Effects of Vaporization and Temperature in Gas/Liquid Relative Permeability Experiments

1982 ◽  
Vol 22 (01) ◽  
pp. 108-116 ◽  
Author(s):  
John R. Counsil ◽  
Henry J. Ramey
Keyword(s):  
Fluid Flow ◽  
Relative Permeability ◽  
Elevated Temperatures ◽  
Gas Mixture ◽  
Relative Permeabilities ◽  
Temperature Dependent ◽  
Liquid Saturation ◽  
Mixture Volume ◽  
Relative Permeability Curves ◽  
Gas Drive

Abstract Liquid vaporization can influence the results of unsteady, external gas-drive relative permeability experiments. At elevated temperatures, liquid vaporization may affectdisplacing gas mixture volume,displacing gas mixture viscosity, andvolumetric liquid saturation calculated from a material balance. Approximate methods are presented to correct laboratory displacement data for the effect of liquid vaporization on displacing gas mixture volume and viscosity. An approximate method also is presented to evaluate the magnitude of liquid saturation reduction caused by liquid vaporization. By use of a modified Jones and Roszelle calculation procedure, equations are developed to describe the dynamic displacement of liquid water by nitrogen gas at elevated temperatures. A conventional analysis of three displacement experiments demonstrated the apparent temperature dependence of gas relative permeability. Use of the proposed method indicated that corrected gas and water relative permeability curves are not strongly temperature dependent for the artificially consolidated sandstone cores used in this study. Introduction Relative permeability curves are required for numerical modelling of multiphase fluid flow through porous media. Although natural reservoir heterogeneity often reduces the utility of laboratory-derived relative permeabilities, laboratory studies are still required to understand basic fluid flow processes. Welge first modified the Buckley-Leverett theory and presented the equations for calculating (relative) permeability ratios from linear displacement data. Johnson et al. later extended this theory, to allow the calculation of individual relative permeabilities. The base permeability was the predrive, displacing-fluid effective permeability at the initial wetting, phase saturation. Jones and Roszelle then presented a simplified graphical technique that yielded individual relative permeabilities with the absolute (brine)permeability as a base. Osoba et al., Geffen et al., Welge, Rapoport and Leas, Stewart et al., Owens et al., Corey and Rathjens. Estes and Fulton. Richardson and Perkins, Craig et al., and others demonstrated the importance of end effects, flow rate, pressure gradient, drainage imbibition hysteresis, viscosity ratio, interfacial tension, contact angle, critical scaling factor, core heterogeneity, gas slippage, and other factors. In addition, temperature-dependent permeability effects were observed by Davidson, Poston et al., Weinbrandt et al., Casse and Ramey, and others. The reasons for the temperature effects were never fully understood or explained. This paper presents a method of eliminating some of the "apparent" gas relative-permeability temperature dependence by correcting approximately for the temperature- and pressure-dependent vapor/liquid phase behavior. Experimental Process and Apparatus The calculation procedure developed in this study models an isothermal, unsteady, linear gas drive. SPEJ P. 108^

Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability

2000 ◽  
Vol 3 (06) ◽  
pp. 473-479 ◽  
Author(s):  
R.E. Mott ◽  
A.S. Cable ◽  
M.C. Spearing
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Relative Permeabilities ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Condensate Reservoir ◽  
Deep Reservoir ◽  
The Relationship

Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .

A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive

2005 ◽  
Vol 8 (04) ◽  
pp. 348-356 ◽  
Author(s):  
Fabrice Bauget ◽  
Patrick Egermann ◽  
Roland Lenormand
Keyword(s):  
Relative Permeability ◽  
History Matching ◽  
Phase Transfer ◽  
Bubble Nucleation ◽  
Relative Permeabilities ◽  
Solution Gas Drive ◽  
Reservoir Conditions ◽  
Depletion Rate ◽  
Gas Drive ◽  
Solution Gas

Summary Relative permeability curves (kr) control production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood), the kr curves obtained in the laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution-gas drive (depressurized field, foamy oils), the experiments conducted in the laboratory depend on the depletion rate and cannot be used directly for reservoir simulations. We have developed a novel approach for calculating representative field relative permeabilities. This new method is based on a physical model that takes into account the various mechanisms of the process: bubble nucleation(pre-existing bubbles model), phase transfer (volumetric transfer function), and gas displacement (bubble flow). In our model, we have identified a few"invariant" parameters that are not sensitive to depletion rate and are specific to the rock/fluid system (mainly the pre-existing bubble-size distribution and a proportionality coefficient relating gas and oil velocity for the dispersed-phase regime). These invariant parameters are determined by history matching one experiment at a given depletion rate. The calibrated model is then used to generate synthetic data at any depletion rate, especially at very low depletion rates representative of the reservoir conditions. Relative permeabilities are derived from these"numerical" experiments in the same way as they are from real experiments. The calculated kr is finally used in commercial reservoir simulators. We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with very good accuracy. Finally, we present an example of determination of relative permeabilities at reservoir depletion rates. Introduction In the case of conventional recovery processes (waterflooding and gasflooding), experiments that are conducted in the laboratory can mimic the conditions that prevail in the reservoir. Hence, the kr data derived from these experiments can be used in a practically straightforward manner for field-simulation purposes (upscaling is often needed to account for heterogeneities). The problem is more complicated for recovery by solution-gas drive. In this case, the laboratory experiments fail in reproducing the reservoir conditions. In reservoirs, the depletion rates are at least several times lower than what can be obtained in the laboratory. Because the depletion rate controls the gas topology (bubble density), the diffusion of gas from solution (out of equilibrium), and the gas displacement (dispersed flow), it also dramatically affects the shape of the kr curves. Therefore, the depletion experiments cannot be used to derive field kr data directly.

Use of a Reservoir Simulator To Interpret Laboratory Waterflood Data

1973 ◽  
Vol 13 (06) ◽  
pp. 343-347 ◽  
Author(s):  
John S. Archer ◽  
S.W. Wong
Keyword(s):  
Relative Permeability ◽  
Core Sample ◽  
Reservoir Rock ◽  
Relative Permeabilities ◽  
Rock System ◽  
The Core ◽  
Water Breakthrough ◽  
Predicting Performance ◽  
Relative Permeability Curves ◽  
Reservoir Simulator

Abstract Relative permeability curves calculated from laboratory waterflood history by the method of Johnson, Bossler and Naumann (JBN) are often poorly defined or anomalous at low and intermediate poorly defined or anomalous at low and intermediate water saturations. Poor definition can be encountered with strongly water-wet homogeneous cores when the displacement is piston-like. Anomalous curve shapes are associated with laboratory-observed water breakthrough ahead of the main flood front and are common in cores that have contrasting permeability streaks. The JBN technique, although permeability streaks. The JBN technique, although valid for the conditions assumed in its development, is unsatisfactory for the conditions specified above. A reservoir simulator has been used to model laboratory tests and thereby provide an alternative interpretation procedure. The simulation uses core properties and trial-and-error relative permeabilities. properties and trial-and-error relative permeabilities. The shapes of the relative permeability curves are adjusted until calculated oil recovery and relative injectivity curves match those obtained from the laboratory displacement tests. The technique has been used successfully to obtain meaningful relative permeability curves for piston-like displacement, mixed wettability systems, piston-like displacement, mixed wettability systems, and heterogeneous carbonates. The technique has also been used in evaluating empirical equations for calculating relative permeability. Introduction Numerical reservoir simulators are finding increasing application in production history matching and performance predictions. Because of the degree of sophistication reached with these models, it is mandatory that the fluid flow properties be of the highest possible quality. Of all the rock and fluid properties required in predicting performance, it is properties required in predicting performance, it is often the relative permeability characteristics that are the most critically important. These data are usually obtained from laboratory waterflood tests using reservoir core samples. The laboratory waterflood test is an attempt to represent the linear displacement behavior of the oil/water/reservoir-rock system. The wettability properties of the rock system should be preserved properties of the rock system should be preserved in the laboratory core sample if reliable results are to be obtained. Furthermore, the viscosity ratio and surface tension of the oil/water system in the laboratory test should ideally be made the same as those in the reservoir. In interpreting laboratory waterflood tests the unsteady-state equations are usually solved by methods of Buckley-Leverett, Welge and Johnson, Bossler and Neumann (JBN). These interpretations are sometimes inadequate for defining relative permeability curves for heterogeneous reservoir permeability curves for heterogeneous reservoir rock systems or for water displacing a very light oil in a homogeneous sandstone. For example, a number of writers have observed anomalous changes in the relative permeability to water during the flooding of heterogeneous carbonate core samples. The relative permeability to water does not increase smoothly with increasing water saturation, but increases stepwise or even humps. Such behavior appears to reflect small-scale local heterogeneity in the core sample and is likely to be insignificant on a field scale. The heterogeneity is often indicated in the laboratory by an observed water breakthrough at the core-sample production face ahead of the main flood front. The time of water breakthrough is an important measurement used in the calculation of relative permeability by the JBN method. If the breakthrough permeability by the JBN method. If the breakthrough time observed is not that of the main flood front but is a little early, then the relative permeabilities calculated will not represent the properties of the bulk of the core sample. It is under these conditions that anomalous relative permeability curves usually occur. We suggest in this paper that, in many cases, the small changes in pressure and in oil and water production rate that accompany anomalous relative production rate that accompany anomalous relative permeability curves can be smoothed to reflect permeability curves can be smoothed to reflect properties more consistent with the bulk behavior properties more consistent with the bulk behavior of the core sample. In essence, we are saying that together the smoothed oil and water production history and the pressure history of the laboratory core sample represent a unique property of that sample. SPEJ P. 343

Issue with Stone-II Three Phase Permeability Model, and A Novel Robust Fundamentals-Based Alternative to It

2021 ◽  
Author(s):  
Subodh Gupta
Keyword(s):  
Relative Permeability ◽  
Phase Flow ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Phase Permeability ◽  
Permeability Model ◽  
Oil Saturation ◽  
Three Phase ◽  
Three Phase Flow ◽  
Relative Permeability Curves

Abstract The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models. While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation. The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker. The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally. The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.

Numerical Investigation of the Effects of Core Heterogeneities on Waterflood Relative Permeabilities

1970 ◽  
Vol 10 (04) ◽  
pp. 381-392 ◽  
Author(s):  
John D. Huppler
Keyword(s):  
Numerical Simulation ◽  
Porous Medium ◽  
Pressure Drop ◽  
Difference Equation ◽  
Relative Permeability ◽  
Phase Difference ◽  
Two Dimensional ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Relative Permeability Curves

Abstract Numerical simulation techniques were used to investigate the effects of common core heterogeneities upon apparent waterflood relative-permeability results. Effects of parallel and series stratification, distributed high and low permeability lenses, and vugs were considered. permeability lenses, and vugs were considered. Well distributed heterogeneities have little effect on waterflood results, but as the heterogeneities become channel-like, their influence on flooding behavior becomes pronounced. Waterflooding tests at different injection rates are suggested as the best means of assessing whether heterogeneities are important. Techniques for testing stratified or lensed cores are recommended. Introduction Since best results from waterflood tests performed on core plugs are obtained with homogeneous cores, plugs selected for testing are chosen for their plugs selected for testing are chosen for their apparent uniformity. We know, however, that uniform appearance can be misleading. For example, flushing concentrated hydrochloric acid through an apparently homogeneous core plug often produces "wormholes" in higher permeability regions. Also, we sometimes find that all core plugs from a region of interest have obvious heterogeneities, so any flooding tests must be run on nonhomogeneous core plugs. plugs. Nevertheless, relative permeabilities, as obtained routinely from core waterflood data, are calculated using the assumption that the core is a homogeneous porous medium. While it is obvious that porous medium. While it is obvious that heterogeneties mill affect these apparent relative permeabilities, there appear to be no experimental permeabilities, there appear to be no experimental results reported in the literature to indicate just how serious the problem is. Accordingly, a computer simulation study of core waterfloods was conducted to systematically examine the effects of different sizes and types of core heterogeneities on flood results. The study was performed by numerical simulation using two-dimensional, two-phase difference equation approximations to describe the immiscible water-oil displacement. For each simulation the permeability and porosity distribution of the heterogeneous core to be studied was specified; fluid flow characteristics of the system, including a single set of input relative-permeabilities curves, were stipulated The system was set in capillary pressure equilibrium at the reducible water saturation. Then a waterflood simulation was performed. From the resulting fluid production and pressure-drop data a set of production and pressure-drop data a set of relative-permeability curves was calculated using the standard computational procedure applicable to homogeneous cores. In this paper these calculated relative-permeability curves are denoted as "waterflood" curves to distinguish them from the specified input curves. The waterflood relative-permeability curves should closely match the input curves for homogeneous systems. Since the same set of input relative-permeability curves was used for all rock sections, deviations of the waterflood from the input relative-permeability curves gave an indication of the effects of heterogeneities. When the system was heterogeneous and there was good agreement between waterflood and input relative-permeability curves, then the heterogeneities did not strongly influence the flow behavior and the system responded homogeneously. MATHEMATICAL MODEL AND METHOD The waterflood simulations were carried out using two-dimensional, two-phase difference equation approximations to the incompressible-flow differential equations:* .....................(1) ....................(2) SPEJ P. 381

Measurement of Three-Phase Relative Permeability with IFT Variation

2005 ◽  
Vol 8 (01) ◽  
pp. 33-43 ◽  
Author(s):  
Yildiray Cinar ◽  
Franklin M. Orr
Keyword(s):  
Experimental Data ◽  
Relative Permeability ◽  
Oil And Gas ◽  
Gas Injection ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Rich Phase ◽  
Injection Process ◽  
Three Phase ◽  
Relative Permeability Curves

Summary In this paper, we present results of an experimental investigation of the effects of variations in interfacial tension (IFT) on three-phase relative permeability. We report results that demonstrate the effect of low IFT between two of three phases on the three-phase relative permeabilities. To create three-phase systems in which IFT can be con-trolled systematically, we used a quaternary liquid system composed of hexadecane(C16), n-butanol (NBA), water (H2O), and isopropanol (IPA). Measured equilibrium phase compositions and IFTs are reported. The reported phase behavior of the quaternary system shows that the H2O-rich phase should represent the "gas" phase, the NBA-rich phase should represent the "oil" phase, and the C16-rich phase should represent the "aqueous" phase. Therefore, we used oil-wet Teflon (PTFE) bead packs to simulate the fluid flow in a water-wet oil reservoir. We determined phase saturations and three-phase relative permeabilities from recovery and pressure-drop data using an extension of the combined Welge/Johnson-Bossler-Naumann (JBN) method to three-phase flow. Measured three-phase relative permeabilities are reported. The experimental results indicate that the wetting-phase relative permeability was not affected by IFT variation, whereas the other two-phase relative permeabilities were clearly affected. As IFT decreases, the oil and gas phases become more mobile at the same phase saturations. For gas/oil IFTs in the range of 0.03 to 2.3 mN/m, we observed an approximately 10-fold increase in the oil and gas relative permeabilities against an approximately 100-fold decrease in the IFT. Introduction Variations in gas and oil relative permeabilities as a function of IFT are of particular importance in the area of compositional processes such as high-pressure gas injection, where oil and gas compositions can vary significantly both spatially and temporally. Because gas-injection processes routinely include three-phase flow (either because the reservoir has been water-flooded previously or because water is injected alternately with gas to improve overall reservoir sweep efficiency), the effect of IFT variations on three-phase relative permeabilities must be delineated if the performance of the gas-injection process is to be predicted accurately. The development of multicontact miscibility in a gas-injection process will create zones of low IFT between gas and oil phases in the presence of water. Although there have been studies of the effect of low IFT on two-phase relative permeability,1–14 there are limited experimental data published so far analyzing the effect of low IFT on three-phase relative permeabilities.15,16 Most authors have focused on the effect of IFT on oil and solvent relative permeabilities.17 Experimental results show that residual oil saturation and relative permeability are strongly affected by IFT, especially when the IFT is lower than approximately 0.1 mN/m (corresponding to a range of capillary number of 10–2 to 10–3). Bardon and Longeron3 observed that oil relative permeability increased linearly as IFT was reduced from approximately 12.5 mN/m to 0.04 mN/m and that for IFT below 0.04, the oil relative permeability curves shifted more rapidly with further reductions in IFT. Later, Asar and Handy6 showed that oil relative permeability curves began to shift as IFT was reduced below 0.18 mN/m for a gas/condensate system near the critical point. Delshad et al.15 presented experimental data for low-IFT three-phase relative permeabilities in Berea sandstone cores. They used a brine/oil/surfactant/alcohol mixture that included a microemulsion and excess oil and brine. The measurements were done at steady-state conditions with a constant capillary number of 10–2 between the microemulsion and other phases. The IFTs of microemulsion/oil and microemulsion/brine were low, whereas the IFT between oil and brine was high. They concluded that low-IFT three-phase relative permeabilities are functions of their own saturations only. Amin and Smith18 recently have published experimental data showing that the IFTs for each binary mixture of brine, oil, and gas phases vary as pressure increases(Fig. 1). Fig. 1 shows that the IFT of a gas/oil pair decreases as the pressure increases, whereas the IFTs of the gas/brine and oil/brine pairs approach each other.

The Effect of Interfacial Tensions on Relative Oil/Water Permeabilities of Consolidated Porous Media

1982 ◽  
Vol 22 (03) ◽  
pp. 371-381 ◽  
Author(s):  
Jude O. Amaefule ◽  
Lyman L. Handy
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Relative Permeability ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Interfacial Tensions ◽  
Oil Displacement ◽  
Oil Water ◽  
Relative Permeability Curves ◽  
Low Tension

Abstract Relative permeabilities of systems containing low- tension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (IFT's) on relative oil/water permeabilities of consolidated porous media. The steady- and unsteady-state displacement methods were used to generate relative permeability curves. Aqueous low-concentration surfactant systems were used to vary IFT levels. Empirical correlations were developed that relate the imbibition relative permeabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc=v mu / sigma). They require two empirical, experimentally generated coefficients. The experimental results show that the relative oil/water permeabilities at any given saturation are affected substantially by IFT values lower than 10-1 mN/m. Relative oil/water permeabilities increased with decreasing IFT (increasing N ). The residual oil and residual water saturations (S, and S) decreased, while the total relative mobilities increased with decreasing IFT. The correlations predict values of relative oil/water permeability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number. The results of this study can be used with simulators to predict process performance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steamflood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative permeabilities has not yet been studied. Introduction Oil displacement with an aqueous low-concentration surfactant solution is primarily dependent on the effectiveness of the solutions in reducing the IFT between the aqueous phase and the reservoir oil. With the attainment of ultralow IFT's (10 mN/m) and with adequate mobility controls, all the oil contacted can conceivably be displaced. When the interfacial tension is reduced to near zero values, the process tends to approach miscible displacement. However, most high-concentration soluble oil systems revert to immiscible displacement processes as the injected chemical traverses the reservoir. This is a result of the continual depletion of the surfactant by adsorption on the rock and by precipitation with divalent cations in the reservoir brine. The mechanism by which residual oil is mobilized by low-tension displacing fluids cannot be explained solely by the application of Darcy's law to both the aqueous and the oleic phases. On the other hand, in those reservoir regions in which water and oil are flowing concurrently as continuous phases, Darcy's law would be expected to apply and the relative permeability concept would be valid. If a low-tension aqueous phase were to invade a region in which the oil had not as yet been reduced to a discontinuous irreducible saturation, one would expect, also, that the relative permeability concept would be applicable. Under circumstances for which these conditions apply, relative permeabilities at low interfacial tensions would be required, The effect of IFT's on relative permeability curves has received limited treatment in the petroleum literature. Leverett reported a small but definite tendency for a water/oil system in unconsolidated rocks to exhibit 20 to 30% higher relative permeabilities if the IFT was decreased from 24 to 5 mN/m. Mungan studied interfacial effects on oil displacement in Teflons cores. The interfacial tension values varied from 5 to 40 mN/m. SPEJ P. 371^

The Analysis Of Laboratory Fluid/Flow Displacement Data To Obtain Relative Permeability Curves

1988 ◽  
Author(s):  
D.W. Ruth ◽  
B. Nikakhtar ◽  
S. Wong ◽  
B.T. Mitchell ◽  
G. Mcleod
Keyword(s):  
Fluid Flow ◽  
Relative Permeability ◽  
Flow Displacement ◽  
Relative Permeability Curves

Three-Phase Relative Permeability Measurement Using a Nuclear Magnetic Resonance Technique for Estimating Fluid Saturation

1967 ◽  
Vol 7 (03) ◽  
pp. 235-242 ◽  
Author(s):  
D.N. Saraf ◽  
I. Fatt
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Relative Permeability ◽  
Sand Sample ◽  
Phase Flow ◽  
Relative Permeabilities ◽  
The Core ◽  
Liquid Saturation ◽  
Three Phase ◽  
Three Phase Flow ◽  
Permeability Data

Abstract A method is described for measuring two- and three-phase relative permeabilities in sandstones or sand packs using a nuclear magnetic resonance (NMR) technique to determine fluid saturations Two- and three-phase relative permeabilities have been determined on Boise sandstone using the NMR technique of saturation measurement. Three- phase relative permeability to water was found to depend only on the water saturation, whereas three-phase permeability to oil depended on both the water and oil saturations. Relative permeability to gas in three-phase flow was found to depend only on the total liquid saturation. Introduction Three-phase relative permeabilities are extremely useful in calculating field performance for reservoirs being produced by simultaneous water and gas drives. Three-phase relative permeability data are also needed for analyzing solution gas-drive reservoirs which are partially depleted and are being produced by water drive. Some thermal recovery processes involve three-phase flow which require three-phase relative permeability data for predicting reservoir-behavior. Unfortunately three-phase relative permeability measurements have rarely been made. Also, because of the scarcity of three-phase data, it has not been possible to date to relate other measured rock characteristics to the relative permeabilities with a great certainty. Leverett and Lewis, Reid and Snells have reported three-phase relative permeability data on unconsolidated sands. Leverett and Lewis used ring electrodes spaced along the length of the sand sample to -measure the resistivity of the sample which was assumed to be monotonically related to brine saturation. Gas saturation was determined from pressure-volume measurements. Oil saturation was obtained by material balance on the cell containing the sand sample. This method is involved and time consuming. Another difficulty arises from the fact that the resistivity of the sand is a function not only of saturation of brine but also of the distribution and saturation history of the brine in the pore spaces. Reid used a gamma ray absorption technique for measuring liquid saturation. This method has the disadvantage that total liquid saturation rather than oil or brine saturation is all that can be measured and still another method is required to determine the saturations of individual components. Snells used a neutron bombardment method which also required a separate determination of the individual component saturations. Caudle et al. measured three-phase relative permeability on consolidated sandstones using vacuum distillation for determining fluid saturations. Distillation after each reading makes this technique very lengthy and time consuming. Corey et al and Naar and Wygal measured three-phase relative permeability on sandstones by the capillary- pressure method. Semipermeable diaphragm assemblies were used at each end of the core specimen to keep the water base in the core. Gravimetric methods were used to determine fluid saturations. Sarem recently repeated an unsteady-state method for measuring three-phase relative permeability on sandstones. This method is an extension of Weige's methods for measuring two-phase relative permeability. Although Sarem's method is simple and comparatively fast, the assumptions involved may oversimplify the problem. Sarem's assumption, that in all rocks relative permeability to each fluid will depend only on the saturation of that fluid, seems to be rather unrealistic. Neglecting capillary effects at the end of the core is also a weak assumption Donaldson and Deans measured three-phase relative permeability using a method similar to Sarem's. SPEJ P. 235ˆ

Sign in / Sign up

Export Citation Format

Share Document