Estimation of relative permeability and capillary pressure from mass imbibition experiments

Alyafei, Nayef; Blunt, Martin J.

doi:10.1016/j.advwatres.2018.03.003

Cited by 42 publications

(34 citation statements)

References 24 publications

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“…The solid gray line in Figure highlights that while the front coarsening scales by t −1/4 , the total water primary imbibition rate into the core closely follows the inverse square root relationship that has been measured in previous studies (Alyafei & Blunt, ; Ma et al, ; Mattax & Kyte, ). While the secondary imbibition data is complicated by spatial variability of initial water saturation, the imbibition flux roughly follows an inverse square root relationship at early time (dashed gray line Figure ).…”

Section: Computed Tomography Imaging Of Dynamic Spontaneous Imbibitiosupporting

confidence: 77%

“…While these experimental studies have been carried out during drainage and forced imbibition, curvature-based capillary pressure analysis has not yet been possible during spontaneous imbibition experiments. These experimental results suggest that imbibition capillary pressure is nonzero at residual nonwetting saturations, conflicting with capillary pressure curves that intersect P c = 0 at the residual nonwetting saturation in strongly water-wet systems (Alyafei & Blunt, 2018;Ma et al, 1997;Pini & Benson, 2017).…”

Section: Introductionmentioning

confidence: 94%

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Spatial and Temporal Quantification of Spontaneous Imbibition

Zahasky

Benson

2019

Geophysical Research Letters

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Spontaneous imbibition—the process of a wetting fluid displacing a nonwetting fluid purely by capillary forces—is a ubiquitous phenomenon in porous and fibrous materials. Here we present a new experimental method for quantification of spontaneous imbibition in geologic materials. This method makes it possible to perform spontaneous imbibition under elevated pressure conditions relevant to environmental and energy resource applications. Computed tomography imaging reveals a new time‐independent scaling relationship that describes local imbibition rates as a function of water saturation. Imbibition capillary pressure curves are calculated with this wetting‐phase pressure and flow rate characterization, with no assumptions about the functional form, end point behavior, or scaling factors. Calculated end point capillary pressure is nonzero, in agreement with recent pore‐scale measurements of capillary pressure of trapped nonwetting phase. This work provides a new approach and insights into trapping and remobilization of nonwetting fluids in CO2 storage reservoirs and contaminated groundwater aquifers.

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Section: Computed Tomography Imaging Of Dynamic Spontaneous Imbibitiosupporting

confidence: 77%

Section: Introductionmentioning

confidence: 94%

Spatial and Temporal Quantification of Spontaneous Imbibition

Zahasky

Benson

2019

Geophysical Research Letters

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“…It is difficult to directly measure the relative permeability for spontaneous imbibition by experiments, especially counter-current imbibition (Li et al, 2018). Generally, relative permeability of spontaneous imbibition is estimated by fitting the theoretical results with experimental results (Haugen et al, 2015;Alyafei and Blunt, 2018). Bourblaux (1990) reported that both oil and water relative permeabilities for counter-current imbibition are lower than that for co-current imbibition.…”

Section: Core Scale Of Spontaneous Imbibition With Different Boundarymentioning

confidence: 99%

Recent advances in spontaneous imbibition with different boundary conditions

Meng¹,

Cai²

2018

Capillarity

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Spontaneous imbibition plays an important role in many practical processes, such as oil recovery, hydrology, and environmental engineering. The past few years have witnessed a rapid development in the mechanism analysis and industry applications of spontaneous imbibition. In this paper, we focus on boundary conditions of spontaneous imbibition, which has important effects on the imbibition rate and efficiency. Various boundary conditions are first generated using different capillary model and introduced focusing on the fundamental physical mechanisms. Then, the studies of spontaneous imbibition in core scale are reviewed. The feature is discussed and the relative permeability for coand counter-current imbibition is analyzed. The scaling of imbibition data with different boundary conditions is also presented by combination of experimental and numerical methods. An analytical model to describe spontaneous imbibition is provided at the end.

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“…Although the scaling laws are well known (Shouxiang et al 1997, Schmid andGeiger 2012), it is no surprise to find recent work on the subject because it is a non-linear complex problem. Essentially, there is an attempt to derive flow parameters (capillary pressure, relative permeability) from saturation vs. time curve (Haugen et al 2014, Alyafei andBlunt 2018) with either local or average saturation data. For this purpose, analytical or numerical analysis is necessary and approximate analytical solutions have been found in one dimension and before the invading phase reaches the end of the core (Ruth et al 2007).…”

Section: Introductionmentioning

confidence: 99%

A Practical Methodology to Screen Oil Recovery Processes Involving Spontaneous Imbibition

et al. 2019

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We present a general novel technique to monitor saturation changes on small rock samples of only 15 mm in diameter and 20 mm in length for the purpose of assessing the kinetics of spontaneous imbibition processes. With a fully-3D imbibition configuration involving countercurrent flows through all faces of the sample, the method is based on a NMR technique in which the sole oil phase present within the sample is monitored. The experimental method is fast for two reasons that are i) the possibility to perform accurate measurements on tiny samples, ii) the adoption of a 3D flow geometry. The kinetics of oil desaturation during spontaneous imbibition is analyzed with the help of an analytical 3D diffusion model, according to which the kinetics is proportional to the value of a "capillary" diffusion coefficient. For the purpose of demonstrating our methodology, we used this technique to compare the spontaneous imbibition of restored sandstone miniplugs from a sandstone reservoir, with and without alkali in the imbibing brine. The imbibition kinetics was quantified as capillary diffusion coefficient values. The studied case results revealed mixed impacts of alkali on the spontaneous imbibition kinetics, involving both a brine-oil interfacial tension change and a wettability alteration of the rock, the latter requiring further investigation beyond the scope of this article.

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Estimation of relative permeability and capillary pressure from mass imbibition experiments

Cited by 42 publications

References 24 publications

Spatial and Temporal Quantification of Spontaneous Imbibition

Spatial and Temporal Quantification of Spontaneous Imbibition

Recent advances in spontaneous imbibition with different boundary conditions

A Practical Methodology to Screen Oil Recovery Processes Involving Spontaneous Imbibition

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