Wettability Literature Survey- Part 1: Rock/Oil/Brine Interactions Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability Summary Wettability is a major factor controlling the location, flow, and distribution of fluids in a reservoir. The wettability of a core will affect almost all types of core analyses, including capillary pressure, relative permeability, waterflood behavior, electrical properties, and simulated tertiary recovery. The most accurate results are obtained when native- or restored-state cores are run with native crude oil and brine at reservoir temperature and pressure. Such conditions provide cores that have the same wettability as the reservoir. The wettability of originally water-wet reservoir rock can be altered by the adsorption of polar compounds and/or the deposition of organic material that was originally in the crude oil. The degree of alteration is determined by the interaction of the oil constituents, the mineral surface, and the brine chemistry. The procedures for obtaining native-state, cleaned, and restored-state cores are discussed, as well as the effects of coring, preservation, and experimental conditions on wettability. Also reviewed are methods for artificially controlling the wettability during laboratory experiments. Introduction This paper is the first of a series of literature surveys covering the effects of wettability on core analysis. Changes in wettability have been shown to affect capillary pressure, relative permeability, waterflood behavior, dispersion of tracers, simulated tertiary recovery, irreducible water saturation (IWS), residual oil saturation (ROS), and electrical properties. For core analysis to predict the behavior of a reservoir accurately, the wettability of a core must be the same as the wettability of the undisturbed reservoir rock. A serious problem occurs because many aspects of core handling can drastically affect wettability. Water-Wet, Oil-Wet, and Neutrally Wet. Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. "In a rock/oil/brine system, it is a measure of the preference that the rock has for either the oil or water. When the rock is water-wet, there is a tendency for water to occupy the small pores and to contact the majority of the rock surface. Similarly, in an oil-wet system, the rock is preferentially in contact with the oil; the location of the two fluids is reversed from the water-wet case, and oil will occupy the small pores and contact the majority of the rock surface. It is important to note, however, that the term wettability is used for the wetting preference of the rock and does not necessarily refer to preference of the rock and does not necessarily refer to the fluid that is in contact with the rock at any given time. For example, consider a clean sandstone core that is saturated with a refined oil. Even though the rock surface is coated with oil, the sandstone core is still preferentially water-wet. This wetting preference can be preferentially water-wet. This wetting preference can be demonstrated by allowing water to imbibe into the core. The water will displace the oil from the rock surface, indicating that the rock surface "prefers" to be in contact with water rather than oil. Similarly, a core saturated with water is oil-wet if oil will imbibe into the core and displace water from the rock surface. Depending on the specific interactions of rock, oil, and brine, the wettability of a system can range from strongly water-wet to strongly oil-wet. When the rock has no strong preference for either oil or water, the system is said to be of neutral (or intermediate) wettability. Besides strong and neutral wettability, a third type is fractional wettability, where different areas of the core have different wetting preferences. The wettability of the rock/fluid system is important because it is a major factor controlling the location, flow, and distribution of fluids in a reservoir. In general, one of the fluids in a porous medium of uniform wettability that contains at least two immiscible fluids will be the wetting fluid. When the system is in equilibrium, the wetting fluid will completely occupy the smallest pores and be in contact with a majority of the rock surface (assuming, of course, that the saturation of the wetting fluid is sufficiently high). The nonwetting fluid will occupy the centers of the larger pores and form globules that extend over several pores. In the remainder of this survey, the terms wetting and nonwetting fluid will be used in addition to water-wet and oil-wet. This will help us to draw conclusions about a system with the opposite wettability. The behavior of oil in a water-wet system is very similar to the behavior of water in an oil-wet one. JPT P. 1125
Summary Many methods have been used to measure wettability. This paper describes the three quantitative methods in use today: contact angle, Amott method, and the U.S. Bureau of Mines (USBM) method. The advantages and limitations of all the qualitative methods-imbibition, microscope examination, flotation, glass slide, relative permeability curves, capillary pressure curves, capillarimetric method, displacement capillary pressure, permeability/saturation relationships, and reservoir logs-are pressure, permeability/saturation relationships, and reservoir logs-are covered. Nuclear magnetic resonance (NMR) and dye adsorption, two methods for measuring fractional wettability, are also discussed. Finally, a method is proposed to determine whether a core has mixed wettability. Introduction This paper is the second in a series of literature surveys covering the effects of wettability on core analysis. Changes in the wettability of cores have been shown to affect electrical properties, capillary pressure, waterflood behavior, relative permeability, dispersion, and simulated EOR. For core analysis to predict the behavior of the reservoir, the wettability of the core must be the same as the wettability of the undisturbed reservoir rock. When a drop of water is placed on a surface immersed in oil, a contact angle is formed that ranges from 0 to 180 deg. [0 to 3.14 rad]. A typical oil/water/solid system is shown in Fig. 1, where the surface energies in the system are related by Young's equation, (1) where sigma = interfacial energy [interfacial tension (IFT)] between the oil and water, sigma = interfacial energy between the oil and solid, sigma = interfacial energy between the water and solid, and theta = contact angle, the angle of the water/oil/solid contact line. By convention, the contact angle, theta, is measured through the water. The interfacial energy sigma is equal to or, the IFT. As shown in Fig. 1, when the contact angle is less than 90 deg. [1.6 rad], the surface is preferentially water-wet, and when it is greater than 90 deg. [1.6 rad], the surface is preferentially oil-wet. For almost all pure fluids and clean preferentially oil-wet. For almost all pure fluids and clean rock or polished crystal surfaces, sigma, and sigma, have values such that theta=0 deg. [0 rad]. When compounds such as crude-oil components are adsorbed on rock surfaces, these interfacial energies are changed unequally. This changes theta and hence the wettability. The farther theta is from 90 deg. [1.6 rad], the greater the wetting preference for one fluid over another. If theta is exactly 90 deg. [1.6 rad], neither fluid preferentially wets the solid. As shown in Table 1, when preferentially wets the solid. As shown in Table 1, when theta is between 0 and 60 to 75 deg. [0 and 1 to 1.3 rad], the system is defined as water-wet. When theta is between 180 and 105 to 120 deg. [3.1 and 1.8 to 2.1 rad], the system is defined as oil-wet. In the middle range of contact angles, a system is neutrally or intermediately wet. The contact angle that is chosen as the cutoff varies from paper to paper. The term a sigma - sigma is is sometimes called the adhesion tension, theta : (2) The adhesion tension is positive when the system is water-wet, negative when the system is oil-wet, and near zero when the system is neutrally wet. Methods of Wettability Measurement Many different methods have been proposed for measuring the wettability of a system. They include quantitative methods-contact angles, imbibition and forced displacement (Amott), and USBM wettability method-and qualitative methods-imbibition rates, microscope examination, flotation, glass slide method, relative permeability curves, permeability/saturation relationships, permeability curves, permeability/saturation relationships, capillary pressure curves, capillarimetric method, displacement capillary pressure, reservoir logs, nuclear magnetic resonance, and dye adsorption. Although no single accepted method exists, three quantitative methods generally are used:contact-angle measurement,the Amott method (imbibition and forced displacement), andthe USBM method. The contact angle measures the wettability of a specific surface, while the Amott and USBM methods measure the average wettability of a core. A comparison of the wettability criteria for the three methods is shown in Table 1. The remaining tests in the list are qualitative, each with somewhat different criteria to determine the degree of water or oil wetness. JPT P. 1246
Summary. The wettability of a core will strongly affect its waterflood behavior and relative permeability. Wettability affects relative permeability because it is a major factor in the control of the location, flow, and distribution of fluids in a porous medium. In unfamiliar or fractionally wetted porous media, the water relative permeability increases and the oil relative permeability decreases as the system becomes more oil- wet. In a mixed-wettability system, the continuous oil-wet paths in the larger pores alter the relative permeability curves and allow the system to be waterflooded to a very low residual oil saturation (ROS) after the injection of many PV's of water. The most accurate relative permeability measurements are made on native-state core, where the reservoir wettability is preserved. Serious errors can result when measurements are made on cores with altered wettability, such as cleaned core or core contaminated with drilling-mud surfactants. Introduction This paper is the fifth in a series of literature surveys covering the effects of wettability on core analysis. Wettability has been shown to affect waterflood behavior, relative permeability, capillary pressure, irreducible water saturation (IWS), ROS, dispersion, simulated tertiary recovery, and electrical properties. Earlier, but less complete, reviews covering the effects of wettability on waterflooding and relative permeability can be found in Refs. 6 through 16. Relative permeability is "a direct measure of the ability of the porous system to conduct one fluid when one or more-fluids are present. These flow properties are the composite effect of pore geometry, wettability, fluid distribution, and saturation history." Wettability affects relative permeability because it is a major factor in the control of the location, flow, and spatial distribution of fluids in the core. Craigs and Raza et al. have given good summaries of the effects of wettability on the distribution of oil and water in a core. Most experimental studies that examined fluid dis-tribution as a function of wettability used bead packs or othe micromodels, although some more recent studies have used reservoir rock and fluids such as epoxy or Wood's metal that can be solidified in situ (e.g., see Yadav et al.). Consider a strongly water-wet rock initially at IWS. Water, the wetting phase, will occupy the small pores and form a thin film over all the rock surfaces. Oil, the nonwetting phase, will occupy the centers of the larger pores. This fluid distribution occurs because it is the most energetically favorable. Any oil placed in the small pores would be displaced into the center of the large pores by spontaneous water imbibition, because this would lower the energy of the system. During a waterflood of a water-wet system, water moves through the porous medium in a fairly uniform front. The injected water will tend to imbibe into any small- or medium-sized pores, moving oil into the large pores where it is easily displaced. Only oil is moving ahead of the front. In the frontal zone, each fluid moves through its own network of pores, but with some wetting fluid located in each pore. In this zone, where both oil and water are flowing, a portion of the oil exists in continuous channels with some dead-end branches, while the remainder of the oil is trapped discontinuous globules. Fig. 1a, taken from Raza et al., shows water displacing oil from a water-wet pore. The rock surface is preferentially wetted by the water, so water will advance along the walls of the pore, displacing oil in front of it. At some point, the neck connecting the oil in the pore with the remaining oil will become unstable and snap off, leaving a spherical oil globule trapped in the center of the pore. After the water front passes, almost all the remaining oil is immobile. Because of such immobility in this water-wet case, there is little or no production of oil after water breakthrough. The disconnected, residual oil exists in two basic forms:small, spherical globules in the center of the larger pores, andlarger patches of oil extending over many pores that are completely surrounded by water. In a strongly oil-wet rock, the rock is preferentially in contact with the oil, and the location of the two fluids is reversed from the water-wet case. Oil generally will be found in the small pores and as a thin film on the rock surfaces, while water will be located in the centers of the larger pores. The interstitial water saturation appears to be located as discrete droplets in the centers of the pore spaces in some strongly oil-wet reservoirs. A waterflood in a strongly oil-wet rock is much less efficient than one in a water-wet rock. When the waterflood is started, the water will form continuous channels or fingers through the centers of the larger pores, pushing oil in front of it (see Fig. 1b). Oil is left in the smaller crevices and pores. As water injection continues, water invades the smaller pores to form additional continuous channels, and the WOR of the produced fluids gradually increases. When sufficient water- filled flow channels form to permit nearly unrestricted water flow, oil flow practically ceases. The remaining oil is found (1) filling the smaller pores, (2) as a continuous film over the pore surfaces, and (3) as larger pockets of oil trapped and surrounded by water. Because much of this oil is still continuous through the thin oil films and can be produced at a very slow rate, the ROS is not well-defined. In this paper, the terms "wetting" and "nonwetting" will be used in addition to water-wet and oil-wet. This will more easily enable us to draw conclusions about a system with the opposite wettability. For example, a waterflood in a system of one wettability will behave in the same manner as an oilflood in the same system with the wettabilities reversed. Relative permeability curves will also show that the fluids can exchange positions and flow behavior. Because relative permeability is a function of saturation history, hysteresis in the relative permeability curves is often observed when comparing relative permeabilities measured with increasing vs. decreasing wetting-phase saturations. "Imbibition" is often used to refer to flow that results in increasing wetting-phase saturations, while "drainage" refers to flow with decreasing wetting-phase saturations. For example, waterflooding a waterwet rock is an imbibition process, while waterflooding an oil-wet rock is a drainage process. JPT P. 1452^
Summary. The wettability of a core will strongly affect its waterflood behavior and relative permeability because wettability is a major factor controlling the location, flow, and distribution of fluids in a porous medium. When a strongly water-wet system is waterflooded, recovery at water breakthrough is high, with little additional oil production after breakthrough. Conversely, water breakthrough occurs much earlier in strongly oil-wet systems, with most of the oil recovered during a long period of simultaneous oil and water production. Waterfloods are less efficient in oil-wet systems compared with water-wet ones because more water must be injected to recover a given amount of oil. This paper examines the effects of wettability on waterflooding, including the effects on the breakthrough and residual oil saturations (ROS's) and the changes in waterflood behavior caused by core cleaning. Also covered are waterfloods in heterogeneously wetted systems. Waterfloods in fractionally wetted sandpacks, where the size of the individual water-wet and oil-wet surfaces are on the order of a single pore, behave like waterfloods in uniformly wetted systems. In a mixed-wettability system, the continuous oil-wet paths in the larger pores alter the relative permeability curves and allow the system to be waterflooded to a very low ROS after the injection of many PV's of water. Introduction This paper is the sixth in a series of literature surveys covering the effects of wettability on core analysis. Wettability has been shown to affect waterflood behavior, relative permeability, capillary pressure, irreducible water saturation (IWS), ROS, dispersion, simulated tertiary recovery, and electrical properties. Earlier but less complete reviews covering the effects of wettability on waterflooding and relative permeability can be found in Refs. 6 through 17. Waterflooding is a frequently used secondary recovery method in which water is injected into the reservoir, displacing the oil in front of it. Assuming that the reservoir is initially at IWS, only oil is produced until breakthrough, the time when water first appears at the production well. After breakthrough, increasing amounts of water and decreasing amounts of oil are produced. The process continues until the WOR is so high that the well becomes uneconomical to produce. Waterfloods in water-wet and oil-wet systems have long been known to behave very differently. For uniformly wetted systems, it is generally recognized that a water-flood in a water-wet reservoir is more efficient than one in an oil-wet reservoir. An example of the effect of wettability on waterflood performance calculations is shown in Fig. 1. Steady-state oil/water relative permeabilities were measured in an outcrop Torpedo sandstone using a mild NaCl brine and a 1.7-cp [ 1.7-mPa-s] refined mineral oil. The wettability of the system was controlled by adding either (1) various amounts of barium dinonyl naphthalene sulfonate to the oil, which made the system more oil-wet, or (2) Orvus K TM liquid (a detergent) to the brine to achieve a strongly water-wet system with a contact angle of O degrees through the brine. Wettability was monitored by contact-angle measurements on a quartz crystal. The measured relative permeability curves were used to calculate field performance, assuming a single 20-acre [8-ha] five-spot with homogeneous properties. Oil and water viscosities were assumed to be 1.74 and 0.35 cp [1.74 and 0.35 mPa-s], respectively. The calculated waterflood results are shown in Fig. 1, where water breakthrough is the point at which each curve first becomes nonlinear. Fig. 1 demonstrates that earlier water break-through and less efficient oil recovery occur as the system becomes more oil-wet. For example, 8 % less oil will be produced at a WOR of 25 if the contact angle is 138 degrees [2.4 rad], rather than 47 degrees [0.82 rad]. Waterflood recovery is controlled by the oil and water relative permeabilities of a system and by the water/oil viscosity ratio. In laboratory-scale experiments, inlet and outlet end effects can also affect the recovery. The effects of relative permeabilities and viscosity ratio on waterflooding are demonstrated by the fractional flow equation. If we neglect capillary effects and assume a horizontal system, the simplified form of the fractional flow equation (e.g., see Craig) is (1) where fw = fractional flow of water, Sw = water saturation, = oil and water viscosities, respectively, cp, and = oil and water relative permeabilities, respectively. Eq. 1 shows that the fractional flow of water at a given saturation is increased when the water/oil viscosity ratio is decreased. Decreasing the water/oil viscosity ratio will cause earlier breakthrough and less efficient oil production. Similar effects will occur when the water/oil relative permeability ratio is increased. The oil and water relative permeabilities are explicit functions of the water saturation. They are also affected by pore geometry, wettability, fluid distribution, and saturation history. Water-Wet Systems. As discussed by Anderson, wettability has a strong effect on relative permeability. As the core becomes more oil-wet, the water relative permeability increases and the oil relative permeability decreases. The water will flow more easily in com-parison with the oil during a waterflood, causing progressivelearlier breakthrough and less efficient recovery. Wettability affects relative permeability and waterflood behavior because it is a major factor controlling the location, flow and spatial distribution of fluids in the core. Craigs and Raza et al. have given good summaries of the effects of wettability on the distribution of oil and water in a core. Consider a strongly water-wet rock initially at the IWS. Water, the wetting phase, will occupy the small pores and form a thin film over all the rock surfaces. Oil, the nonwetting phase, will occupy the centers of the larger Pores. This fluid distribution occurs because it is most energetically favorable. Any oil placed in the small pores would be displaced into the center of the large pores by spontaneous water imbibition, because this would lower the energy of the system. JPT P. 1605^
Wettability Literature Survey- Part 4: Effects of Wettability Part 4: Effects of Wettability on Capillary Pressure Summary. The capillary-pressure/saturation relationship depends on the interaction of wettability, pore structure, initial saturation, and saturation history. No simple relationship exists that relates the capillary pressures determined at two different wettabilities. Therefore, the most accurate measurements are made with cores that have native reservoir wettability. In a uniformly wetted porous medium, pore geometry effects and the extremely rough surfaces of the porous medium make the capillary pressure curve insensitive to wettability for small contact angles (less than about 50 deg.[0.87 rad] for drainage capillary pressure curves and less than about 20 deg. [0.35 rad] for spontaneous-imbibition capillary pressure curves). When the porous medium has fractional or mixed wettability, both the amount and distribution of the oil-wet and water-wet surfaces are important in determining the capillary pressure curve, residual saturations, and imbibition behavior. Imbibition also depends on the interaction of wettability, pore structure, initial saturation, and saturation history. Because of these interactions, there is a large range of contact angles where neither oil nor water will imbibe freely into a uniformly wetted reservoir core. In contrast, it is sometimes possible for both fluids to imbibe freely into a core with fractional or mixed wettability. Contact Angles, Capillary Pressure, and Wettability This paper is the fourth in a series of literature surveys covering the effects of wettability on core analysis. Changes in the wettability of cores have been shown to affect electrical properties, capillary pressure, waterflood behavior, relative permeability, dispersion, simulated tertiary recovery, irreducible water saturation (IWS), and residual oil saturation (ROS). When oil and water are placed together on a surface, a curved interface between the oil and water is formed, with a contact angle at the surface that can range from 0 to 180 deg. [0 to 3.15 rad]. By convention, the contact angle, 0, is measured through the water. Generally, when 0 is between 0 and 60 to 75 deg. [0 and 1.05 to 1.31 rad], the system is defined as water-wet. When 0 is between 180 and 105 to 120 deg. [3.15 and 1.83 to 2.09 rad], the system is defined as oil-wet. In the middle range of contact angles, a system is neutrally or intermediately wet. It can be shown that whenever an oil/water interface is curved, the pressure will abruptly increase across the interface to balance the interfacial tension (IFT) forces. This pressure jump, which is the capillary pressure, is given by Laplace's equation : (1) where sigma = IFT, P = capillary pressure, p = pressure in the oil, p = pressure in the water, and r1, r2 = radii of curvature of the interface, measured perpendicular to each other. By convention, the capillary pressure is defined as po-pw. Because of this definition, a radius of curvature po-pw. Because of this definition, a radius of curvature directed into the oil is positive, while one directed into the water is negative. Depending on the curvature of the surface, the capillary pressure can be positive or negative. When the interface is flat, the capillary pressure is zero. When fluids other than oil and water are used, the capillary pressure is usually defined as (2) where pNW is the pressure in the nonwetting fluid and pWET is the pressure in the wetting fluid. pWET is the pressure in the wetting fluid. The radii of curvature of the interface, and hence the capillary pressure, are determined by local pore geometry, wettability, saturation, and saturation history. For most porous media, the equations for the interfacial curvature are much too complicated to be solved analytically, and capillary pressure must be determined experimentally. In these cases, a simple relationship between contact angle and capillary pressure cannot be derived. One geometry where capillary pressure can be calculated as a function of geometry, wettability, and IFT is a capillary tube. Laplace's equation can be used to solve for the capillary pressure as a function of IFT, contact angle, and rt, the radius of the tube. P. 1283
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