A self-similar analytical solution of spontaneous and forced imbibition in porous media

Wang, Xiukun; Sheng, James J.

doi:10.26804/ager.2018.03.04

Cited by 38 publications

(17 citation statements)

References 14 publications

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“…Other areas that have recently caught interest due to their importance in understanding the fluid behavior in shale or increasing the productivity are (i) spontaneous imbibition in shales [218,[223][224][225], (ii) thermodynamic phase behavior of fluids inside shales as a function of pressure drawdown during production [226][227][228][229][230][231], (iii) alternate fracturing fluids [232][233][234][235][236][237] for better reservoir stimulation and to avoid water usage, and (iv) enhancing oil recovery by injection of fluids [238][239][240].…”

Section: Literature Reviewmentioning

confidence: 99%

Critical Review of Fluid Flow Physics at Micro‐ to Nano‐scale Porous Media Applications in the Energy Sector

Singh

Myong

2018

Advances in Materials Science and Engineering

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While there is a consensus in the literature that embracing nanodevices and nanomaterials helps in improving the efficiency and performance, the reason for the better performance is mostly subscribed to the nanosized material/structure of the system without sufficiently acknowledging the role of fluid flow mechanisms in these systems. This is evident from the literature review of fluid flow modeling in various energy-related applications, which reveals that the fundamental understanding of fluid transport at micro- and nanoscale is not adequately adapted in models. Incomplete or insufficient physics for the fluid flow can lead to untapped potential of these applications that can be used to increase their performance. This paper reviews the current state of research for the physics of gas and liquid flow at micro- and nanoscale and identified critical gaps to improve fluid flow modeling in four different applications related to the energy sector. The review for gas flow focuses on fundamentals of gas flow at rarefied conditions, the velocity slip, and temperature jump conditions. The review for liquid flow provides fundamental flow regimes of liquid flow, and liquid slip models as a function of key modeling parameters. The four porous media applications from energy sector considered in this review are (i) electrokinetic energy conversion devices, (ii) membrane-based water desalination through reverse osmosis, (iii) shale reservoirs, and (iv) hydrogen storage, respectively. Review of fluid flow modeling literature from these applications reveals that further improvements can be made by (i) modeling slip length as a function of key parameters, (ii) coupling the dependency of wettability and slip, (iii) using a reservoir-on-chip approach that can enable capturing the subcontinuum effects contributing to fluid flow in shale reservoirs, and (iv) including Knudsen diffusion and slip in the governing equations of hydrogen gas storage.

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Section: Literature Reviewmentioning

confidence: 99%

Critical Review of Fluid Flow Physics at Micro‐ to Nano‐scale Porous Media Applications in the Energy Sector

Singh

Myong

2018

Advances in Materials Science and Engineering

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“…However, the average pore pressure during formation cannot be directly obtained (Shen et al, 2014;Li et al, 2017;Ameh 2019). Additionally, the formation-pressure gradient near water injection and oil production wells is excessively large to be used as the basic parameter for calculating the average formation pressure (Wang and Sheng, 2018;Zhang et al, 2020). The technology for predicting formation pore pressure has been successfully employed in seismic data prediction research since the 1970s (Tipper 1976).…”

Section: Introductionmentioning

confidence: 99%

Calculation of Average Reservoir Pore Pressure Based on Surface Displacement Using Image-To-Image Convolutional Neural Network Model

Wang

2021

Front. Earth Sci.

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The average pore pressure during oil formation is an important parameter for measuring the energy required for the oil formation and the capacity of injection–production wells. In past studies, the average pore pressure has been derived mainly from pressure build-up test results. However, such tests are expensive and time-consuming. The surface displacement of an oilfield is the result of change in the formation pore pressure, but no method is available for calculating the formation pore pressure based on the surface displacement. Therefore, in this study, the vertical displacement of the Earth’s surface was used to calculate changes in reservoir pore pressure. We employed marker-stakes to measure ground displacement. We used an improved image-to-image convolutional neural network (CNN) that does not include pooling layers or full-connection layers and uses a new loss function. We used the forward evolution method to produce training samples with labels. The CNN completed self-training using these samples. Then, machine learning was used to invert the surface vertical displacement to change the pore pressure in the oil reservoir. The method was tested in a block of the Sazhong X development zone in the Daqing Oilfield in China. The results showed that the variation in the formation pore pressure was 83.12%, in accordance with the results of 20 groups of pressure build-up tests within the range of the marker-stake measurements. Thus, the proposed method is less expensive, and faster than existing methods.

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“…Numerical simulations are also commonly used for correcting the capillary‐end effect (Qadeer et al, 1988). In the numerical simulations, relative permeability is corrected with experimental data, such as in situ saturation measurements and an independent measurement of capillary pressure (Cao et al, 2020; Qadeer et al, 1988; Wang & Sheng, 2018; Zou & Armstrong, 2019). These measurements are then history‐matched via numerical modeling, with the core outlet treated as a zero capillary pressure boundary.…”

Section: Introductionmentioning

confidence: 99%

Influence of Capillarity on Relative Permeability in Fractional Flows

Zou

Liu

Cai

et al. 2020

Water Resources Research

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The effect of capillary pressure on multiphase flow is described by the capillary pressure gradient term in the fractional flow equation. This term is typically neglected during core-flooding experiments, as it is not easily accessible. However, the capillary pressure is not constant during core flooding owing to a capillary pressure discontinuity at the core outlet. By imaging spatial fluid distributions under two-phase steady-state flow, we determine in situ phase saturations and capillary pressures from interfacial curvature measurements along an entire core, thus achieving the assessment of the capillary pressure gradient and its influence on multiphase flow. We demonstrate how the pore-scale capillary pressure gradient affects multiphase flow and, in turn, the core-scale relative permeability measurements. Further, an alternative approach to determining relative permeability from a single fractional flow experiment is proposed. The approach provides a range of relative permeabilities for a single fractional flow experiment and does not require capillary-end correction, as the formulation directly accounts for the effect of capillary pressure on the flow.

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A self-similar analytical solution of spontaneous and forced imbibition in porous media

Cited by 38 publications

References 14 publications

Critical Review of Fluid Flow Physics at Micro‐ to Nano‐scale Porous Media Applications in the Energy Sector

Critical Review of Fluid Flow Physics at Micro‐ to Nano‐scale Porous Media Applications in the Energy Sector

Calculation of Average Reservoir Pore Pressure Based on Surface Displacement Using Image-To-Image Convolutional Neural Network Model

Influence of Capillarity on Relative Permeability in Fractional Flows

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