacement process, resulting in higher oil recovery.…”

Section: Resultsmentioning

confidence: 99%

Investigation of the Effect of Nanoparticle-Stabilized Foam on EOR: Nitrogen Foam and Methane Foam

Zhao

et al. 2020

ACS Omega

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In recent years, studies conducted on foam stabilization have focused on nanoparticles by generating strong adsorption at the interface to stabilize the foam under harsh reservoir conditions. Meanwhile, the selection of a gas source is also of great importance for foam performance. In this study, a mixed system of surfactants was selected, and the foamability and foam stability of nitrogen and methane were evaluated according to the improved jet method. After adding modified SiO 2 nanoparticles, the foam-related parameters were analyzed. The plugging abilities of the different foams were compared through core-flooding experiments, and the oil displacement effects of the different foams were compared through microfluidic experiments. The results show that the amphoteric surfactant betaine has an excellent synergistic effect on the anionic surfactant SDS. The methane foam produced using the jet method has a larger initial volume than the nitrogen foam, but its stability is poor. The half-life of the nitrogen foam is about two times that of the methane foam. After adding 1.0 wt % SiO 2 nanoparticles to the surfactant solution, the viscosity and stability of the formed foam improve. However, the maximum viscosity of the surfactant nanoparticle foam (surfactant-NP foam) is 53 mPa·s higher than that of the surfactant foam. In the core-flooding experiment, the plugging performance of the methane foam was worse than that of the nitrogen foam, and in the microfluidic experiment, the oil displacement abilities of the methane foam and the nitrogen foam were similar. The plugging performance and the oil displacement effect of the foam are greatly improved by adding nanoparticles. The surfactant-NP foam flooding has a better oil displacement effect and can enhance the recovery factor by more than 30%. Under actual high-pressure reservoir conditions, although the stability of the methane foam is weaker than that of the nitrogen foam, some methane may be dissolved in the crude oil to decrease the viscosity after the foam collapses, which leads to the methane foam being the preferred method in oilfields.

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Network Modeling of Gas Trapping and Mobility in Foam Enhanced Oil Recovery

Cited by 43 publications

References 81 publications

Toward a New Method of Porosimetry: Principles and Experiments

Toward a New Method of Porosimetry: Principles and Experiments

Experimental Study of Non-Newtonian Behavior of Foam Flow in Highly Permeable Porous Media

Investigation of the Effect of Nanoparticle-Stabilized Foam on EOR: Nitrogen Foam and Methane Foam

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