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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. A novel technique has been developed and used to study the microscopic distribution of wetting and nonwetting phases in reservoir rocks during immiscible displacements. The underlying principle is the us of appropriate fluids, serving as the wetting and the nonwetting phases, that can be solidified in situ, one at a time, without altering to any significant extent the position and orientation of the phases acquired at capillary equilibrium conditions. After both phases are solidified, the rock matrix is etched and replaced by a resin to enhance the quality of polishing. Polished sections are then serially made at each 5- to 10-mu m depth and photomicrographed, wherein the three phases are distinguishable from each other. Experimental results have been obtained with Berea sandstone and the phase distribution is being analyzed, Relative permeabilities measured with the other phase solidified compare very well with conventional results obtained by the Penn State steady-state method, using Soltrol- and brine. Wettabilities of the fluid pairs were also visualized directly by this new technique. Introduction To model multiphase flow and to predict ultimate oil recoveries from reservoir formations more realistically, it is essential to study flow behavior and fluid distributions in the pore matrix on the pore level at various relative saturations. The microstructure of reservoir rocks strongly influences the transport of mass, momentum, and energy in one pore space. Both the pore geometry and pore topology dictate the motion and distribution of fluids within porous media. In addition, such factors asfluid/ fluid properties-interfacial tension (IFT), viscosity ratio, density difference, phase behavior, and interfacial mass transfer, fluid/solid properties-wettability, ion exchange, adsorption, and interaction; and magnitude of applied pressure gradient, gravity, and agings play roles in entrapment, distribution, and mobilization of oil in petroleum reservoirs. Some interesting literature on the trapping of nonwetting phase and on blob mobilization includes data on sizes, shapes, populations, and distributions. Very little has been said however, about the location and distribution of the wetting phase at or near the so-called irreducible saturation, despite the fact that many reservoirs are known to be oil-wet and that "irreducible saturation" has been shown to be a misnomer. Recently, Dullien et al. observed that the irreducible wetting-phase saturation can be reduced by a so-called leakage mechanism if high capillary pressures are maintained, owing to the hydraulic continuity of the wetting phase in pore wedges and microgrooves in the pore walls. Irreducible wetting-phase saturations depend on specific surface area, surface texture, small scale heterogeneity in microstructure, and pore size and shape distributions. Wardlaw and Cassan generalized the recovery efficiencies in terms of pore connectivities and pore sizes. To date, experimental findings correlating macroscopic flow phenomena to pore-space morphology are sketchy and principally qualitative. Although considerable efforts have been made to incorporate pore-level phenomena and pore structure data into the network models of pore space for predictions of macroscopic flow behavior, there has been a dearth of experimentally determined quantitative information on fluid distributions and pore topology for testing the validity of the theoretical models. Such parameters as pore-body and pore-throat size distributions, and pore and individual fluid-phase coordination numbers as a function of saturation, which are incorporated in the mathematical models, have not been determined experimentally. This lacuna can be attributed partly to the lack of good experimental techniques required for three-dimensional (3D) visualization of microstructures in natural porous media while the original pore and phase geometry are maintained. SPERE P. 137^
- 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)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)