Low Relative Permeability Research Articles

Effect of Crude-Oil-Induced Wettability Changes on Oil Recovery

Summary Displacements in strongly water-wet cores are compared with results of similar tests for a mixed wettability condition induced by a selected crude oil. Cores exposed to crude oil showed weakly water-wet imbibition behavior and 30 to 65% improvement in microscopic displacement efficiency. Other characteristics included clean breakthrough and low relative permeability to water at residual oil saturation. Flow visualization experiments with crude oil in micromodels showed improved oil recovery from pore bodies with oil trapping in pore throats. Capillary numbers for mobilization of residual oil from weakly water-wet systems were higher than for strongly water-wet systems. Contact-angle measurements showed that adsorbed transition metal ions at a high-energy surface could have a dominant effect on wetting behavior.

Reasons for Production Decline in the Diatomite, Belridge Oil Field: A Rock Mechanics View

Strickland, Frank G.; SPE; Dow Chemical U.S.A. Summary This paper summarizes research conducted on diatomite cores from the Belridge oil field in Kern County, CA. The study was undertaken to explain the rapid decline in oil production in diatomite wells by investigating three of six possible reasons. Characterization of the rock indicated that the rock was composed of principally amorphous opaline silica diatoms with only a trace of crystoballite quartz or chert quartz. Physical properties tests showed the diatomite to be of very low strength and plastic. It was established that long-term creep of diatomite into a propped fracture proceeds at a rate of approximately 1.5 microns/D [1.5 /d], a phenomenon that may contribute to rapid production declines. Also revealed was a matrix strength for the formation of about 1,325 psi [9136 kPa], a critical value to consider when depleting the reservoir. This also may help to explain the phase transformation to Opal CT around 2,000- to 2,500-ft [610- to 762-m] depth. Introduction The sample depths for this study were 1,530 and 1,915 m [466 and 584 m]. The study was undertaken to investigate the rapid decline in oil production in wells drilled in diatomite. The approach was two-fold:a characterization of the rock was taken andthe physical properties of the diatomite were investigated as they apply to fracture stimulation. Before noting specifics, we discuss the reasons certain tests were chosen over others. The rapid production declines may be caused by one or all of at least six reasons.Erosion or abrasion of the soft formation face by hard, dense, angular proppant generates fines that later, during production, migrate and progressively seal off the proppant pack permeability(see Fig. 1).Initial embedment of the hard proppant into the soft surface of the formation immediately following the completion of the fracture treatment causes flaking of the surface. This generates particlesfree to migrate; in addition, the proppant pack width is decreased substantially (see Fig. 2).Long-term creep of the soft formation around the proppant is causedby high in-situ pressure and/or temperature encountered downhole. This also causes loss of the effective proppant pack width (seeFig. 3).As the fluids and/or gas are produced from the formation, the porepressure or reservoir pressure is decreased, which has the effectof increasing the effective stress (compressional load) on the proppant. When this value exceeds the strength of the formationface, large-scale embedment takes place with a resulting drop inpermeability and production.The intersection of a limited number of natural fractures during stimulation treatment caused flush production. As the fissures aredrained, the production declines to what can be produced throughthe tight matrix permeability.The formation has very low relative permeability to oil. Of thesesix possibilities, only three (2,3, and 4) were addressed during this research. One (5) was supported by observations of what appeared to be natural fractures in the cores. Specimen preparation was far from being trivial. The soft nature of the diatomite led to disking, desiccation, and expansion upon retrieval from depth. Extreme care had to be taken in handling the core. It had to be sealed into a polyvinyl chloride (PVC) pipe with drilling mud poured into the annular space. In addition, the core was hand carried from the well location by plane to the laboratory, and specimens were prepared within a few days after arrival. Even with such precautions, the amount of usable samples obtained was just sufficient to conduct one each of the following tests, with no duplications at this time. Consequently, the results discussed further must be taken with caution, since no statistical theory could be applied at the time. Geological Description Issacs described three phases of mineralogy in the diatomite, with transitions occurring from temperature and pressure changes (Fig. 4). He mentioned that each type has significantly different properties, especially in the areas of porosity and permeability. Characterization of the rock was conducted using X-ray diffraction, spectrographic analysis, scanning electron microscope (SEM) analysis, petrographic microscope, and energy-dispersive analysis on the SEM. Petrographic Microscope Analysis Thin sections of the cores were prepared from each of the two zones and examined under the petrographic microscope. JPT P. 521^

TAILINGS POND BEHAVIOR AND CHARACTERIZATION OF OIL SAND TAILINGS SLUDGE

ABSTRACT Oil sand tailings are disposed of in large tailings ponds by upstream dyke construction and beaching. Sand separates and forms a gentle beach; the thin sludge flows into the pond as a density current, sedimentation takes place, and the rate of density increase rapidly becomes dominated by consolidation processes. The effect of the presence of bitumen on particles is an acceleration of sedimentation as the result of plastic collisions and agglomeration of particles. However, consolidation time is lengthened because the sludge solids have low relative densities and permeabilities. New system definitions are presented to account for the presence of bitumen as a non-mobile phase. A nomogram for oil sand sludge is presented to allow direct determination of sludge density and solids content from bitumen and water content. New experimental procedures for index tests are given, as the presence of bitumen creates laboratory difficulties. Grain size analysis and clay mineralogy require removal of bitumen, ...

Relative Permeability During Cyclic Steam Stimulation of Heavy-Oil Reservoirs

Introduction Reliable relative permeability data are important to the overall planning for prospective thermal recovery projects. Empirically derived relative permeability functions presented here have characteristics quite different from those determined experimentally. The empirical functions emerged from simulations of numerous ongoing thermal projects in unconsolidated heavy-oil reservoirs from Trinidad, West Germany, Canada, and the U.S.The cyclic steam process involves strongly changing saturation and pressure conditions during alternating imbibition and drainage cycles. Three-phase flow effects are to be expected in this process, where both steam and mobile water are found in the presence of oil due to steam condensation. Experimental procedures for determining relative permeability on a microscopic scale often ignore dependency on saturation history (hysteresis), changing pressure levels, and three-phase effects. Hence, relative permeability in this process (and in other thermal processes) often is considered a weakly determined parameter. The thermal simulator, which has been available since 1973, provides insight into the nature of relative permeability on a reservoir scale. Thermal Reservoir Simulator A volatile-oil steamflood simulator developed by Todd, Dietrich & Chase Inc. was used during analysis of the field thermal projects. This model is a fully implicit, finite-difference-based program that can treat up to four mass conservation equations and an energy balance. There are three phases: aqueous, liquid hydrocarbon, and vapor. The four mass species are water, a nonvolatile heavy oil, and two volatile components. Although only water and a dead-oil component were used in the majority of field projects, all four mass species were needed in some projects. The volatile components have been used to model (1) noncondensable-gas and CO2 additives to steam, (2) solution-gas and free-gas effects, and (3) distillation of hydrocarbon pseudocomponents.The model was employed in two-dimensional areal and vertical (cross section) simulations and in three dimensions, using Cartesian (x, y, z) and cylindrical (r, o, z) coordinates. Relative permeability functions were changed between the injection and production stages of the cyclic steam process to model the previously noted imbibition and drainage hysteresis effects. Empirical Relative Permeability Functions Relative permeability relationships shown in Fig. 1 are typical of those developed empirically (through simulation) to reproduce observed producing water/oil ratios in cyclic steam projects worldwide. In this work, two-phase data similar to those shown in Figs. 1a and 1b were used with a modified form of Stone's expression to generate three-phase oil relative permeability functions. These functions were used with adjustments for temperature dependency (Table 1) to match drainage production behavior. In each field application, very low water relative permeability curves (0.0025 is lesser than krwro is lesser than 0.25) were required to reproduce field performance. These empirically developed curves are much lower than those routinely measured (0.05 is lesser than krwo is lesser than 0.25) during imbibition water/oil relative permeability tests using unconsolidated core material.Experimentally determined imbibition water relative permeability curves often are used successfully to match observed steam injection pressures and rates. Physical Basis Several complementary conjectures are offered regarding a physical basis for the empirically derived relative permeability functions. Hysteresis of drainage and imbibition nonwetting-phase relative permeability curves is an established phenomenon. Only recently are experimental results appearing in the literature that indicate wetting-phase hysteresis. Jones and Roszelle showed that water relative permeability exhibits pronounced hysteretic behavior in water-wet sandstone, and Schneider and Owens demonstrated oil relative permeability hysteresis in oil-wet carbonate. These results support the speculation that water relative permeability (in water-wet sands) is much lower on the production cycle (drainage) than on the injection (imbibition) cycle during cyclic steam stimulation.A second complementary conjecture is related to mechanical stress. JPT P. 1987^

Soil Piping and Stream Channel Initiation

The hydrologic significance of soil piping has been generally ignored. Piping has been associated primarily with drylands, yet evidence of piping is available from a large range of climatic regions. In particular, soil piping is found to be widespread in the United Kingdom. Preferred locations for piping are either just above or within a horizon of low relative permeability and low aggregate stability. Chemical environment may range from acidic moorland soils to saline marshes. There are significant trends to lower aggregate stability and coarser grain size (particularly in the range above 250 μm) in the bed of a pipe than in the roof. Many pipes in the areas studied appear to be dormant or relatively inactive and may well be in approximate equilibrium with the soil pore and channel subsystems. However, when equilibrium is destroyed (e.g., by stream incision) pipes can form loci for channel extension. Studies of the spatial distribution of outlets show that to create normal channel networks, pipe clusters within the ensemble and, similarly, individual pipes within those clusters must be selected on an unequal basis. A low density random selection from pipes located on percolines would fulfill the requirements. The presence of piping may have a significant effect on the form of the hydrograph.

Sandstone and Carbonate Two- and Three-Phase Relative Permeability Characteristics

Abstract Three-phase relative permeability characteristics applicable to various oil displacement processes in the reservoir such as combustion and alternate gas-water injection were determined on both outcrop and reservoir core samples. Steady-state and nonsteady-state tests were performed on a variety of sandstone and carbonate core samples having different wetting properties. Some of the tests were performed on preserved samples. Some of the three-phase tests were performed on samples that contained two flowing phases and a third nonflowing phase, either gas or oil. These were classed as three-phase flow tests because the third phase played an important role in the flow behavior which was determined. The three-phase relative permeability test results are directly compared with the results of two-phase gas-oil and water-oil test. Wetting-phase relative permeability was found to be primarily dependent on its own saturation, i.e., relative permeability to the wetting phase during three-phase flow was in agreement with and could be predicted from the tow-phase data. Nonwetting-phase relative permeability-saturation relationships were found to be more complex and to depend in some cases on the saturation history of both nonwetting phases and on the saturation ratio of the second nonwetting phase and the wetting phases. Trapping of a given nonwetting phase or mutual flow interference between the two nonwetting phases when both are flowing accounts for most of the low relative permeabilities observed for three-phase flow tests. However, in special cases nonwetting-phase relative permeabilities at a given saturation are higher than those given by two-phase flow data. Despite these complexities some types of three-phase flow behavior can be predicted from two-phase flow data. Through its effect on the spatial distribution of the phases, wettability is shown to be a controlling factor in determining three-phase relative permeability characteristics. however, despite the importance of wettability the present data shown that for both water-wet and oil-wet systems oil recovery can be improved by several different injection processes, but the additional oil recovery is accompanied by lower fluid mobility. Introduction The increasing emphasis on optimizing recovery and the rapid and extensive development and use of mathematical modes for predicting reservoir performance are together creating a widespread need for reliable basic data on rock flow behavior. The two-phase imbibition or drainage flow relationships common to conventional oil recovery processes (depletion, gas or water injection, gravity drainage) are not applicable to some of the newer secondary and tertiary recovery techniques. This is because the reservoir displacement process may differ from that easily simulated in laboratory relative permeability studies. in some situations, data are needed fro a three-phase system where almost any combination of two fluids or even all three fluids may be flowing. In other, however, only two flowing phases are present, but the saturation history of the system is unique. Leverett and Lewis were the first to collect experimental relative permeability data on a three-phase system. Corey et al. were similarly leaders in efforts to define three-phase flow relationships using empirical approaches. Space does not permit a critical review of these earlier works. For those interested, a recent article by Saraf and Fatt provides a brief discussion of the experimental techniques used by earlier investigators. Suffice it to say that both experimental and empirical approaches have been used, but the applicability of both has been limited because in only one case have three-phase relative permeability data been obtained on reservoir rock material. SPEJ P. 75ˆ

Deerfield Pilot Test of Recovery by Steam Drive

VALLEROY, V.V., ESSO PRODUCTION RESEARCH CO., HOUSTON, TEX. WILLMAN, B.T., ARABIAN AMERICAN OIL CO., DHAHRAN, SAUDI ARABIA CAMPBELL, J.B., HUMBLE OIL and REFINING CO., OKLAHOMA CITY, OKLA. POWERS, L.W., KINGSVILLE, TEX., MEMBERS AIME Abstract A steam drive of heavy oil was field tested in a shallow, low oil-saturation formation near Deerfield, Mo. The pilot was conducted in the Warner formation, a sandstone containing an 18 degrees API oil having 1,000-cp viscosity at the 60F original reservoir temperature. The formation was at a depth of 160 ft. Steam was injected into nine input wells arranged in an array of inverted five-spot patterns. In the completely confined center pattern, 14 temperature observation wells were installed to obtain thermal data and observe test progress. Late in the test, slugs of ammonia were injected to trace the flow paths of injected fluids. From the test area about 7,000 bbl of oil were produced. Data were obtained on areal and vertical temperature distribution, steam front advance, reservoir fluid movement and terminal saturations. This field test of a steam drivedemonstrated the feasibility of the method,confirmed that the low residual oil saturations observed in the laboratory are obtained in the steam-swept region in the field andprovided recovery and conformance data for one set of field conditions. Introduction The Deerfield steam drive pilot test located in Vernon County, Mo., was conducted in a shallow sandstone containing 1,000-cp oil. The venture was undertaken cooperatively by the research and production departments of Carter Oil Co., which organizations have since been consolidated into Esso Production Research Co. and Humble Oil and Refining Co., respectively. The production department was interested in steam injection at Deerfield because it appeared to be the most promising method of commercially producing this heavy oil deposit. The research department was interested in applying the new recovery method and in evaluating its performance in the field. At the time the test was begun, the initial oil saturation was not well known. Subsequent air coring and early pilot results confirmed that there was too little oil in place for profitable commercial exploitation by steam. Pilot termination at that time, however, would have been premature for evaluating field performance of the process, and the test was continued to obtain additional data on steam injection as a recovery method. DESCRIPTION OF PILOT TEST The test was located about 10 miles north of the town of Deerfield and only a few miles from the Kansas border. The pilot site was selected as typical of the area. The location represented neither the highest nor the lowest oil saturation region in the acreage under lease in 1954. The steam drive was conducted in the Warner sandstone of Lower Pennsylvanian age. At the test site the top of the Warner occurs at about 160 ft subsurface and the formation is a fine- to medium-grained micaceous sandstone that dips gently to the northwest at the rate of 12 to 15 ft/ mile. A cross-section and permeability profile of the test location are shown in Fig. 1. At the pilot location the average total thickness of the Warner formation is about 43 ft, but the effective thickness for steam drive is 26 ft. Two distinct types of hydrocarbon saturation are apparent. The lower portion of the total sand, averaging about 17 ft thick, contains a very heavy asphaltic material that will not flow under the influence of a steam drive. This bottom interval, referred to as a dead oil residue, was not considered as part of the net sand undergoing steam exploitation. The initial formation and fluid properties of the upper 26 ft in the test area are summarized in Table l, and variation of oil viscosity with temperature is shown in Fig. 2. Imbibition tests on preserved core samples taken at the end of the pilot test showed that the Warner sandstone was then neutral or slightly water-wet. Initially, the reservoir may have been strongly water-wet as indicated by low relative permeability to water during both water injection testing and early steam injection. PRIOR HISTORY Initial production tests of wells at the pilot site produced water with only a faint show of oil. No gas was produced except at Well 7-W in the pilot area and at another well about 1/3 mile northeast of the pilot. Prior to the start of the steam drive, a two-well water injection test and a two-well air injection test were conducted. No oil was produced by either. Water was pumped into Well 1-W in the northeast corner of the pilot area with simultaneous production from Well 1 (Fig. 3). The air-injection test was run at input Well 9-W and its offset, Well 2, in the southwest corner. Air and water injectivities were about the same when corrected for viscosity and pressure differences. JPT P. 956ˆ