Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

1999 ◽  
Vol 2 (01) ◽  
pp. 25-36 ◽  
Author(s):  
A.B. Dixit ◽  
S.R. McDougall ◽  
K.S. Sorbie ◽  
J.S. Buckley
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Aging Process ◽  
Water Saturation ◽  
Contact Angles ◽  
Initial Water ◽  
Water Imbibition ◽  
Pore Level ◽  
Capillary Pressure Curves

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed. Introduction In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.

scholarly journals Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

2001 ◽  
Vol 4 (06) ◽  
pp. 455-466 ◽  
Author(s):  
A. Graue ◽  
T. Bognø ◽  
B.A. Baldwin ◽  
E.A. Spinler
Keyword(s):  
Crude Oil ◽  
Numerical Simulations ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
History Matching ◽  
Water Saturation ◽  
Fracture Network ◽  
Stock Tank ◽  
Recovery Mechanisms

Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only. Introduction Laboratory waterflood experiments, with larger blocks of fractured chalk where the advancing waterfront has been imaged by a nuclear tracer technique, showed that changing the wettability conditions from strongly water-wet to moderately water-wet had minor impact on the the oil-production profiles.1–3 The in-situ saturation development, however, was significantly different, indicating differences in oil-recovery mechanisms.4 The main objective for the current experiments was to determine the oil-recovery mechanisms at different wettability conditions. We have reported earlier on a technique that reproducibly alters wettability in outcrop chalk by aging the rock material in stock-tank crude oil at an elevated temperature for a selected period of time.5 After applying this aging technique to several blocks of chalk, we imaged waterfloods on blocks of outcrop chalk at different wettability conditions, first as a whole block, then when the blocks were fractured and reassembled. Earlier work reported experiments using an embedded fracture network,4,6,7 while this work also studied an interconnected fracture network. A secondary objective of these experiments was to validate a full-field numerical simulator for prediction of the oil production and the in-situ saturation dynamics for the waterfloods. In this process, the validity of the experimentally measured capillary pressure and relative permeability data, used as input for the simulator, has been tested at strongly water-wet and moderately water-wet conditions. Optimization of either Pc data or kr curves for the chalk matrix in the numerical simulations of the whole blocks at different wettabilities gave indications of the data's validity. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations of the fractured blocks, in which only the fracture representation was a variable. Experimental Rock Material and Preparation. Two chalk blocks, CHP8 and CHP9, approximately 20×12×5 cm thick, were obtained from large pieces of Rørdal outcrop chalk from the Portland quarry near Ålborg, Denmark. The blocks were cut to size with a band saw and used without cleaning. Local air permeability was measured at each intersection of a 1×1-cm grid on both sides of the blocks with a minipermeameter. The measurements indicated homogeneous blocks on a centimeter scale. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were dried in a 90°C oven for 3 days. End pieces were mounted on each block, and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing 5 wt% NaCl+3.8 wt% CaCl2. Fluid data are found in Table 1. Porosity was determined from weight measurements, and the permeability was measured across the epoxy-coated blocks, at 2×10–3 µm2 and 4×10–3 µm2, for CHP8 and CHP9, respectively (see block data in Table 2). Immobile water saturations of 27 to 35% pore volume (PV) were established for both blocks by oilflooding. To obtain uniform initial water saturation, Swi, oil was injected alternately at both ends. Oilfloods of the epoxy-coated block, CHP8, were carried out with stock-tank crude oil in a heated pressure vessel at 90°C with a maximum differential pressure of 135 kPa/cm. CHP9 was oilflooded with decane at room temperature. Wettability Alteration. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperatures, produced a moderately water-wet chalk block, CHP8, with similar mineralogy and pore geometry to the untreated strongly water-wet chalk block CHP9. Block CHP8 was aged in crude oil at 90°C for 83 days at an immobile water saturation of 28% PV. A North Sea crude oil, filtered at 90°C through a chalk core, was used to oilflood the block and to determine the aging process. Two twin samples drilled from the same chunk of chalk as the cut block were treated similar to the block. An Amott-Harvey test was performed on these samples to indicate the wettability conditions after aging.8 After the waterfloods were terminated, four core plugs were drilled out of each block, and wettability measurements were conducted with the Amott-Harvey test. Because of possible wax problems with the North Sea crude oil used for aging, decane was used as the oil phase during the waterfloods, which were performed at room temperature. After the aging was completed for CHP8, the crude oil was flushed out with decahydronaphthalene (decalin), which again was flushed out with n-decane, all at 90°C. Decalin was used as a buffer between the decane and the crude oil to avoid asphalthene precipitation, which may occur when decane contacts the crude oil.

A Dimensionless Capillary Pressure Function for Imbibition Derived From Pore-Scale Modeling in Mixed-Wet-Rock Images

SPE Journal ◽  
2012 ◽  
Vol 18 (02) ◽  
pp. 296-308 ◽  
Author(s):  
Y.. Zhou ◽  
J.O.. O. Helland ◽  
D.G.. G. Hatzignatiou
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Wettability Alteration ◽  
Scale Model ◽  
Pore Scale ◽  
Pressure Function ◽  
Initial Water ◽  
Scale Modeling ◽  
Pore Scale Modeling ◽  
Capillary Pressure Curves

Summary It has been demonstrated experimentally that Leverett's J-function yields almost unique dimensionless drainage capillary pressure curves in relatively homogeneous rocks at strongly water-wet conditions, whereas for imbibition at mixed-wet conditions, it does not work satisfactorily because the permeability dependency on capillary pressure has been reported to be weak. The purpose of this study is to formulate a new dimensionless capillary pressure function for mixed-wet conditions on the basis of pore-scale modeling, which could overcome these restrictions. We simulate drainage, wettability alteration, and imbibition in 2D rock images by use of a semianalytical pore-scale model that represents the identified pore spaces as cross sections of straight capillary tubes. The fluid configurations occurring during drainage and imbibition in the highly irregular pore spaces are modeled at any capillary pressure and wetting condition by combining the free-energy minimization with an arc meniscus (AM)-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Capillary pressure curves for imbibition are simulated for different mixed-wet conditions in Bentheim sandstone samples, and the results are scaled by a newly proposed improved J-function that accounts for differences in formation wettability induced by different initial water saturations after primary drainage. At the end of primary drainage, oil-wet-pore wall segments are connected by many water-wet corners and constrictions that remain occupied by water. The novel dimensionless capillary pressure expression accounts for these conditions by introducing an effective contact angle that depends on the initial water saturation and is related to the wetting property measured at the core scale by means of a wettability index. The accuracy of the proposed J-function is tested on 36 imbibition capillary pressure curves for different mixed-wet conditions that are simulated with the semianalytical model in scanning-electron-microscope (SEM) images of Bentheim sandstone. The simulated imbibition capillary pressure curves and the reproduced curves, based on the proposed J-function, are in good agreement for the mixed-wet conditions considered in this study. The detailed behavior is explained by analyzing the fluid displacements occurring in the pore spaces. It is demonstrated that the proposed J-function could be applied to mixed-wet conditions to generate a family of curves describing different wetting states induced by assigning different wetting properties on the solid surfaces or by varying the initial water saturation after primary drainage. The variability of formation wettability and permeability could be described more accurately in reservoir-simulation models by means of the proposed J-function, and hence the opportunity arises for improved evaluation of core-sample laboratory experiments and reservoir performance.

Influence of Initial Water Saturation on Recovery by Spontaneous Imbibition in Gas/Water/Rock Systems and the Calculation of Relative Permeability

2006 ◽  
Vol 9 (04) ◽  
pp. 295-301 ◽  
Author(s):  
Kewen Li ◽  
Kevin Chow ◽  
Roland N. Horne
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Spontaneous Imbibition ◽  
Rock Properties ◽  
Initial Water ◽  
Gas Recovery ◽  
Water Imbibition ◽  
Theoretical Predictions

Summary It has been a challenge to understand why recovery by spontaneous imbibition could both increase and decrease with initial water saturation. To this end, mathematical models were developed with porosity, permeability, viscosity, relative permeability, capillary pressure, and initial water saturation included. These equations foresee that recovery and imbibition rate can increase, remain unchanged, or decrease with an increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to approximately 50%. The effects of initial water saturation on residual saturation, relative permeability, capillary pressure, imbibition rate, and recovery in gas/water/rock systems by cocurrent spontaneous imbibition were investigated both theoretically and experimentally. Water-phase relative permeabilities and capillary pressures were calculated with the experimental data of spontaneous imbibition. Experimental results in different rocks were compared. Introduction Spontaneous water imbibition is an important mechanism during water injection. Prediction of recovery and imbibition rate by spontaneous water imbibition is essential to evaluate the feasibility and the performance of water injection. For example, is water injection effective in the case of high initial water saturation in reservoirs? Answers to such a question may be found by investigating the effect of initial water saturation on spontaneous water imbibition. It has been observed experimentally that initial water saturation affects recovery and production rate significantly (Blair 1964; Zhou et al. 2000; Viksund et al. 1998; Cil et al. 1998; Tong et al. 2001; Li and Firoozabadi 2000; Akin et al. 2000). However, the experimental observations from different authors (Zhou et al. 2000; Cil et al. 1998; Li and Firoozabadi 2000; Akin et al. 2000) are not consistent. On the other hand, few studies have investigated the effect of initial water saturation on recovery and imbibition rate theoretically, especially in gas reservoirs. Using numerical-simulation techniques, Blair (1964) found that the quantity and the rate of oil produced after a given period of imbibition increased with a decrease in initial water saturation for countercurrent spontaneous imbibition. Zhou et al. (2000) found that both imbibition rate and final oil recovery in terms of oil originally in place (OOIP) increased with an increase in initial water saturation, whereas oil recovery by waterflooding decreased. Viksund et al. (1998) found that the final oil recovery (OOIP) by spontaneous water imbibition in Berea sandstone showed little variation with a change in initial water saturation from 0 to approximately 30%. For the chalk samples tested by Viksund et al. (1998), the imbibition rate first increased with an increase in initial water saturation and then decreased slightly as initial water saturation increased above 34%.Cil et al. (1998) reported that the oil recovery (in terms of recoverable oil reserves) for zero and 20% initial water saturation showed insignificant differences in behavior. However, the oil recovery for initial water saturation above 20% increased with an increase in initial water saturation. Li and Firoozabadi (2000) found that the final gas recovery in the units of gas originally in place (GOIP) by spontaneous imbibition decreased with an increase in initial water saturation in both gas/oil/rock and gas/water/rock systems. The imbibition rate (GOIP/min) increased with an increase in initial water saturation at early time but decreased at later time. Akin et al. (2000) found that the residual oil saturation was unaffected significantly by initial water saturation. In this study, equations, derived theoretically, were used to study the effect of initial water saturation on gas recovery and imbibition rate. The equations correlate recovery, imbibition rate, initial water saturation, rock/fluid properties, and other parameters. Experiments of spontaneous water imbibition in gas-saturated rocks were conducted to confirm the theoretical predictions. The effect of rock properties on gas recovery and imbibition rate was also studied. An X-ray CT scanner was used to monitor the distribution of the initial water saturation to confirm that the initial distribution of the water saturation was uniform. In this study, we only focused on cocurrent spontaneous imbibition. It was assumed that there were no chemical reactions or mass transfer between gas and liquid.

Role of molecular diffusion in the recovery of water flood residual oil

2019 ◽  
Author(s):  
Chem Int
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Gravity Drainage ◽  
Co2 Injection ◽  
Initial Water ◽  
Water Imbibition ◽  
Naturally Fractured ◽  
Carbon Dioxide Co2

Traditionally, carbon dioxide (CO2) injection has been considered an inefficient method for enhancing oil recovery from naturally fractured reservoirs. Obviously, it would be useful to experimentally investigate the efficiency of waterflooding naturally fractured reservoirs followed by carbon dioxide (CO2) injection. This issue was investigated by performing water imbibition followed by CO2 gravity drainage experiments on artificially fractured cores at reservoir conditions. The experiments were designed to illustrate the actual process of waterflooding and CO2 gravity drainage in a naturally fractured reservoir in the Brass Area, Bayelsa. The results demonstrate that CO2 gravity drainage could significantly increase oil recovery after a waterflood. During the experiments, the effects of different parameters such as permeability, initial water saturation and injection scheme was also examined. It was found that the efficiency of the CO2 gravity drainage decrease as the rock permeability decreases and the initial water saturation increases. Cyclic CO2 injection helped to improve oil recovery during the CO2 gravity drainage process which alters the water imbibition. Oil samples produced in the experiment were analyzed using gas chromatography to determine the mechanism of CO2-improved oil production from tight matrix blocks. The results show that lighter components are extracted and produced early in the test. The results of these experiments validate the premises that CO2 could be used to recover oil from a tight and unconfined matrix efficiently.

Calculation of Oil Displacement by Countercurrent Water Imbibition

1964 ◽  
Vol 4 (03) ◽  
pp. 195-202 ◽  
Author(s):  
P.M. Blair
Keyword(s):  
Porous Medium ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Pressure Gradients ◽  
Oil Viscosity ◽  
Initial Water ◽  
Water Imbibition ◽  
Pressure Profiles ◽  
Water Viscosity

Abstract This paper presents numerical solutions of the equations describing the imbibition of water and the countercurrent flow of oil in porous rocks. The imbibition process is of practical importance in recovering oil from heterogeneous formations and has been studied principally by experimental means. Calculations were made for imbibition of water into both linear and radial systems. Imbibition in the linear systems was allowed to take place through one open, or permeable, face of the porous medium studied. In the radial system, water was imbibed inward from the outer radius. The effects on rate of imbibition of varying the capillary pressure and relative permeability curves, oil viscosity and the initial water saturation were computed. For each case studied, the rate of water imbibition and the saturation and pressure profiles were calculated as functions of time. The results of these calculations indicate that, for the porous medium studied, the time required to imbibe a fixed volume of water of a certain viscosity is approximately proportional to the square root of the viscosity of the reservoir oil whenever the oil viscosity is greater than the water viscosity. Results are also presented illustrating the effects on rate of imbibition of the other variables studied. Introduction The process of imbibition, or spontaneous flow of fluids in porous media under the influence of capillary pressure gradient s, occurs wherever there exist in permeable rock capillary pressure gradients which are not exactly balanced by opposing pressure gradients (such as those resulting from the influence of gravity). The importance of such capillary movement in the displacement of oil by water or gas was recognized in early investigations and described by Leverett, Lewis and True in 1942. Methods advanced by these authors for studying the process using dynamically scaled models were rendered more general and flexible by the research of later workers. The influence of capillary forces in laboratory water floods has also been discussed by several authors. While imbibition plays a very important role in the recovery of oil from normal reservoirs, Brownscombe and Dyes pointed out that imbibition might be the dominant displacement process in water flooding reservoirs characterized by drastic variations in permeability, such as in fractured- matrix reservoirs. In water-wet, fractured-matrix reservoirs, water will be imbibed from fractures into the matrix with a countercurrent expulsion of oil into the fractures. If the imbibition occurs at a sufficiently rapid rate, a very successful water flood can result; if the imbibition proceeds slowly the project might not be economically attractive. Scaled-model studies have demonstrated the vital importance of imbibition in secondary recovery in fractured reservoirs. It is therefore important in the evaluation of waterflooding prospects to develop a thorough understanding of the quantitative relationships of the factors which control the rapidity of capillary imbibition. The imbibition process serves reservoir engineers in still another important way by providing a technique for studying the wettability of reservoir core samples. Such experiments are usually conducted by observing the rate of expulsion of oil or water from core samples submerged in the appropriate fluid. Several papers have been published on the experimental techniques involved. Although Handy has recently published a method for calculating capillary pressures from experiments with gas-saturated cores, it has not yet been possible to deduce quantitative information regarding water-oil relative permeability and capillary pressure characteristics of the rock from the experimental results. Thus a technique is needed for studying the quantitative dependence of imbibition rate on oil and water viscosity, initial water saturation, relative permeability-saturation, and capillary pressure-saturation relations. The development of such information, including saturation and pressure profiles by laboratory experiments, would be very difficult. SPEJ P. 195ˆ

Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 152-169 ◽  
Author(s):  
Y.. Zhou ◽  
J. O. Helland ◽  
D. G. Hatzignatiou
Keyword(s):  
Capillary Pressure ◽  
Cross Sections ◽  
Water Saturation ◽  
Gas Oil ◽  
Initial Water ◽  
Three Phase ◽  
Mixed Wettability ◽  
Oil Water ◽  
Simulation Results ◽  
Capillary Pressure Curves

Summary In this study, we present a three-phase, mixed-wet capillary bundle model with cross sections obtained from a segmented 2D rock image, and apply it to simulate gas-invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration, and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations, and saturation paths for the gas-invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas/oil, oil/water, and gas/water interfaces are determined in the pore cross sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently on the basis of free-energy minimization. The valid configuration change is given by the displacement with the most favorable (the smallest) gas/oil capillary entry pressure. The simulation results show that three-phase oil/water and gas/oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas/oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a nonspreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas-invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occur frequently. The initial water saturation at the end of primary drainage has a significant effect on the gas-invasion processes after imbibition. Small initial water saturations yield more-oil-wet behavior, whereas large initial water saturations show more-water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas/oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.

Effect of Temperature Level upon Capillary Pressure Curves

1971 ◽  
Vol 11 (01) ◽  
pp. 13-22 ◽  
Author(s):  
Ali A. Sinnokrot ◽  
H.J. Ramey ◽  
S.S. Marsden
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Temperature Increase ◽  
Water Saturation ◽  
Effect Of Temperature ◽  
Temperature Level ◽  
Dynamic Displacement ◽  
Irreducible Water Saturation ◽  
Limestone Sample ◽  
Capillary Pressure Curves

Abstract A number of recent studies of drainage relative permeability ratio by dynamic displacement have permeability ratio by dynamic displacement have indicated temperature sensitivity. Poston et al. found that the irreducible water saturation appeared to increase significantly with temperature-level increase and speculated that capillary pressure saturation data would also change to show this effect. Although there have been capillary pressure-saturation studies which show important pressure-saturation studies which show important differences between laboratory and reservoir conditions (presumably higher temperatures), the effects have usually been attributed to adsorption and desorption of polar components from the liquid phases. There appears to be no systematic studies phases. There appears to be no systematic studies of the effect of temperature level upon capillary pressure. pressure. Equipment was constructed to permit measuring capillary pressures for simple systems at temperatures ranging from room temperature to about 350 deg. F. Drainage and imbibition capillary pressure curves were measured for three consolidated pressure curves were measured for three consolidated sandstones and one limestone sample, at either three or four temperature levels form 70 deg to 325 deg F. Fluid used were a filtered white oil and distilled water. Results for the sandstone samples were similar. The practical irreducible water saturation increased significantly as temperature was raised from 70 deg F to the maximum temperature studies - about 325 deg F. Surprisingly, the hysteresis between drainage and imbibition cycles decreased as temperature increased and was nearly absent at 300 deg F. Results indicated that the sandstone samples became markedly more water-wet as temperature level increased. Results for the limestone sample were quite different. All capillary pressure-saturation curves for the various isotherms were found to lie within the envelope of the room-temperature drainage and imbibition curves. The main objective of this study was to determine whether the supposition of Poston et al. was correct. Results are in agreement with the previous dynamic displacement work. Introduction In 1967, Poston et al reported displacement experiments on unconsolidated sands at elevated temperatures and found that the irreducible water saturation increased with temperature increase. The oil viscosity appeared to have had no real effect on their results. Although less conclusive, practical residual oil saturations (to a producing practical residual oil saturations (to a producing water-oil ratio of 100) appeared to decrease with temperature increase. The results also indicated important increases in both oil and water relative permeabilities as temperature increased. This led permeabilities as temperature increased. This led Poston et al. to suggest that temperature affects. Poston et al. to suggest that temperature affects. the sand wettability. Sessile-drop contact angle measurements indicated that the water-oil-glass contact angle decreased with temperature increase. The results of Poston et al. regarding an increase in irreducible water saturation with temperature increase and the nondependence of this finding on the viscosity ratio deserve more attention. it is a well established concept in the literature that increasing water wetness of sands is reflected in an increase in the irreducible water saturation and an increase in oil recovery efficiency. The effect on a capillary pressure-saturation curve would be to cause a shift toward increasing irreducible wetting-phase saturation. if this is the case, then the studies of McNiel and Moss and Willman et al. should give partial credit for the added oil recovery efficiency involved in hot water flooding to the effect of temperature level upon wettability. In view of the potential importance of hot fluid injection for improving oil recovery and the lack of an adequate description of the flow process and thermodynamics involved, it was decided to study the speculation of Poston et al. that capillary pressure-saturation curves should be temperature pressure-saturation curves should be temperature dependent. This study concerns the effect of temperature level upon capillary pressure-saturation relationships for consolidated porous media. SPEJ p. 13

Residual Gas Saturation Revisited

2001 ◽  
Vol 4 (06) ◽  
pp. 467-476 ◽  
Author(s):  
Apostolos Kantzas ◽  
Minghua Ding ◽  
Jong Lee
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Spontaneous Imbibition ◽  
Gas Reservoirs ◽  
Initial Water ◽  
Gas Saturation ◽  
Water Imbibition ◽  
Residual Gas ◽  
Trapped Gas ◽  
Residual Gas Saturation

Summary The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic. Introduction When a porous medium is partially or fully saturated with a nonwetting phase, and a wetting phase is allowed to invade the porous medium, the process is called imbibition. For the problem addressed in this work, the nonwetting phase is assumed to be gas, and the wetting phase is assumed to be the aquifer water. If the medium is dry and the water is imbibing, then the imbibition is primary (Swi=0). If the water is already in the medium, the imbibition is secondary (Swi>0). If there is no driving force other than the affinity to wet, the imbibition is spontaneous. If there is any other positive pressure gradient, the imbibition is called forced. Numerous papers have been written on the subject of residual oil saturation from imbibition, but fewer have been prepared on the subject of residual gas saturation from imbibition. The common perception is that many of the principles that cover oil and gas reservoirs are the same. Agarwal1 addressed the relationship between initial and final gas saturation from an empirical perspective. He worked with 320 imbibition experiments and segmented the database to develop curve fits for common rock classifications. Land2 noted that available data seemed to fit very well to an empirical functional form given asEquation 1 In this model, the only free parameter is the maximum observable trapped nonwetting phase saturation corresponding to Sgr (Sgi=1). This expression does not predict residual phase saturation, only how residual saturation scales with initial saturation. Zhou et al.3 studied the effect of wettability, initial water saturation, and aging time on oil recovery by spontaneous imbibition and waterflooding. A correlation between water wetness and oil recovery by waterflooding and spontaneous imbibition was observed. Geffen et al.4 investigated some factors that affect the residual gas saturation, such as flooding rate, static pressure, temperature, sample size, and saturation conditions before flooding. They found that water imbibition on dry-plug experiments was different from waterflooding experiments with connate water. However, they concluded that the residual gas saturation from the two types of experiments was essentially the same. Keelan and Pugh5 concluded that trapped gas saturation existed after gas displacement by wetting-phase imbibition in carbonate reservoirs. Their experiments showed that the trapped gas varied with initial gas in place and that it was a function of rock type. Fishlock et al.6 investigated the residual gas saturation as a function of pressure. They focused on the mobilization of residual gas by blowdown. Apparently, the trapped gas did not become mobile immediately as it expanded. The gas saturation had to increase appreciably to a critical value for gas remobilization. Tang and Morrow7 introduced the effect of composition on the microscopic displacement efficiency of oil recovery by waterflooding and spontaneous imbibition. They concluded that the cation valency was important to crude/oil/rock interactions. Chierici et al.8 tested whether a reliable value of reserves could be obtained from reservoir past-production performance by analyzing results from six gasfield experiments. They concluded that different gas reservoir aquifer systems could show the same pressure performance in response to a given production schedule. Baldwin and Spinler9 investigated residual oil saturation starting from different initial water saturation using magnetic resonance imaging (MRI). They concluded that at low initial water saturation, the presence of a significant waterfront during spontaneous water imbibition indicated that the rate of water transport was less than that of oil. At high initial water saturation, the more uniform saturation change during spontaneous water imbibition indicated that the rate of water transport was greater than that of oil. The pattern of spontaneous imbibition depended on sample wettability, with less effect from frontal movement in less water-wet samples. Pow et al.10 addressed the imbibition of water in fractured gas reservoirs. Field and laboratory information suggested that a large amount of gas was trapped through fast water imbibition through the fractures and premature water breakthrough. The postulation was made that such gas reservoirs would produce this gas if and when the bypassed gas was allowed to flow to the production intervals under capillary-controlled action. The question of whether the rate of imbibition could enhance the production of this trapped gas was raised. Preliminary experiments on full-diameter core pieces showed that the rates of imbibition were extremely slow and that if the different imbibition experiments were performed in full-diameter plugs, the duration of the experiments would be prohibitively long. These experiments formulated the experimental strategy presented in the following sections.

Wettability Determination and Its Effect on Recovery Efficiency

1969 ◽  
Vol 9 (01) ◽  
pp. 13-20 ◽  
Author(s):  
Erle C. Donaldson ◽  
Rex D. Thomas ◽  
Philip B. Lorenz
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Quantitative Method ◽  
Test Procedure ◽  
Dye Adsorption ◽  
Pressure Curve ◽  
Recovery Efficiency ◽  
Water Drainage ◽  
Capillary Pressure Curves

Abstract A quantitative method for measuring the wettability of porous media containing brine and crude oil has been developed by the USBM using capillary pressure curves determined with a centrifuge. These measurements were reproducible within a standard deviation of 8.2 percent. The determination of fractional wettability has been compared with a method involving a combination of imbibition and displacement. Results are in agreement qualitatively as to whether a sample was water-wet or oil-wet. When tested with outcrop cores of Torpedo Sandstone, wetting tendencies of oils from widely different fields range from highly water-wet to almost neutral. Silicone-treated cores vary in extent of wettability in a predictable manner, becoming more oil-wet as the concentration of silicone used in core preparation is increased. Wettability, used as a parameter in designing linear mathematical models for predicting recovery efficiency, is equal in significance to viscosity and permeability. permeability Introduction Wettability is one of the major factors that influences oil recovery. The importance of maintaining a water-wet condition in a field under water drive has been discussed by many authors. These authors have shown that oil recovery, as a function of the water injected, is greater from water-wet cores than from oil-wet cores. A few authors have indicated that recovery from strongly water-wet or oil-wet cores is less than recovery from cores that are at some intermediate wettability. One reason that the significance of wettability to oil recovery is still being evaluated is because a quantitative measurement of wettability has not been available when crude oil is involved. Some qualitative methods for determining the wettability of cores that are discussed in the literature includeuse of relative permeability data,imbibition,displacement pressure,capillary pressure, anda combination of imbibition and displacement. Using these methods, cores can be classified as either water-wet or oil-wet. However, these methods are not satisfactory for intermediate wettabilities between water-wet and oil-wet. Nuclear magnetic relaxation and dye adsorption offer promise of a quantitative method for determining wettability; however, they have not been widely accepted. This paper presents a quantitative technique for determining the wettability of sandstone cores containing brine and crude petroleum oils. The method is rapid and reproducible and requires only a minimum handling of the cores before testing. It also establishes a numerical wettability scale for systems ranging from strongly water-wet to strongly oil-wet. TECHNIQUE WETTABILITY TEST PROCEDURE The USBM method for determining wettability is based on a correlation, suggested by Gatenby and Marsden, between the degree of wetting and the areas under the capillary-pressure curves. The method employs the two areas under the capillary-pressure curves obtained by the centrifuge method described by Slobod et al., and extended to determine capillary pressure curves for oil and water. Gatenby and Marsden, and earlier Slobod and Blum, suggested the use of individual points on the capillary pressure curve, but the area is considered representative of the over-all wettability, as it is an integrated value over the practical range of saturations. Capillary-pressure curves obtained by the centrifugal method are not complete descriptions of the capillary pressure vs saturation relationship of a porous medium. The water imbibition curve for pressures greater than zero and the water drainage curve for pressures less than zero cannot be obtained by the centrifugal technique. SPEJ P. 13

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