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Summary The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB's). Salinity was varied by changing the concentration of total dissolved solids (TDS's) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized. Introduction Reservoir wettability has a direct influence on recovery factors for the displacement of oil by water. Laboratory studies have demonstrated the complexity of crude-oil/brine/rock (COBR) interactions and point to the uncertainty in assessments of wetting behavior in reservoirs. Displacement tests at reservoir conditions are most likely to be valid if results for preserved and restored state cores coincide. Even greater confidence follows if there is consistency between laboratory tests and in-situ measurements of reservoir residual oil saturation (ROS) and between forecasted and actual production. The expense and time involved in obtaining core-analysis data must always be weighed against their reliability and significance. Laboratory tests designed to duplicate reservoir conditions always include compromises. For example, in laboratory displacements, the connate brine and the injected brine usually have the same composition but are different in practice. Laboratory tests are run at isothermal conditions with very small pressure differences across the core. In the reservoir, the injected water is often colder than the reservoir fluids, as evidenced by thermal fracturing. To match pressure gradients within the reservoir, laboratory displacements are run at close to isobaric conditions, whereas large differences in pressure exist between injection and production wells.
- North America > United States > Wyoming (0.28)
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- (2 more...)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Asia > China > Tianjin > Bohai Basin > Huanghua Basin > Dagang Field (0.99)
- (2 more...)
Summary This paper presents a definitive account of the effect of wettability on oil recovery from Berea sandstone based on the results of more than 50 slow-rate laboratory waterfloods. Closely reproducible wettability conditions and waterflood recoveries were obtained with wettability, depending on the crude oil, brine composition, aging temperature, and initial water saturation. Maximum oil recovery by waterflooding was obtained at very weakly water-wet conditions from shortly after breakthrough up to discontinuation of the test at 20 PV of water injected. In most of the tests, coproduction of oil and water continued long after breakthrough. Introduction Numerous reports of experimental work relating to the role of wettability in various aspects of oil recovery have been published. Several recent reviews are available. All point out the diverse conclusions regarding the optimum wetting condition for oil recovery by waterflooding. This probably results from problems in obtaining wettability control and characterization and differences in the nature of the systems used in evaluating wettability effects. In several investigations, wettability of cores and other porous media was altered by chemical treatment, usually with an organochlorosilane. A disadvantage of this technique is the inconsistency in wetting condition with time because of hydrolysis and desorption of weakly adsorbed molecules. Aside from concerns about the artificial nature of such systems, no generally accepted standard procedures exist for generating a spectrum of wettability conditions by chemical treatment.
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- North America > United States > Ohio (0.25)
- North America > United States > Kentucky (0.25)
Summary Reservoir wettability is important to oil recovery by waterflooding and many other oil recovery processes. The difficulties associated with determination of in-situ wettability, together with uncertainties about application of laboratory observations to field conditions, necessitate a more basic understanding of factors that control wettability. We previously reported that the adhesion of crude oil to a solid surface could be related to wettability alteration. In this work, conditions under which oil adheres to a particular solid surface are demonstrated for several crude oils. For a given oil, pH and ionic strength were varied to obtain a mapping of conditions under which adhesion occurs. Results were satisfactorily explained by double-layer calculations in combination with the ionizable surface group model. Lack of adhesion signifies the presence of a stable water film that results from double-layer repulsion between the crude oil and the solid surface. Introduction Results of laboratory waterflows show that wettability can have a profound effect on the efficiency of displacement of oil by water. Departure from strongly water-wet conditions, which are often taken as a convenient standard, can result in either a decrease or increase in oil recovery efficiency, reflecting a range of possible wettability changes. Laboratory waterfloods in which wettability change involved the use of or exposure to crude oil are compared in Fig. 1 with results for strongly water-wet conditions. Results are presented as percent of original oil recovered (or microscopic displacement efficiency), ED, vs. PV of water injected. There is growing opinion that mixed-wettability conditions pertain in many oil reservoirs. At areas of rock surface that are contacted by the crude oil, the potential exists for adsorption of water-insoluble polar components from the crude oil. Thus, in-situ wettability may depend directly on the initial distribution of oil and interstitial water with respect to the rock surface. The results shown in Fig. 1 illustrate the importance of performing laboratory waterfloods at properly representative reservoir conditions; however, maintaining or establishing the correct conditions is a major difficulty. A much improved understanding of the effects of crude oils on wettability is needed to give confidence in core recovery and handling procedures] aimed at preservation or restoration of reservoir wettability. Contact between crude oil and rock is dependent on the stability of water films between rock surface and the crude oil. The existence of stable water films in the range of 1- to 100-nm [10- to 1,000- A] thickness has been shown to depend on the presence of an electrical double-layer repulsion that results from surface charges at the solid/water and water/oil interfaces being of the same sign. In the regions of contact, thin films contour the solid surface. except as modified by surface roughness. Water held essentially as a skin at the rock surface by electrical double-layer or shorter-range forces will be referred to as pellicular water. Equilibrium with the bulk water, which will be at some capillary pressure, is satisfied by the disjoining pressure acting in the pellicular water. A schematic of the distribution of crude oil and bulk and pellicular water in pores of a triangular cross section is shown in Figs. 2a and 2b for smooth and rough pore walls, respectively. In this paper, discussion of film stability will refer to pellicular water unless otherwise stated. As long as water-soluble surfactants from the crude or in the formation water do not alter wettability, the stability of water films between crude oil and the rock surface and their ability to prevent adsorption of water-insoluble components over geologic time are key factors in maintaining reservoirs at strongly water-wet conditions. If the film is unstable, polar components from the oil will have the opportunity to adsorb directly onto the rock surface. If the adsorbed components cannot migrate from the region of contact, a mixed-wettability condition can be expected with the distribution of oil-wet surfaces complementing the regions overlain by bulk water. Whether migration occurs or not, instability of the wetting film followed by adsorption probably results in departure from a strongly water-wet condition in the region of contact. It has been shown that film stability is dominated by pH, brine concentration, and composition. In the present study, adhesion behavior observed for crude oils is related through electrical double-layer theory to the properties of the oil/water and water/solid interfaces. Theory and Background Electric Properties of the Oil/Water Interface. It has been previously demonstrated with bitumen that an oil/water interface has a negative electric charge that can be adequately explained by the ionizable surface group (ISG) model. In the application of this model, it is assumed that the negative charge of the interface is caused by the dissociation of carboxylic acids, which are naturally occurring surfactants. In contrast to observations reported previously for bitumen, electrophoresis measurements for three conventional crude oils studied in the present work showed a change from negative to positive interfacial charge at low pH, indicating the presence of basic and acidic surface-active groups at the oil/water interface. The theoretical model applied to bitumen was therefore extended to take into account the zwitterionic nature of the crude-oil/water interface by use of a method described by Harding and Healy: (1) (1b) where A- and BH+ represent acidic and basic groups at the interface. Their dissociation constants are defined by (2a) and (2B) where [Hs+] = hydrogen ion concentration in the vicinity of the surface, which can be related to the bulk concentration, [Hb+], by use of the Boltzmann relationship, (3a) where ro is a reduced potential given by (3b) where e=electron charge, 4) oro = surface potential, k=Boltzmann constant, and T=absolute temperature. SPERE P. 332^
Summary Changes that occur with increase in capillary number in the detailed structure of residual oil trapped in water-wet sandstone core samples have been investigated. The technique of using a nonwetting phase that can be solidified and separated from the porous medium has been applied with styrene monomer as the nonwetting phase and 2% CaCl2 brine as the wetting phase. The size distributions of residual oil blobs, obtained under various flow conditions, were measured by both image analysis and Coulter counter techniques. Specific features of blob shapes and dimensions were checked by optical and electron microscopy. The changes in size distribution and shapes of blobs provide insight into the mechanisms of trapping and mobilization of residual oil. Introduction At the conclusion of waterflooding an oil-bearing reservoir, a significant fraction of the original oil still remains in the swept region as trapped residual oil. In water-wet reservoirs, this residual oil, S*or, may typically occupy 25 to 50% of the pore space and provides a main target for tertiary oil recovery. Trapped oil can provides a main target for tertiary oil recovery. Trapped oil can be recovered from a core sample at S*or, by immiscible displacement if the ratio of viscous to capillary forces, expressed in this work as the capillary number Nc = exceeds a critical value. Changes in microscopic distribution of oil within pore spaces can still occur at capillary numbers less than critical. Above the critical capillary number, Nc,(crit), oil is displaced from the core sample. In laboratory investigations, nondimensional relationships between capillary number and the ratio Sor/S*or (residual oil saturation, Sor, normalized with respect to S*or) have been found to be remarkably similar for a variety of sandstones. In addition to the amount of trapped oil. its microscopic distribution within the pore spaces of a reservoir rock is important to gain a better understanding of oil-recovery mechanisms. This knowledge may also be important to the design and implementation of tertiary recovery processes. For example, in modeling the recovery of residual oil, the viscous force required for mobilization of a residual oil blob trapped under water-wet conditions is expected to be inversely proportional to blob length. The technique of using a nonwetting phase, which after flooding to residual saturation can be solidified and then separated from the porous medium to study the microscopic structure of residual porous medium to study the microscopic structure of residual nonwetting phase, was probably first employed by Craze, who referred to the observed capillary structures as irregularly shaped blobs. Blob-size distributions have been measured in the past in sandpacks with styrene monomer as the oleic phase before solidification. The results of this study, although released, have not been made available through publication to the research community at large. A previous study in which styrene polymerization was used has also been cited but is not available. A technique for the study of residual oil structures that involved trapping of melted wax has been used by Morrow and Humphrey. Since Reed and Healy credit the method used by Humphrey to Taber's much earlier unpublished work, it is clear that blobs prepared by this technique have been examined by several investigators. Also, scanning electron micrographs (SEM's) of pore casts of blobs of residual nonwetting phase obtained through solidification of Wood's metal with hot toluene as the wetting phase have been presented by Swanson. Although considerable attention has been paid to the obviously important subject of residual oil structure, the amount of experimentally determined, quantitative information on blob structure and the statistics of blob populations is very limited. To obtain such information, satisfactory techniques for preparing statistically representative blob samples and measuring their size distributions must be devised. Once obtained, the experimentally determined blob-size distributions can be related to measured conditions for mobilization and compared with changes in size distribution predicted by theory.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Summary Phase behavior, interfacial tension (IFT), viscosity, and density data were determined for the system 2% CaCl2 brine/isopropyl alcohol (IPA)/isooctane. Liquid pairs from this system were used in a test of capillary number as a correlating function for mobilization of residual oil in geometrically similar porous media as provided by bead packs. Close correlation of results was obtained for a more than five-fold variation in permeability and a more than six-fold variation in IFT. Extensive permeability and a more than six-fold variation in IFT. Extensive investigation was also made of the change in trapped oil saturation given by vertical upward flooding; the ratio of gravity to capillary forces varied more than 100-fold. A correlation between trapped oil saturation and Bond number was obtained that was in good agreement with previous results obtained for gas entrapment. However, capillary numbers for entrapment of a given reduced residual oil saturation (ROS) were found to be slightly higher than those for entrapment of gas. Relative permeabilities were independent of whether the trapped phase was oil or gas and were determined mainly by the magnitude of the trapped nonwetting-phase saturation. Capillary numbers for mobilization of residual oil from bead packs were much higher than typical values for sandstones. For bead packs that had been consolidated by sintering, capillary numbers for prevention of entrapment increased and those for mobilization decreased. The net result was that differences in capillary numbers for mobilization and entrapment were greatly reduced and results became more akin to relationships observed for consolidated sandstones. Introduction Secondary recovery by waterflooding leads to entrapment of oil as a result of capillary action. The oil remaining in the swept zone will be referred to as normal waterflood ROS, S*,. Enhanced recovery of oil over that produced by secondary recovery can be achieved under immiscible conditions either by reducing the amount of oil entrapped or by mobilization of some of the trapped oil. For strongly wetting conditions, which are assumed to apply through-out the present work, trapped oil is held as discrete blobs. The processes of mobilization and entrapment are associated respectively with displacement of discontinuous and continuous oil. Minimization of entrapment is particularly important to maintain the integrity of banks of recovery agents and developed banks of continuous oil. Reductions in ROS with an increase in the ratio of viscous to capillary forces have been demonstrated previously. This ratio is often expressed as the dimensionless group vu/o, where o is the IFT, v is the superficial velocity, and tt is the viscosity of the displacing (wetting) phase. Relationships between capillary number and oil recovery by mobilization have been correlated fairly satisfactorily for consolidated sandstones having a wide range of permeabilities. Capillary numbers for mobilization from selected carbonate cores were much lower than for sandstones, however, showing that the correlation determined for sandstones is by no means general for consolidated rocks. One approach to more detailed delineation of the role of pore geometry in mobilization and trapping, which also provides a more meaningful testing of capillary number as a correlating function, is to investigate geometrically similar systems. In the laboratory, porous media are commonly prepared from glass beads or unconsolidated sands. With due attention to the method of packing, close-sized particles provide media that, in a statistical sense, are geometrically similar. provide media that, in a statistical sense, are geometrically similar. For such media, porosity is constant and permeability varies as r2, where r is the particle radius. Ability to scale porous media ge-ometrically is of particular value with respect to making a directest of correlations between capillary number and ROS. Furthermore, theoretical estimates of capillary numbers for oil recovery need to be tested further against experimental results. In the present work, experimental results are reported for mobilization and entrapment in unconsolidated and consolidated bead packs.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Summary The effects of interfacial tension (IFT) on displacement behavior have been investigated through flow visualization experiments in porous media formed by thin layers of sintered glass beads. Fluid densities and viscosities were matched to avoid viscous and gravitational instabilities. Displacements were carried out with aqueous/oleic liquid pairs, which gave IFT's of 17.0, 1.2, 0.029, and 0.002 dynes/cm [17.0, 1.2,0.029, and 0.002 mN/m]. Results show how IFT, wettability, and model heterogeneity interact to determine the shape and stability of the displacement front. Introduction When one fluid is displaced by another, the stability of the displacement front generally involves the complex interplay of a variety of phenomena. Instabilities that can arise when a less viscous fluid displaces a more viscous fluid lead to viscous fingering. In miscible displacement, fingers tend to be damped by dispersion; in immiscible displacement, the behavior of fingers will normally be strongly dependent on capillary forces. An interesting situation arises in low-IFT displacements because capillary forces are reduced by several orders of magnitude. Thin-layered porous media provide a convenient method of investigating the stability of displacement fronts under a wide variety of circumstances. It was recently shown that, even in porous media given by a thin layer of beads and at highly favorable mobility ratio, instabilities can arise because of gravity segregation if IFT is reduced sufficiently. In the work described here, the effect of IFT on stability is investigated in the absence of viscous and gravitational instabilities by use of fluid pairs of aqueous and organic liquids (hereafter referred to as oil and water, respectively) of closely matched density and viscosity. Under these circumstances, the effect of IFT, wettability, and porous-medium heterogeneity on the stability of displacement fronts can be observed.