FOR many years the permeability of reservoir sands has been measured by flowing air through a cleaned and dried core sample. This differs from the true reservoir permeability in one important respect: the rock particles in the reservoir are surrounded by interstitial water, not air, and their physical shape and condition of hydration are greatly dependent thereon. Permeability as defined must be measured with a single-phase fluid. Since no means exist for removing the oil and gas from a core sample by simply flowing water through it, the sample must be cleaned and then resaturated with water before testing. The present discussion attempts to show that after the cleaning process a considerably different permeability is determined with salt or fresh water than is obtained with air. The postulate is made that the salt-water permeability is probably closer to the true reservoir permeability than is the measurement with air. This is discussed in relation to both physically possible and economically feasible measure-men~. Data on more than 1200 core samples are given to show the nature of the effects observed, and a plea is made for others to consider water permeability measurements as a routine necessity, eventually replacing air permeability in regions where the differences are great. Q 27rk SPI = h(P. -P",) = p.log. r./r w [4] or in terms of practical units, and allowing for shrinkage:[ 1 p.FVF loglo r./r;. 5
Laboratory flood pot testing of California sands has progressed to aconsiderable extent in the past 18 months. Flood evaluations have been carriedout on over 200 large core samples. Many of these were heavy oil sands of highpermeability and completely unconsolidated in nature. The oil frequently formeda bank, though some of the oil was recovered in the subordinate phase of theflood, by viscous drag. Flood pot recoveries as high as 1400 bbl/ acre ft havebeen recorded. Reservoir analysis suggests a conformance factor of 0.4 toreduce laboratory recovery to probable field practice. Oils with viscosities upto 1800 cp have been successfully handled in flood pot evaluations. Theshallow, loose sands are not well adapted to the application of high pressuresto offset the high viscosities. Introduction Secondary recovery may be said to have started 60 years ago when accidentalfloods occurred in the Bradford sand in Pennsylvania; About 1921 artificiallyconducted water drives came into extensive use and since that time the greatBradford field has been almost completely subjected to water flooding. Duringthe last 30 years, most of the known medium and deeper production in Californiahas been discovered and is being exploited by primary recovery methodssupplemented in some instances by high pressure gas injection. The Californiaarea is just beginning to feel the need for secondary recovery in view of anunprecedented market demand and the rapidly rising cost of new pooldiscoveries. With the presently recognized desirability of secondary recovery inCalifornia, there must also be appreciated a number of serious differencesbetween the water flooding problems here as compared to the territory east ofthe Rockies. California sands are generally thicker, and are frequently softand argillaceous. The oils are often heavier and asphaltic. Much of the oil isbelow 15?API, occurs at shallow depth, is cool and free from appreciabledissolved gas, which results in relatively high reservoir oil viscosity.Secondary recovery is particularly beneficial where primary recovery has beenpoor and where no natural water drive exists. These conditions applyparticularly to the heavy, shallow, clean production from soft, oftenargillaceous California sands so abundantly found at depths less than 1500feet. Often, too, there is a totally insufficient supply of water ofsatisfactory quality to inject at a reasonable cost. Also, the crude oils arepriced far below the premium Bradford crude. T.P. 3640
Fall Meeting of the Southern California Petroleum Section of AIME, 17–18 October, Los Angeles, California Introduction Many phases of oil and gas reservoir evaluation, and operation of such properties for maximum economic return, depend on a thorough knowledge of the volumetric behavior of the oil and/or gas contained therein. One of the basic elements in measurements of this sort is the density of the gas phase. This parameter must be accurately known whether the complete Pressure-Volume-Temperature [PVT] study of the oil and gas system is made or whether empirical correlations are being used, as with the method of Marshall B. Standing. The density of gas may well be used as a monitor on many refinery processes and in an endless list of chemical engineering processes where gas of any composition is an integral part of the process. Some of the gas density-measuring devices on the market now are fairly satisfactory where a large amount of gas is available or monitoring of the density of a large stream of gas is required. Where time is no object or if extreme accuracy is not required, several available instruments prove satisfactory. But where rapid measurements of the density of small quantities of gas are required with a high degree of accuracy, coupled with a minimum of lost motion between samples, the Beckman Density Balance has proved to be invaluable. The first laboratory model of the Density Balance was installed in Jan., 1955. Except for minor adjustments and one improvement in the interest of corrosion resistance, it has operated for two years on hundreds of samples of gas, giving more precision than is necessary for most PVT work with smaller samples and more quickly than any other method known to the authors. The result are so outstanding that further laboratory development is entirely restricted to other phases of the PVT equipment and procedures. Principle of Operation Inside the measuring cell a horizontal quartz fiber supports a light dumbbell-mirror assembly. One ball of the dumbbell is punctured, making it independent of buoyancy effects. The other dumbbell ball rises or dips as the density of the gas fluctuates.
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