Scaling of Recovery by Cocurrent Spontaneous Imbibition in Fractured Petroleum Reservoirs

Mirzaei‐Paiaman, Abouzar; Masihi, Mohsen

doi:10.1002/ente.201300155

Cited by 34 publications

(25 citation statements)

References 41 publications

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“…Second, in COCSI, different faces are chosen as no-flow boundaries or flow boundaries. Considering rock−fluid properties and reservoir rock data, 47,51,52 different boundary conditions (Figure 5) resulted in experimental matching with the mathematical model given in Figure 6 using the matching procedure as already applied. 53−55 As the experimental matching in Figure 6 confirms, boundary condition and direction of flow have no effect on the accuracy of the mathematical solution presented in this study, and it is another positive point of this methodology.…”

Section: Model Validation With Experimental Resultsmentioning

confidence: 99%

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

et al. 2021

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Spontaneous imbibition (SI) of the wetting phase through the porous medium to displace the nonwetting phase is determined by capillary diffusion and injection fluid advection. This system is described using a transport equation of involved mechanisms and a pressure equation. The Buckley−Leverett solution is a particular case when capillary pressure is negligible. There are also analytical solutions available for cases with capillary diffusion as the dominant involved mechanism. In this study, a new mathematical model is developed to consider how both effects are significant. The model proposes an exact valid solution for both early-time (until the saturation front reaches effluent) and late-time imbibition. The accuracy of the model has been validated by comparing the suggested analytical model with numerical and experimental data. One of the advantages of the developed model is that despite the previous models, the injection rate does not need to be proportional to the square root of time, and other functional forms can be applied. Furthermore, the suggested analytical scheme is valid for strongly water-wet (SWW), weakly water-wet (WWW), and mixed-wet (MW) rock surfaces.

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Section: Model Validation With Experimental Resultsmentioning

confidence: 99%

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

et al. 2021

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“…For one-dimensional isothermal immiscible flow of two incompressible fluids in a porous medium neglecting gravity effects (Mirzaei-Paiaman et al 2011a) as well as non-equilibrium effects Geiger 2012, 2013;Mirzaei-Paiaman et al 2011b;Mirzaei-Paiaman and Masihi 2014) with only one face open to flow (i.e., countercurrent flow) the governing equation, which is a highly non-linear parabolic partial differential equation of second order, appears by combining Darcy's law for wetting and nonwetting phases with the capillary pressure definition and the mass continuity equation for the wetting phase. By imposing a specific inlet boundary condition, McWhorter and Sunada (1990) presented an exact analytical solution to this governing equation for the situation where the entering fluid has not reached the no-flow boundary.…”

Section: The Mpms Methods (Background and Formulations)mentioning

confidence: 99%

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Mirzaei‐Paiaman

Saboorian‐Jooybari

Masihi

2016

J Petrol Explor Prod Technol

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Wettability is a key parameter affecting petrophysical properties of reservoir rocks. Mirzaei-Paiaman et al. (Energy Fuels 27:7360-7368, 2013) presented an index (referred to as MPMS) for laboratory characterization of wettability of native-or restored-state reservoir rock samples. To use this index two counter-current spontaneous imbibition (COUCSI) experiments are needed, one on the native-or restored-state core sample and another on the strongly water-wet (SWW) reference system. Slope analysis of recovery data in these two systems gives inputs for determination of MPMS index. The two systems must have the same pore structure, initial water saturation, and viscosity ratio. The case of high viscosity reservoir crude needs the reference COUCSI test to be performed using a high viscosity polar compounds-free oil. Such test could be very slow and time consuming. The purpose of this study is to remove the need for limiting condition of the same viscosity ratio between the two systems, so that the reference experiment could be performed using any viscosity ratio independent of viscosity ratio of the native-or restored-state system. Thus, in the case of high viscosity reservoir crude, the reference test can be conducted using a low viscosity oil. Such test is relatively very fast and time efficient. We do this by benefiting the viscosity scaling group (VSG) proposed by Mason et al. (J Pet Sci Eng 72:195-205, 2010). Using experimental data from three sets of mixed-wet systems, we show that applicability of this VSG is not limited to SWW systems only. This VSG is used to relax the need for the limiting condition of the same viscosity ratio between the native-or restored-state and reference systems in the MPMS method. Using two sets of experimental data, we show that acceptable results are observed when comparing the MPMS indices estimated by the proposed technique and the original MPMS method.

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“…As an important pattern to displace oil from reservoirs arising from capillary force, the static spontaneous imbibition test was identified as an appropriate way to check the internal wettability of the core samples. − Amott imbibition cells were used to conduct the imbibition. The detailed procedures were as follows: 4 core samples with very close properties were treated with SC-CO 2 fracturing fluid.…”

Section: Experimental Sectionmentioning

confidence: 99%

Wettability Alteration Study of Supercritical CO₂ Fracturing Fluid on Low Permeability Oil Reservoir

et al. 2017

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Hydraulic fracturing has become an important stimulation technique for low/ultralow permeability reservoirs. Supercritical CO 2 (SC-CO 2 ), as a no water phase material of fracturing fluid, receives wide attention. Current researches on SC-CO 2 fracturing fluid has mainly focused on its viscous properties and superiorities. However, little attention has been devoted to the interaction between SC-CO 2 fracturing fluid and the oil reservoir during the fracturing process. Besides, in a low permeability reservoir, the wettability determines the oil recovery by imbibition, which is a main way to explore oil for a matrix. Therefore, it is crucial to study the wettability alteration on a low permeability oil reservoir introduced by SC-CO 2 fracturing fluid. In this study, a contact angle goniometer was introduced to characterize the wettability alteration on low permeability cores by SC-CO 2 fracturing fluid. Meanwhile, nuclear magnetic resonance T2 spectra, a scanning electron microscope, and a energy dispersive spectrometer were used to explain the mechanisms of wettability alteration and the adsorption of fracturing fluid was analyzed. In addition, spontaneous imbibition tests were conducted to definite the impact of wettability alteration on oil production. The results showed that the thickener in SC-CO 2 fracturing fluid, fluid filter loss, and reservoir permeability were all responsible for wettability alteration on the core surface. With the increasing thickener contents and filter loss of fracturing fluid, cores turned to be intermediate and slightly water-wet from initial strongly water-wet, which was unfavorable for oil production.Comparatively low permeability cores which consist of more micro-small pores were more likely to make treated cores oleophilic, as well. Thickener adsorption was confirmed to be the main mechanism on wettability alteration by SC-CO 2 fracturing fluid, which resulted in different pore surfaces, and thus a more oleophilic cores surface. On the basis of the results of spontaneous imbibition, strong lipophilicity cores corresponded to lower oil recovery, which illustrated that wettability alteration caused by SC-CO 2 fracturing fluid was not favored for oil flow.

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Scaling of Recovery by Cocurrent Spontaneous Imbibition in Fractured Petroleum Reservoirs

Cited by 34 publications

References 41 publications

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Wettability Alteration Study of Supercritical CO₂ Fracturing Fluid on Low Permeability Oil Reservoir

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Scaling of Recovery by Cocurrent Spontaneous Imbibition in Fractured Petroleum Reservoirs

Cited by 34 publications

References 41 publications

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

Analytical Exact Solution for Co-Current Spontaneous Imbibition in Porous Media Considering Early- and Late-Time Effects

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Wettability Alteration Study of Supercritical CO2 Fracturing Fluid on Low Permeability Oil Reservoir

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Wettability Alteration Study of Supercritical CO₂ Fracturing Fluid on Low Permeability Oil Reservoir