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.

A Crucial Role of the Applied Capillary Pressure in Drainage Displacement

SPE Journal ◽  
2021 ◽  
pp. 1-19
Author(s):  
Danial Arab ◽  
Apostolos Kantzas ◽  
Ole Torsæter ◽  
Salem Akarri ◽  
Steven L. Bryant
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Crucial Role ◽  
Driving Force ◽  
Oil Reservoirs ◽  
Injection Velocity ◽  
Oil Viscosity ◽  
The Core

Summary Waterflooding has been applied either along with primary production to maintain reservoir pressure or later to displace the oil in conventional and heavy-oil reservoirs. Although it is generally accepted that waterflooding of light oil reservoirs in oil-wet systems delivers the least oil compared to either water-wet or intermediate-wet systems, there is a lack of systematic research to study waterflooding of heavy oils in oil-wet reservoirs. This research gives some new insights on the effect of injection velocity and oil viscosity on waterflooding of oil-wetreservoirs. Seven different oils with a broad range of viscosity ranging from 1 to 15 000 mPa·s at 25°C were used in 18 coreflooding experiments in which injection velocity was varied from 0.7 to 24.3 ft/D (2.5×10−6 to 86.0×10−6 m/s). Oil-wet sand (with contact angle of 159.3 ± 3.1°) was used in all the flooding experiments. Breakthrough time was precisely determined using an in-line densitometer installed downstream of the core. Oil-wet microfluidics (164.4 ± 9.7°) were used to study drainage displacement at the pore scale. Our observations suggest the crucial role of the wetting phase (oil) viscosity and the injection velocity in providing the driving force (capillary pressure) required to drain oil-wet pores. Capillarity-driven drainage can significantly increase oil recovery compared to injecting water at smaller pressure gradients. Increasing viscosity of the oil being displaced (keeping velocity the same) increases pressure gradient across the core. This increase in pressure gradient can be translated to the increase in the applied capillary pressure, especially where the oil phase is nearly stationary, such as regions of bypassed oil. When the applied capillary pressure exceeds a threshold, drainage displacement of oil by the nonwetting phase is facilitated. The driving force to push nonwetting phase (water) into the oil-wet pores can also be provided through increasing injection velocity (keeping oil viscosity the same). In this paper, it is demonstrated that in an oil-wet system, increasing velocity until applied capillary pressure exceeds a threshold improves forced drainage to the extent that it increases oil recovery even when viscous fingering strongly influences the displacement. This is consistent with the classical literature on carbonates (deZabala and Kamath 1995). However, the current work extends the classical learnings to a much wider operational envelope on oil-wet sandstones. Across this wider range, the threshold at which applied capillary pressure makes a significant contribution to oil recovery exhibits a systematic variation with oil viscosity. However, the applied capillary pressure; that is, the pressure drop observed during an experiment, does not vary systematically with conventional static parameters or groups and thus cannot be accurately estimated a priori. For this reason, the scaling group presented here incorporates a dynamic capillary pressure and correlates residual oil saturation more effectively than previously proposed static scaling groups.

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.

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 Foam Generation in Flow Across a Sharp Permeability Transition: Effect of Velocity and Fractional Flow

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 451-464 ◽  
Author(s):  
Swej Y. Shah ◽  
Herru As Syukri ◽  
Karl-Heinz Wolf ◽  
Rashidah M. Pilus ◽  
William R. Rossen
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Permeability Transition ◽  
Fractional Flow ◽  
Local Pressure ◽  
The Core ◽  
Foam Generation ◽  
Gas Mobility ◽  
Foam Propagation ◽  
Strong Foam

Summary Foam reduces gas mobility and can help improve sweep efficiency in an enhanced-oil-recovery (EOR) process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that the local pressure gradient exceed a critical value (▿Pmin). Normally, this happens only in the near-well region. Away from wells, these requirements might not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (Rossen 1999). The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of fractional flow on this process. This article is an extension of a recent study (Shah et al. 2018) investigating the effect of permeability contrast on this process. In this study, the effects of fractional flow and total superficial velocity are described. Coreflood experiments were performed in a cylindrical sintered-glass porous medium with two homogeneous layers and a sharp permeability jump in between, representing a lamination or cross lamination. Unlike previous studies of this foam-generation mechanism, in this study, gas and surfactant solution were coinjected at field-like velocities into a medium that was first flooded to steady state with gas/brine coinjection. The pressure gradient is measured across several sections of the core. X-ray computed tomography (CT) is used to generate dynamic phase-saturation maps as foam generates and propagates through the core. We investigate the effects of velocity and injected-gas fractional flow on foam generation and mobilization by systematically changing these variables through multiple experiments. The core is thoroughly cleaned after each experiment to remove any trapped gas and to ensure no hysteresis. Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, and it then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities. Foam was generated in all cases, at all the injected conditions tested; however, at the lowest velocity tested, strong foam did not propagate all the way to the outlet of the core. Although foam generation was triggered across the permeability boundary at this velocity, it appeared that, for our system, the limit of foam propagation, in terms of a minimum-driving-force requirement, was reached at this low rate. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate—probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ▿P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injection rate.

A New Unsteady-State Model for Calculating Oil-Water Relative Permeability of Low-Permeability/Ultra-Low Permeability Reservoirs

2012 ◽  
Vol 616-618 ◽  
pp. 964-969 ◽  
Author(s):  
Yue Yang ◽  
Xiang Fang Li ◽  
Ke Liu Wu ◽  
Meng Lu Lin ◽  
Jun Tai Shi
Keyword(s):  
Porous Media ◽  
Pressure Gradient ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Low Permeability ◽  
Threshold Pressure ◽  
Flow Process ◽  
Threshold Pressure Gradient

Oil and water relative permeabilities are main coefficients in describing the fluid flow in porous media; however, oil and water relative permeability for low - ultra low perm oil reservoir can not be obtained from present correlations. Based on the characteristics of oil and water flow in porous media, the model for calculating the oil and water relative permeability of low and ultra-low perm oil reservoirs, which considering effects of threshold pressure gradient and capillary pressure, has been established. Through conducting the non-steady oil and water relative permeability experiments, oil and water relative permeability curves influenced by different factors have been calculated. Results show that: the threshold pressure gradient more prominently affects the oil and water relative permeability; capillary pressure cannot influence the water relative permeability but only the oil relative permeability. Considering effects of threshold pressure gradient and capillary pressure yields the best development result, and more accordant with the flow process of oil and water in low – ultra low perm oil reservoirs.

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.

A Novel Method To Model Low-Salinity-Water Injection in Carbonate Oil Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1154-1166 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad ◽  
Gary Pope
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
History Matching ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Summary There are few low-salinity-water-injection (LSWI) models proposed for carbonate rocks, mainly because of incomplete understanding of complex chemical interactions of rock/oil/brine. This paper describes a new empirical method to model the LSWI effect on oil recovery from carbonate rocks, on the basis of the history matching and validation of recently published corefloods. In this model, the changes in the oil relative permeability curve and residual oil saturation as a result of the LSWI effect are considered. The water relative permeability parameters are assumed constant, which is a relatively fair assumption on the basis of history matching of coreflood data. The capillary pressure is neglected because we assumed several capillary pressure curves in our simulations in which it had a negligible effect on the history-match results. The proposed model is implemented in the UTCHEM simulator, which is a 3D multiphase flow, transport, and chemical-flooding simulator developed at The University of Texas at Austin (UTCHEM 2000), to match and predict the multiple cycles of low-salinity experiments. The screening criteria for using the proposed LSWI model are addressed in the paper. The developed model gives more insight into the oil-production potential of future waterflood projects with a modified water composition for injection.

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