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Results
The Effect of Crude-Oil Aging Time and Temperature on the Rate of Water Imbibition and Long-Term Recovery by Imbibition
Zhou, Xiam-min (Western Research Inst./U. of Wyoming) | Torsaeter, Ole (U. of Trondheim) | Xie, Xina (Western Research Inst./U. of Wyoming) | Morrow, N.R. (Western Research Inst./U. of Wyoming)
Summary We investigated short-term rates of imbibition of water and long-term recovery by spontaneous imbibition for crude oil/brine/rock systems. Increasing the aging time and aging temperature decreased the early time rate of imbibition of water. Moderately water-wet plugs gave the highest recovery by long-term imbibition. We present photographic records of oil production at core surfaces, which are indicative of connectivity and capillary-pressure driving forces for imbibition. Introduction The transfer of fluids by capillary imbibition can play a very important role in the recovery of oil from most reservoirs; in fractured reservoirs, imbibition may be the dominant recovery mechanism. The imbibition process has been studied both theoretically and experimentally. Models have been developed to match laboratory results for the behavior of a single matrix block; other models are used in full field studies. The field models usually involve an expression describing the movement of hydrocarbon fluids from the matrix to the fractures. The most complex of these exchange terms includes capillary imbibition, viscous flow, and gravity. Problems arise in attempting to quantify the oil recovery because of uncertainty in input parameters, such as relative permeabilities, capillary pressures, and especially the end-point saturations. Extensive experimental work is needed to define these parameters and to understand the relative importance of the various drive mechanisms in the matrix-fracture exchange term. The experiments must be conducted with representative reservoir rocks and fluids, and the results must be scaled to give realistic matrix-fracture fluid exchange data for a given matrix-fracture geometry. A selection of published work on imbibition is presented in Table 1 of Ref. 27, together with a list of the main parameters that were investigated. As this table shows, most of the early experimental investigations of spontaneous imbibition were made with strongly water-wet systems and constant fluid and rock properties. Later investigations included changes in fluid properties, rock properties, and boundary conditions. Other experimental parameters, such as exposure of rock to oil, aging temperature, and the handling of the crude oil, affect wetting properties, and hence, imbibition. A recent detailed study of oil recovery from crude oil/brine/rock (COBR) systems included measurements of spontaneous imbibition rates. These rates are controlled by capillary pressures and thus by the wetting condition of the system. Therefore, measurements of spontaneous imbibition provide a sensitive means of detecting subtle changes in capillary forces and displacement behavior that result from changes in wettability.
- North America > United States (0.69)
- Europe (0.46)
- 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 > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Summary Berea sandstone is widely used as a model rock for study of fluid flow phenomena. Consistent core properties are often essential to interpretation of experiments. Core samples are often fired in order to ensure completely water-wet conditions by removal of adsorbed organic matter from pore surfaces, and to reduce problems caused by clay swelling and other effects. Reported firing temperatures range from 350 to 1000ยฐC and firing times from 1 to 48 hours. The choice of firing temperature appears to be somewhat arbitrary and only limited information is available on the effect of firing. A series of experiments have been performed using Berea cores fired at temperatures ranging from 110 to 1100ยฐC and times varying from 2 to 8 hours. Experimental results show that firing can cause complex changes, most of which are caused by changes in mineralogy due to heating. Important mineralogical changes include clay dehydration up to about 600deg.C, dolomite decomposition below 800deg.C, and calcite decomposition at about 900deg.C. Also important are to quartz conversion at about 573deg.C, phase transformation of clay minerals, and obvious melting at temperatures of about 1000deg.C and above. Observed changes in mineralogy and petrophysical properties show that:firing temperature has a much stronger influence on core samples than firing time; surface area has a peak value at 600ยฐC; permeability and porosity increase with firing temperature; the ratio of brine to gas permeabilities approaches a maximum close to unity at a firing temperature of about 900deg.C; firing temperatures of above 400ยฐC result in increased waterflooding displacement efficiency of refined oil; and at firing temperatures above 900deg.C, the core samples become friable and migration of fine particles affects liquid permeability. Because of the complex effects of firing, careful consideration should always be given to use of unfired cores. Introduction Berea sandstone was first identified in the 1950s as a model rock for production research on oil recovery. Supplied by Cleveland Quarries, Ohio, it has stood for over thirty years as the most commonly used rock in laboratory displacement tests. Cores cut from given batches of the quarried stone usually have consistent petrophysical properties. Batches cut from different parts of the petrophysical properties. Batches cut from different parts of the quarry provide cores of different permeabilities. In the present work, initial studies were performed from a batch having permeabilities of about 800 md to gas (designated Berea 800). permeabilities of about 800 md to gas (designated Berea 800). Subsequent work was performed on core samples of about 380 md permeability (designated Berea 380). Properties of cores cut from permeability (designated Berea 380). Properties of cores cut from a given block were usually extremely close. In many laboratories studies, cores are fired as a preliminary step. Usually, cores are fired for one or more of three main reasons:to ensure strongly water-wet mineral surfaces by burning off organic contaminants; to stabilize clay minerals and so reduce problems of clay swelling and fines migration; and to minimize problems arising from ion exchange. The general objectives of firing are to improve reproducibility and reduce the number of variables that may affect the results of displacement tests. A summary of research involving the use of fired core samples wad recently prepared by Ma. Firing temperatures, T, reported by various researchers ranged from 350ยฐ to 1000ยฐC and firing times, t, from 1 to 48 hours. Differences in temperatures and times can be expected to result in differences in petrophysical properties. However, firing conditions are usually reported without properties. However, firing conditions are usually reported without explanation of choice of firing temperature and time; furthermore in many studies the firing time is not stated. Casse and Ramey mentioned that 505ยฐC was generally high enough to oxidize any organic matter and to deactivate swelling clay. Sydansk and Shaw et al. both found 1000ยฐC to be an adequate temperature to stabilize clays. Nelson et al. and Potts et al. found that waterflood residual saturations of mineral oil were decreased by the firing treatment. Somerton and Selim performed a series of studies on thermal alteration of porous media for temperatures ranging from 25 to 1000ยฐC.
- North America > United States > Ohio (1.00)
- North America > United States > West Virginia (0.82)
- North America > United States > Pennsylvania (0.82)
- North America > United States > Kentucky (0.82)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (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 > Core analysis (1.00)
Wei, K.K.; New Mexico Inst. of Mining and Technology, Petroleum Recovery Research Center; Morrow, N.R.; SPE, New Mexico Inst. of Mining and Technology, Petroleum Recovery Research Center; Brower, K.R.; New Mexico Inst. of Mining and Technology, Petroleum Recovery Research Center Summary The combined effect of temperature, confining pressure, and test fluid on absolute permeabilities of low-permeability sandstones has been investigated. Absolute permeabilities to liquids were dependent on polarity but were always significantly less than Klinkenberg permeabilities polarity but were always significantly less than Klinkenberg permeabilities for gases. Differences are ascribed to swelling and dispersion of fine particles. Changes in state of dispersion caused by ultrasonication were particles. Changes in state of dispersion caused by ultrasonication were investigated by measurement of resulting changes in permeabilities. Nitrogen, brine, and distilled water were used as test fluids in a main series of tests for which temperatures ranged from 0 to 93 deg. C [32 to 199 deg. F] and confining pressures from 3.45 to 34.47 MPa [500 to 5,000 psi]. Absolute permeabilities of five formation samples of various origins psi]. Absolute permeabilities of five formation samples of various origins differed by up to three orders of magnitude, with the highest permeability being a few millidarcies. All specimens showed marked reduction in permeability with increase in confining pressure. For all cores, however, permeability with increase in confining pressure. For all cores, however, absolute permeabilities to gas were essentially independent of temperature at all levels of confining pressure. Comparable measurements of brine permeability were made for two core samples and, as with gas flow results, permeability were made for two core samples and, as with gas flow results, no significant temperature effect was found. Klinkenberg slip factors, B, were found to vary linearly with absolute temperature, but gave positive intercepts on the temperature axis of B vs. T plots. The intercepts were larger for gases of higher boiling point. This deviation is shown to be mainly a result of the nonideal effect of temperature on gas viscosities. Introduction The need to relate laboratory measurements to formation conditions has led to numerous studies of the effects of confining pressure and temperature on petrophysical properties. These properties include porosity, electrical properties. These properties include porosity, electrical resistivity, permeability, and relative permeability to various fluids. A summary of work on this subject was recently reported by Gobran et al. All investigations report a decrease in permeability with an increase in confining pressure. Although numerous experimental studies have been made, no comparable consensus has been reached on the qualitative effects of temperature on permeability and relative permeabilities. McKay and permeability and relative permeabilities. McKay and Brigham state that the majority of published results show a decrease in absolute permeability with an increase in temperature. While temperature effects have been reported, in general, explanations of their likely cause are not readily amenable to systematic testing. In some instances, reported dependence of permeability on temperature has later been ascribed to experimental artifact. Absence of significant temperature effects has now been reported for a variety of artificial and natural media and fluids. In general, however, the complexity of most sedimentary rocks is such that the possibility of temperature effects on permeability cannot be categorically excluded. Many studies show that low-permeability gas sands (now commonly referred to as tight gas sands) often exhibit unusually high reductions in permeability with increase in confining pressure. It is therefore highly desirable for permeability measurements on core samples to be made at stress conditions that are representative of those in the formation. In the present work, the possible need to duplicate reservoir temperature in making permeability measurements on pressure-sensitive rocks is permeability measurements on pressure-sensitive rocks is investigated. An important feature of gas-permeability measurements on tight sands is the contribution to gas flow provided by gas slippage. Klinkenberg determined absolute permeabilities to gases and isooctane for a variety of natural permeabilities to gases and isooctane for a variety of natural and artificial porous media ranging in permeability from 2 to 1,347 md. In many instances, liquid permeabilities measured with isooctane were in almost exact agreement with gas permeabilities. In no case was the liquid permeability less than 92 % of the gas permeability determined permeability less than 92 % of the gas permeability determined by extrapolation of results to infinite mean pressure. It is well known that rock/fluid interactions cause water permeabilities to be significantly lower than k infinity values for permeabilities to be significantly lower than k infinity values for gases. Jones and Owens report that permeabilities to 60,000-ppm NaCl solution were about 85% less than k values and that with distilled water, the reduction was about 95%. SPEFE P. 413
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)