scholarly journals Assessment of the Influence of Water Saturation and Capillary Pressure Gradients on Size Formation of Two-Phase Filtration Zone in Compressed Low-Permeable Reservoir

2020 ◽  
Vol 245 ◽  
pp. 569-581
Author(s):  
Valentin Korotenko ◽  
Sergei Grachev ◽  
Nelly Kushakova ◽  
Semyon Mulyavin
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Lower Limit ◽  
Water Saturation ◽  
Pressure Variation ◽  
Saturation Ratio ◽  
Two Phase ◽  
Oil Displacement ◽  
Displacement Front ◽  
Capillary Pressure Gradient

The paper examines the influence of capillary pressure and water saturation ratio gradients on the size of the two-phase filtration zone during flooding of a low-permeable reservoir. Variations of water saturation ratio s in the zone of two-phase filtration are associated with the pressure variation of water injected into the reservoir; moreover the law of variation of water saturation ratio s(r, t) must correspond to the variation of injection pressure, i.e. it must be described by the same functions, as the functions of water pressure variation, but be subject to its own boundary conditions. The paper considers five options of s(r, t) dependency on time and coordinates. In order to estimate the influence of formation and fluid compressibility, the authors examine Rapoport – Lis model for incompressible media with a violated lower limit for Darcy’s law application and a time-dependent radius of oil displacement by water. When the lower limit for Darcy’s law application is violated, the radius of the displacement front depends on the value of capillary pressure gradient and the assignment of s function.     It is shown that displacement front radii contain coefficients that carry information about physical properties of the reservoir and the displacement fluid. A comparison of two-phase filtration radii for incompressible and compressible reservoirs is performed. The influence of capillary pressure gradient and functional dependencies of water saturation ratio on oil displacement in low-permeable reservoirs is assessed. It is identified that capillary pressure gradient has practically no effect on the size of the two-phase filtration zone and the share of water in the arbitrary point of the formation, whereas the variation of water saturation ratio and reservoir compressibility exert a significant influence thereupon.

Filtration-Flow Fragmentation in Medium with Capillary-Pressure Gradient

2018 ◽  
Vol 63 (5) ◽  
pp. 199-202 ◽  
Author(s):  
V. A. Shargatov ◽  
G. G. Tsypkin ◽  
Yu. A. Bogdanova
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Filtration Flow ◽  
Capillary Pressure Gradient

scholarly journals Lattice Boltzmann Modeling-based Design of a Membrane-free Liquid-liquid Microseparator

2020 ◽  
Vol 34 (2) ◽  
pp. 73-78
Author(s):  
Filip Strniša ◽  
Polona Žnidaršič-Plazl ◽  
Igor Plazl
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Lattice Boltzmann ◽  
In Silico ◽  
Continuous Processing ◽  
Geometrical Characteristics ◽  
Internal Structures ◽  
Simulation Results ◽  
Lattice Boltzmann Modeling ◽  
Capillary Pressure Gradient

The benefits of continuous processing and the challenges related to the integration with efficient downstream units for end-to-end manufacturing have spurred the development of efficient miniaturized continuously-operated separators. Membrane-free microseparators with specifically positioned internal structures subjecting fluids to a capillary pressure gradient have been previously shown to enable efficient gas-liquid separation. Here we present initial studies on the model-based design of a liquid-liquid microseparator with pillars of various diameters between two plates. For the optimization of in silico separator performance, mesoscopic lattice-Boltzmann modeling was used. Simulation results at various conditions revealed the possibility to improve the separation of two liquids by changing the geometrical characteristics of the microseparator.

scholarly journals Pore-Scale Modelling of Three-Phase Capillary Pressure Curves Directly in Uniformly Wet Rock Images

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Yingfang Zhou ◽  
Dimitrios Georgios Hatzignatiou ◽  
Johan Olav Helland ◽  
Yulong Zhao ◽  
Jianchao Cai
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pore Space ◽  
Phase Region ◽  
Gas Oil ◽  
Two Phase ◽  
Sem Image ◽  
Three Phase ◽  
Scale Modelling ◽  
Capillary Pressure Curves

In this work, we developed a semianalytical model to compute three-phase capillary pressure curves and associated fluid configurations for gas invasion in uniformly wet rock images. The fluid configurations and favorable capillary entry pressures are determined based on free energy minimization by combining all physically allowed three-phase arc menisci. The model was first validated against analytical solutions developed in a star-shaped pore space and subsequently employed on an SEM image of Bentheim sandstone. The simulated fluid configurations show similar oil-layer behavior as previously imaged three-phase fluid configurations. The simulated saturation path indicates that the oil-water capillary pressure can be described as a function of the water saturation only. The gas-oil capillary pressure can be represented as a function of gas saturation in the majority part of the three-phase region, while the three-phase displacements slightly reduce the accuracy of such representation. At small oil saturations, the gas-oil capillary pressure depends strongly on two-phase saturations.

scholarly journals Bentonite Extrusion into Near-Borehole Fracture

Geosciences ◽  
2019 ◽  
Vol 9 (12) ◽  
pp. 495 ◽  
Author(s):  
Mohammad N. Islam ◽  
Andrew P. Bunger ◽  
Nicolas Huerta ◽  
Robert Dilmore
Keyword(s):  
Finite Element ◽  
Pressure Gradient ◽  
Capillary Pressure ◽  
Swelling Pressure ◽  
Elastic Model ◽  
Swelling Potential ◽  
Liquid Saturation ◽  
Modified Cam Clay ◽  
Swell Cell ◽  
Capillary Pressure Gradient

In this paper, we discuss laboratory experiments of bentonite swelling and coupled finite element simulations to explicate bentonite extrusion. For the experiments, we developed a swell cell apparatus to understand the bentonite migration to the near-borehole fracture. We constructed the swell cell using acrylic, which comprised of a borehole and open fracture. Initially, the borehole of the swell cell was filled with bentonite and liquid. Then, the apparatus was sealed for observations. Due to the liquid saturation increase of bentonite, its swelling pressure increased. The developed pressure caused the extrusion of bentonite into the fracture, and the flow of bentonite from the borehole decreased with time. Moreover, for the effectiveness of bentonite-based plugging, there is a limiting condition, which represents the relation between the maximum bentonite migration length with the fracture aperture. Additionally, we also performed the bentonite free swelling test to assess the swelling potential to the fluid salinity, and we observed that with the increase of the salinity, the swelling potential decreased. In addition, we present a fully coupled two-phases fluids flow (e.g., liquid and gas) and deformation flow finite element (FE) model for the bentonite column elements and swell cell model. We also combined the Modified Cam Clay (MCC) model and the swelling model for the bentonite deformation flow model. Then, we also present the validation of the bentonite model. To model other sub-domains, we used the poro-elastic model. Additionally, we obtained the transition between the wetting phase (i.e., liquid) and non-wetting phase (i.e., gas) using the Brooks–Corey model. From the finite element results, we observed that due to the liquid intrusion into the bentonite, the developed capillary pressure gradient results in a change of the hydro-mechanical behavior of the bentonite. Initially, we observed that due to the high capillary pressure gradient, the liquid saturation and the swelling pressure increased, which also decreased with time due to a reduction in the capillary pressure gradient. Thereby, the swelling pressure-induced bentonite migration to the fracture also decreased over time, and after the equilibrium state (for a negligible pressure gradient), there was no significant transport of bentonite into the fracture.

Modeling of Spontaneous–Imbibition Experiments With Porous Disk—On the Validity of Exponential Prediction

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1326-1337 ◽  
Author(s):  
P. Ø. Andersen ◽  
S.. Evje ◽  
A.. Hiorth
Keyword(s):  
Experimental Data ◽  
Pressure Gradient ◽  
Capillary Pressure ◽  
Analytical Model ◽  
Time Scale ◽  
Flow Resistance ◽  
Equilibrium Points ◽  
Porous Disk ◽  
The Core ◽  
Capillary Pressure Gradient

Summary Imbibition experiments with porous disk can be used to derive accurate capillary pressure curves for porous media. An experimental setup is considered in which brine spontaneously imbibes cocurrently through a water-wet porous disk and into a mixed-wet core. Oil is produced from the core's top surface, which is exposed to oil. The capillary pressure is reduced in steps to determine points on the capillary pressure curve. A mathematical model is presented to interpret and design such experiments. The model was used to history match experimental data from Ahsan et al. (2012). An analytical model was then derived from a simplification of the general model, and validated by comparing the two by use of parameters from history matching. The main assumption of the analytical model is that the imbibition rate is sufficiently low, allowing fluids to redistribute inside the core, leading to a negligible capillary pressure gradient. This results in an exponential imbibition time profile with a time scale τ. Exponential matching has been applied earlier in the literature, but, for the first time, we derive this expression theoretically and provide an explicit formulation for the time scale. The numerical simulations show that, at low saturations, there can be a significant flow resistance in the core. A capillary-pressure gradient then forms, and the analytical solution overestimates the rate of recovery. At higher saturations, the fluids are more mobile, and imbibition rate is restricted by the disk. Under such conditions, the exponential solution is a good approximation. The demonstrated ability to predict the time scale in the late stage of the experiment is of significant benefit, because this part of the test is also the most time-consuming and most important to estimate. A method is presented to derive capillary pressure data point by point from measured imbibition data. It provides reliable data between the equilibrium points, and demonstrates consistent variations in flow resistance during the imbibition tests. Gravity had minor influence on the considered experimental data, but generally implies that equilibrium points have higher capillary pressure than the phase pressure difference defined by the boundary conditions.

Interpreting Relative Permeability and Wettability From Unsteady-State Displacement Measurements

1981 ◽  
Vol 21 (03) ◽  
pp. 296-308 ◽  
Author(s):  
J.P. Batycky ◽  
F.G. McCaffery ◽  
P.K. Hodgins ◽  
D.B. Fisher
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Capillary Forces ◽  
Unsteady State ◽  
The Core ◽  
Fluid Systems ◽  
System Length ◽  
Capillary Pressure Gradient

Abstract A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents. Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties—besides indicating strong, weak, intermediate, or mixed wettability—then can be used to derive relative permeabilities from the displacement data. Examples of the technique for determining wettability are given for pure-fluids/Berea-sandstone andreservoir-fluids/preserved-reservoir-rock systems. Introduction It long has been recognized that capillary forces can influence the results of relative permeability and oil recovery measurements on core samples.1–5 A scaling criterion for linear displacement tests has been proposed to remove the dependence of oil recovery on displacement rate and system length.5 The objective is to avoid appreciable influence of capillary forces on the flooding behavior that causes a spreading of the displacement front and the well-known end effect or buildup of the wetting phase at the ends of the core. The suggested scaling causes the capillary pressure gradient in the direction of flow to be small compared with the imposed pressure gradient and is expressed asEquation 1 where L is system length (in centimeters), µ is displacing phase viscosity (in centipoise or millipascal-seconds), and q/A is flow rate per unit cross-sectional area (in centimeters per minute). Bentsen6 refined the criterion for neglecting capillary forces to include consideration of the mobility ratio. In related work, Peters and Flock7 recently proposed a dimensionless number and its critical value for predicting the onset of instabilities resulting from viscous fingering at unfavorable mobility ratios. In apparent contrast to the scaling coefficient suggested in Eq. 1, displacements were shown to decline at high flow rates for a given core system and wettability condition.

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