A modified well index to account for shear-thinning behaviour in foam EOR simulation

Soulat, Antoine; Douarche, F.; Flauraud, E.

doi:10.1016/j.petrol.2020.107146

Cited by 5 publications

(6 citation statements)

References 26 publications

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“…This is in practice one of the key points to be addressed for any viscous fluid injection in low-permeability formations, but since we assume the existence of very permeable layers as detailed in Section 3.3, this assumption remains reasonable. It is worth noting that the injectivity of shear-thinning (or shear-thickening) fluids whose viscosity varies a lot for large velocity gradients in the near-wellbore, as it can be the case of pre-formed foam or polymer solution, requires a specific treatment of injectivity and productivity indices [40] whose traditional formulation presupposes a constant viscosity over the well gridblock [41], which underestimates the injectivity of shear-thinning fluids.…”

Section: Static Picture Dynamic Picture Observationmentioning

confidence: 99%

Foam placement for soil remediation: scaling foam flow models in heterogeneous porous media for a better improvement of sweep efficiency

Douarche,

Braconnier,

Bourbiaux

2023

STET

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If injected with a large gas fraction, foam reduces mobility more in high-permeability layers and diverts flow to low-permeability layers. Here is a qualitative statement that has been claimed many times in many works related to environmental remediation and oil recovery. It is so true and relevant for foam flow in porous media and yet so little quantified and even less exploited in Darcy-scale numerical simulation. After briefly reviewing opportunities and challenges related to the use of foams in porous media and its Darcy-scale implicit-texture and population-balance modelling, we make a detour out of the strict framework of mathematical models by revisiting with a fresh eye the physics of foams on the large scale of heterogeneous natural porous media in terms of scaling laws. Specifically, it has been recently shown experimentally and theoretically that foam mobility reduction scales approximately as the square root of rock permeability within the framework of Darcy-type implicit-texture foam flow models [Douarche et al. (2020) Scaling foam flow models in heterogeneous reservoirs for a better improvement of sweep efficiency (Paper ThB04), in:17th European Conference of the Mathematics of Oil Recovery (ECMOR), Edinburgh, Scotland, 14–17 September; Gassara et al. (2020) Trans. Porous Media 131, 1, 193–221]. This also appears to hold for population-balance models under the local steady state assumption. This quantitative scaling law for the effect of permeability on foam properties was inferred from an analogy between foam flow in porous media and foam flow in capillary tubes and was found consistent with the modelling of available experimental data. We demonstrate by varying the permeability contrast and anisotropy of a stack of porous layers how foam regulates the flow and leads to flow diversion from high- to low-permeability layers. The threshold in permeability heterogeneity for which such a foam-driven diversion becomes effective is quantified through a sensitivity study accounting for foam injection type, permeability heterogeneity and anisotropy, heterogeneity structure, and scaling procedure. The simulations carried out clearly indicate that ignoring mobility reduction dependence on permeability in the foam process assessment of heterogeneous formations leads to an underestimation of mobility reduction benefits to improve flow conformance. The question of cores selection, as this rock-typing strategy in relation to the porous medium characterization may guide a smart and optimal design of pre-feasibility laboratory campaign for foam evaluation, and the generalization of the findings to multi-facies geological formations are also discussed. As such, the use of physical foam mobility reduction scaling law is highly recommended for foam process evaluation.

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Section: Static Picture Dynamic Picture Observationmentioning

confidence: 99%

Foam placement for soil remediation: scaling foam flow models in heterogeneous porous media for a better improvement of sweep efficiency

Douarche,

Braconnier,

Bourbiaux

2023

STET

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“…The injectivity index is used to characterize the ability of the well to deliver certain volume rate of fluids into a reservoir. A widely accepted mathematical definition for well injectivity index (J) is the ratio of the injection rate over the pressure difference between the wellbore and reservoir boundary (Soulat et al, 2020;Yang et al, 2019).…”

Section: Parametric Study On Well Injectivity Indexmentioning

confidence: 99%

Poroelastic Solution for the Nonlinear Injectivity of Subsurface Rocks With Strain‐Induced Permeability Variations

Zhang

Mehrabian

2020

Water Resources Research

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Fluid injection in porous rock occurs in a variety of hydrogeological operations including wastewater disposal, CO2 sequestration, enhanced oil recovery, and geothermal energy extraction. Influx of fluid into the host rock is usually accompanied by induced permeability enhancement due to increased pore fluid pressure and consequent dilation of the pore volume. The effect would, in turn, enhance the well injectivity index. This paper presents an analytical solution to the nonlinear problem of underground fluid injection in a disk‐shaped reservoir while accounting for the induced permeability enhancement. The host rock permeability is considered to depend on the rock total stress and pore fluid pressure. For this purpose, the rock stress is formulated as a nonlocal function of disturbances in the pore fluid pressure using the fundamental solution for a nucleus of strain in an elastic half space. Alongside, the nonlinear fluid transport equation that incorporates stress‐sensitive rock permeability is analytically solved using a perturbation technique. The good match with finite difference solution to the same problem verifies the validity and accuracy of the perturbation solution. Parametric study on a test case problem is conducted to examine the influence of different parameters on well injectivity. Findings reveal the higher vulnerability of shallower host reservoirs to stress‐induced permeability variations. The effect of rock poroelastic properties on fluid transport process is discussed.

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“…During foam injection, better conformation control is expected than when no-foamed gas (either in a single slug or in a WAG scheme) is injected, because foam is shown to increase apparent viscosity of the injected fluid, leading to reduced gravity override and viscous fingering (Smith 1988;Hirasaki 1989a, b). However, when adopting the Peaceman well model (Peaceman 1978) [the most used in commercial software, such as STARS (Computer Modeling Group 2019)] in foam simulations, the well injectivity can be significantly underestimated when combined with a coarse grid (Rossen 2003(Rossen , 2013Leeftink et al 2015;Li et al 2017;Gong et al 2019Gong et al , 2020Soulat et al 2020).…”

Section: Introductionmentioning

confidence: 99%

“…However, their solution is over-restricted by simplifying hypotheses, and the methodology lacks a procedure applicable in commercial simulators. On the other hand, Soulat et al (2020) focused on developing a methodology that could be embedded into commercial simulators. They propose a modification to the well index that takes into account only the foam quality.…”

Section: Introductionmentioning

confidence: 99%

“…Differently from several other methods proposed in the literature (Leeftink et al 2015;Soulat et al 2020;Gong et al 2019;Li et al 2017), none of the well block partitioning approaches changes the input data or the commercial reservoir simulator injectivity model (including formulas or values for the well index or the skin factor, for instance). The results obtained with these strategies show a better estimation of the BHP (or equivalently, the well injectivity) as the number of well block partitions is increased, especially when the innermost block is closer to the wellbore.…”

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

On the injectivity estimation in foam EOR

Quinelato

Paula

Igreja

et al. 2022

J Petrol Explor Prod Technol

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In this work, we study injectivity issues caused by the use of the Peaceman equation in the numerical simulation of chemical enhanced oil recovery (EOR) processes aimed at reducing fluid mobility, such as foam injection, on coarse grids. Employing analytical solutions, we demonstrate that the Peaceman equation, commonly applied to mathematical modeling of the injectivity in commercial simulators, leads to errors of more than two orders of magnitude in the injection well pressure drop when the foam flow effects near the well are considered for assuming homogeneous mobility in a coarse-well block. To circumvent this issue, we investigate numerical treatments focused on the grid of well blocks through local grid partitioning strategies (radial and Cartesian) to improve the injection well bottom-hole pressure (BHP) estimation. This methodology does not change the input data nor the injectivity model characteristics of the commercial simulator. It does not significantly affect the computational cost of the simulation, since the grid treatment occurs only in the blocks containing the wells. Thus, the radial and Cartesian grid partitioning for the well block are compared using the STARS simulator. Our results show the clear capability of the methodology to reduce the well BHP overestimation, mitigating the errors caused by the Peaceman equation. Indeed, in some simulated scenarios, the BHP overestimation was reduced a hundredfold after applying the partitioning technique. Furthermore, we discuss the choice of simulation parameters leading to more accurate and numerically stable results.

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A modified well index to account for shear-thinning behaviour in foam EOR simulation

Cited by 5 publications

References 26 publications

Foam placement for soil remediation: scaling foam flow models in heterogeneous porous media for a better improvement of sweep efficiency

Foam placement for soil remediation: scaling foam flow models in heterogeneous porous media for a better improvement of sweep efficiency

Poroelastic Solution for the Nonlinear Injectivity of Subsurface Rocks With Strain‐Induced Permeability Variations

On the injectivity estimation in foam EOR

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