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.

scholarly journals Foam Generation by Capillary Snap-Off in Flow Across a Sharp Permeability Transition

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 116-128 ◽  
Author(s):  
Swej Y. Shah ◽  
Karl-Heinz Wolf ◽  
Rashidah M. Pilus ◽  
William R. Rossen
Keyword(s):  
Porous Media ◽  
Pressure Gradient ◽  
Surfactant Solution ◽  
Permeability Transition ◽  
Small Scale ◽  
Fractional Flow ◽  
The Core ◽  
Foam Generation ◽  
Theoretical Predictions ◽  
Gas Mobility

Summary Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery (EOR) process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. This requirement is typically met only near the wellbore, and it is uncertain whether foam can propagate several tens of meters away from wells as the local pressure gradient and superficial velocity decreases. Theoretical studies show that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities are presented. We use model consolidated porous media made out of sintered glass, with a well-characterized permeability transition in each core. The change in permeability in these artificial cores is analogous to sharp, small-scale heterogeneities, such as laminations and cross laminations. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computed tomography (CT) provides dynamic images of the coreflood with an indication of foam presence through phase saturations. We investigate the effects of the magnitude of permeability contrast on foam generation and mobilization. Experiments demonstrate foam generation during simultaneous flow of gas and surfactant solution across a sharp increase in permeability, at field-like velocities. The experimental observations also validate theoretical predictions of the permeability contrast required for foam generation by “snap-off” to occur at a certain gas fractional flow. Pressure-gradient measurements across different sections of the core indicate the presence or absence of foam and the onset of foam generation at the permeability change. There is no foam present in the system before generation at the boundary. CT measurements help visualize foam generation and propagation in terms of a region of high gas saturation developing at the permeability transition and moving downstream. If coarse foam is formed upstream, then it is transformed into stronger foam at the transition. Significant fluctuations are observed in the pressure gradient across the permeability transition, suggesting intermittent plugging and mobilization of flow there. This is the first CT-assisted experimental study of foam generation by snap-off only, at a sharp permeability increase in a consolidated medium. The results of experiments reported in this paper have important consequences for a foam application in highly heterogeneous or layered formations. Not including the effect of heterogeneities on gas mobility reduction in the presence of surfactant could underestimate the efficiency of the displacement process.

Experimental Study of Foam Generation, Sweep Efficiency, and Flow in a Fracture Network

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1140-1150 ◽  
Author(s):  
M. A. Fernø ◽  
J.. Gauteplass ◽  
M.. Pancharoen ◽  
A.. Haugen ◽  
A.. Graue ◽  
...  
Keyword(s):  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Fracture Network ◽  
Mobility Control ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Foam Generation ◽  
Gas Mobility ◽  
Mobility Reduction

Summary Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

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

2019 ◽  
Author(s):  
Swej Shah ◽  
Herru As Syukri ◽  
Karl-Heinz Wolf ◽  
Rashidah Pilus ◽  
William Rossen
Keyword(s):  
Permeability Transition ◽  
Fractional Flow ◽  
Transition Effect ◽  
Foam Generation

A Study of Gravity Counterflow Segregation

1962 ◽  
Vol 2 (02) ◽  
pp. 185-193 ◽  
Author(s):  
E.E. Templeton ◽  
R.F. Nielsen ◽  
C.D. Stahl
Keyword(s):  
Experimental Data ◽  
Pressure Gradient ◽  
Capillary Pressure ◽  
Closed System ◽  
Fractional Flow ◽  
Flow Rates ◽  
Flow Equations ◽  
Actual Flow ◽  
Capillary Pressures ◽  
Darcy Equations

Abstract It has been customary, in predicting saturation changes, to use the Leverett "fractional flow formula", obtained by eliminating the unknown pressure gradient from the generalized Darcy equations for the separate phases. The formula presents difficulties in the case of counterflow, since the "fractional" flow may be negative, greater than unity, or, in the case of a closed system, infinite. Recently, it has been shown by several authors that the corresponding equations (with capillary pressure and gravity terms) for actual flow of the phase may be used just as well. These equations are in agreement with Pirson's statement that, if the two mobilities differ considerably from each other in a closed system, the flow is largely governed by the lower value. The present study was undertaken because of an apparent lack of experimental data on gravity counterflow with which to test the theory. A 4-ft sandpacked tube in a vertical position was employed. Electrodes for determining saturations by resistivity were spaced along the tube, one phase being always an aqueous salt solution. Air, heptane, naphtha, or Bradford crude oil was used for the other phase. A reasonably uniform initial saturation was set up by pumping the phases through the system, after which the tube was shut in and saturation profiles obtained at definite intervals. Cumulative flows over certain horizontal levels were obtained by integration of the distributions; hence, differentiation of the cumulative flows with respect to time gave instantaneous flow rates. To compare experimental and theoretical flow values, capillary pressures were assumed given by the final saturation-distribution curve. The upper part corresponds to the "drainage" region and the lower part to the "imbibition" region, where trapping of the nonwetting phase occurred. While calculations indicated that the capillary pressure saturation function and, probably, the relative permeability saturation functions changed during the segregation, the relation of the measured rates to saturation distributions are in general accord with the frontal-advance equation. It appears that the Darcy equations, as modified for the separate phases, are generally valid for counterflow due to density differences. The usual method of predicting saturation changes, which involves a continuity equation and the elimination of the unknown pressure gradient from the flow equations, should therefore be applicable. However, the need for advance knowledge of drainage and imbibition "capillary pressures" and relative permeabilities during various stages presents difficulties. Introduction The present study was undertaken because of a seeming lack of experimental data relating to vertical counterflow of fluids of different densities in porous media. In particular, it was desired to determine whether data obtained from these laboratory tests were in accordance with certain mathematical treatments of counterflow which have been proposed. The gravity "correction" has been incorporated into the flow equations (and, hence, into displacement theory) nearly as long as both have been used. Field and laboratory data have generally borne out the validity of the theory as applied, for instance, to downward displacement by gas, with all fluids moving downward. However, the modifications for counterflow have only recently been pointed out. It has been customary to use fractional flow rates instead of actual flow rates in displacement calculations. In the case of counterflow, this results in negative values, values greater than unity and, when rates are equal and opposite, in infinite values. As pointed out by Sheldon, et al, and by Fayers and Sheldon, actual flow rates may be used just as well. The fact that these may be of opposite signs for the two fluids does not present any difficulty. SPEJ P. 185^

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.

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.

Modeling Techniques for Foam Flow in Porous Media

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 453-470 ◽  
Author(s):  
Kun Ma ◽  
Guangwei Ren ◽  
Khalid Mateen ◽  
Danielle Morel ◽  
Philippe Cordelier
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Population Balance ◽  
Flow In Porous Media ◽  
Fractional Flow ◽  
Foam Flow ◽  
Foam Generation ◽  
Modeling Techniques ◽  
Foam Modeling ◽  
Gas Mobility

Summary Foam, a dispersion of gas in liquid, has been investigated as a tool for gas-mobility and conformance control in porous media for a variety of applications since the late 1950s. These applications include enhanced oil recovery, matrix-acidization treatments, gas-leakage prevention, as well as contaminated-aquifer remediation. To understand the complex physics of foam in porous media and to implement foam processes in a more-controllable way, various foam-modeling techniques were developed in the past 3 decades. This paper reviews modeling approaches obtained from different publications for describing foam flow through porous media. Specifically, we tabulate models on the basis of their respective characteristics, including implicit-texture as well as mechanistic population-balance foam models. In various population-balance models, how foam texture is obtained and how gas mobility is altered as a function of foam texture, among other variables, are presented and compared. It is generally understood that both the gas relative permeability and viscosity vary in the reduction of gas mobility through foam generation in porous media. However, because the two parameters appear together in the Darcy equation, different approaches were taken to alter the mobility in the various models: only reduction of gas relative permeability, increasing of effective gas viscosity, or a combination of both. The applicability and limitations of each approach are discussed. How various foam-generation mechanisms play a role in the foam-generation function in mechanistic models is also discussed in this review, which is indispensable to reconcile the findings from different publications. In addition, other foam-modeling methods, such as the approaches that use fractional-flow theory and those that use percolation theory, are also reviewed in this work. Several challenges for foam modeling, including model selection and enhancement, fitting parameters to data, modeling oil effect on foam behavior, and scaling up of foam models, are also discussed at the end of this paper.

scholarly journals Reliability of Relative Permeability Measurements for Heterogeneous Rocks Using Horizontal Core Flood Experiments

2021 ◽  
Vol 13 (5) ◽  
pp. 2744
Author(s):  
Chia-Wei Kuo ◽  
Sally M. Benson
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Synthetic Data ◽  
Critical Value ◽  
Core Flooding ◽  
Fractional Flow ◽  
The Core ◽  
Heterogeneous Rocks ◽  
Core Flood ◽  
Relative Permeability Curves

New guidelines and suggestions for taking reliable effective relative permeability measurements in heterogeneous rocks are presented. The results are based on a combination of high resolution of 3D core-flooding simulations and semi-analytical solutions for the heterogeneous cores. Synthetic “data sets” are generated using TOUGH2 and are subsequently used to calculate effective relative permeability curves. A comparison between the input relative permeability curves and “calculated” relative permeability is used to assess the accuracy of the “measured” values. The results show that, for a capillary number (Ncv = kLpc × A/H2μCO2qt) smaller than a critical value, flows are viscous dominated. Under these conditions, saturation depends only on the fractional flow as well as capillary heterogeneity, and is independent of flow rate, gravity, permeability, core length, and interfacial tension. Accurate whole-core effective relative permeability measurements can be obtained regardless of the orientation of the core and for a high degree of heterogeneity under a range of relevant and practical conditions. Importantly, the transition from the viscous to gravity/capillary dominated flow regimes occurs at much higher flow rates for heterogeneous rocks. For the capillary numbers larger than the critical value, saturation gradients develop along the length of the core and accurate relative permeability measurements are not obtained using traditional steady-state methods. However, if capillary pressure measurements at the end of the core are available or can be estimated from independently measured capillary pressure curves and the measured saturation at the inlet and outlet of the core, accurate effective relative permeability measurements can be obtained even when there is a small saturation gradient across the core.

An Attack on the Contamination Problem in the Electron Microscope

1967 ◽  
Vol 25 ◽  
pp. 368-368
Author(s):  
J. J. Kelsch ◽  
A. Holtz
Keyword(s):  
Electron Microscope ◽  
Pressure Gradient ◽  
Ionization Potential ◽  
Simple Solution ◽  
Specimen Surface ◽  
Contamination Rate ◽  
Local Pressure ◽  
High Ionization ◽  
Hydrocarbon Molecules ◽  
Contamination Problem

A simple solution to the serious problem of specimen contamination in the electron microscope is presented. This is accomplished by the introduction of clean helium into the vacuum exactly at the specimen position. The local pressure gradient thus established inhibits the migration of hydrocarbon molecules to the specimen surface. The high ionization potential of He permits the use of relatively large volumes of the gas, without interfering with gun stability. The contamination rate is reduced on metal samples by a factor of 10.

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