Consolidated Sandstone Research Articles

Effect of Temperature Level upon Capillary Pressure Curves

Abstract A number of recent studies of drainage relative permeability ratio by dynamic displacement have permeability ratio by dynamic displacement have indicated temperature sensitivity. Poston et al. found that the irreducible water saturation appeared to increase significantly with temperature-level increase and speculated that capillary pressure saturation data would also change to show this effect. Although there have been capillary pressure-saturation studies which show important pressure-saturation studies which show important differences between laboratory and reservoir conditions (presumably higher temperatures), the effects have usually been attributed to adsorption and desorption of polar components from the liquid phases. There appears to be no systematic studies phases. There appears to be no systematic studies of the effect of temperature level upon capillary pressure. pressure. Equipment was constructed to permit measuring capillary pressures for simple systems at temperatures ranging from room temperature to about 350 deg. F. Drainage and imbibition capillary pressure curves were measured for three consolidated pressure curves were measured for three consolidated sandstones and one limestone sample, at either three or four temperature levels form 70 deg to 325 deg F. Fluid used were a filtered white oil and distilled water. Results for the sandstone samples were similar. The practical irreducible water saturation increased significantly as temperature was raised from 70 deg F to the maximum temperature studies - about 325 deg F. Surprisingly, the hysteresis between drainage and imbibition cycles decreased as temperature increased and was nearly absent at 300 deg F. Results indicated that the sandstone samples became markedly more water-wet as temperature level increased. Results for the limestone sample were quite different. All capillary pressure-saturation curves for the various isotherms were found to lie within the envelope of the room-temperature drainage and imbibition curves. The main objective of this study was to determine whether the supposition of Poston et al. was correct. Results are in agreement with the previous dynamic displacement work. Introduction In 1967, Poston et al reported displacement experiments on unconsolidated sands at elevated temperatures and found that the irreducible water saturation increased with temperature increase. The oil viscosity appeared to have had no real effect on their results. Although less conclusive, practical residual oil saturations (to a producing practical residual oil saturations (to a producing water-oil ratio of 100) appeared to decrease with temperature increase. The results also indicated important increases in both oil and water relative permeabilities as temperature increased. This led permeabilities as temperature increased. This led Poston et al. to suggest that temperature affects. Poston et al. to suggest that temperature affects. the sand wettability. Sessile-drop contact angle measurements indicated that the water-oil-glass contact angle decreased with temperature increase. The results of Poston et al. regarding an increase in irreducible water saturation with temperature increase and the nondependence of this finding on the viscosity ratio deserve more attention. it is a well established concept in the literature that increasing water wetness of sands is reflected in an increase in the irreducible water saturation and an increase in oil recovery efficiency. The effect on a capillary pressure-saturation curve would be to cause a shift toward increasing irreducible wetting-phase saturation. if this is the case, then the studies of McNiel and Moss and Willman et al. should give partial credit for the added oil recovery efficiency involved in hot water flooding to the effect of temperature level upon wettability. In view of the potential importance of hot fluid injection for improving oil recovery and the lack of an adequate description of the flow process and thermodynamics involved, it was decided to study the speculation of Poston et al. that capillary pressure-saturation curves should be temperature pressure-saturation curves should be temperature dependent. This study concerns the effect of temperature level upon capillary pressure-saturation relationships for consolidated porous media. SPEJ p. 13

Displacement of oil by Solvent at High Water Saturation

Abstract Displacements of laboratory oils by propane in long, consolidated sandstone cores in the presence of high water saturations have shown that oil recoveries approaching 100 percent may be realized by continuous water-propane injection, even for oil saturations close to residual oil. However, it was often necessary to inject many pore volumes of solvent to attain this high a recovery. Initial oil saturations were established by injecting water and oil at a constant ratio into the porous medium containing residual oil to a waterflood until a steady state was obtained. Propane and water were then injected in the same fixed ratio to displace the oil. These and other experiments indicate that in the presence of a high water saturation only part of the presence of a high water saturation only part of the oil is flowable. Part resides in locations that are blocked by water, and the oil in these stagnant locations is not flowable. This nonflowable oil, it is believed, can be recovered by molecular diffusion into the flowing propane of a water-propane displacement. Values for the saturation of hydrocarbon that is contained in the stagnant locations and values for the ratio of the longitudinal hydrodynamic-dispersion coefficient to displacement velocity were determined at various water saturations in the test sandstones. The data suggest that rock wettability may influence the stagnant saturation and that stagnant oil saturations may not be as large in reservoir rocks as they are observed to be in laboratory sandstones. Mass transfer between the flowing solvent and hydrocarbon components in the stagnant saturation was expressed by a first-order rate expression. Rough values for the mass transfer coefficients for the propane-trimethylhexane hydrocarbon pair were estimated from experiments. Computations using these values for mass transfer coefficients indicate that experiments in laboratory-size cores may show much poorer displacement efficiency than that which might actually occur in the field. Introduction Injection of water with light hydrocarbon solvents is a technique that may be used to partially control solvent mobility. The higher water saturation forced by water injection reduces the permeability to solvent flow, and the mobility of the solvent region is reduced relative to that of the oil-bank region. However, it also might be expected that this higher water saturation influences the microscopic unit displacement of oil by solvent to some degree. For example, as discussed by Thomas et al., two possible effects of high water saturation on the displacement mechanism come to mind. First, a miscible displacement in the presence of water is operating on a different pore-size distribution than if no water were present. Pore-size distribution and the dp term (product of the microscopic inhomogeneity factor and "effective" particle diameter) may considerably influence the magnitudes of transverse and longitudinal dispersion coefficients. Secondly, in a multiphase system the wetting phase may trap single pores or even isolate large fingers or dendrites of the nonwetting phase. The nonwetting phase in these dead-end pores or dendrites would be phase in these dead-end pores or dendrites would be nonflowing and might either be completely isolated by the wetting phase or might communicate with the flowing nonwetting fluid by diffusion through nonwetting fluid-filled pores. Aspects of miscible displacement in the presence of water have been investigated by a number of researchers. Fitzgerald and Nielson observed that the simultaneous injection of gasoline and water into a Berea sandstone core in a 1:2 ratio recovered only 36 percent of the Bradford crude oil left in the core after waterflooding, and that only 55 to 75 percent recoveries were obtained for simultaneous water-solvent injection into the core when it contained crude oil at connate water saturation. Moreover, these authors reported recoveries of only 60 to 80 percent when solvent alone was injected into the core to displace residual oil to a waterflood. Raimondi et al. injected ethyl benzene (oil) and water simultaneously into a Berea sandstone core to establish flowing oil and water saturations and then injected heptane (solvent) and water simultaneously into the core to miscibly displace the ethyl benzene.

THERMAL AND ELECTRICAL CONDUCTIVITIES OF SANDSTONE ROCKS AND OCEAN SEDIMENTS

Relationships between electrical and thermal conductivities of consolidated sandstone rocks and sediments were investigated. Equations given by Archie (1942) and Woodside and Messmer (1961) were combined to give an equation which relates the two conductivities for the rocks. Equations relating conductivity and porosity, given by Maxwell (1881), Bruggeman (1935), and Woodside and Messmer (1961) were combined to give two equations which relate thermal and electrical conductivities for sediments. Data from 65 rock samples and 105 sediment samples (including data for 37 rock samples published by Zierfuss and Van der Vliet, 1956) were use establishing the reliability and parameter values of the equations. The derived equations can be used to determine thermal conductivities from electrical conductivities providing thermal conductivities of the solid constituents can be approximated. For samples of sandstone rock, deviations of the data from values predicted by the equations are shown to be related to the variations in composition of the samples. Within the accuracy of the data, the thermal conductivities of sediment samples seem to be controlled more by the water content than by the mineral composition.

Correlations of Physical Properties of Porous Media

Abstract Regression analysis was used to correlate the physical properties of 478 sandstone and 90 carbonate core samples. Porosity, permeability, electrical formation resistivity factor, capillary pressure and the sonic velocity of the shear and compressional waves were measured. Prediction equations for porosity, permeability and electrical formation resistivity factor were found which should be useful in understanding the relationships between the physical properties of porous media in formation evaluation. Introduction The physical properties of porous media are important to the petroleum engineer and geologist. To evaluate fully the potential and behavior of a subsurface formation such as a petroleum reservoir, certain physical properties of the porous medium must be known. The problem of accurately determining physical properties of subsurface formations has not been solved because many determinations must be made by indirect measurements and because of the difficulties caused by complex pore structure and presence of clays in most naturally occurring porous media. Due to the difficulty in measuring some of the physical properties of porous media, it would be advantageous to be able to predict a certain physical property of a rock from other physical properties of the rock which could be measured more easily and more accurately. Since most potential reservoir rocks are heterogeneous, relationships between the physical properties are very complex and thus far no satisfactory correlations based on theory or laboratory models have been developed. It appears that empirical relationships obtained by measuring the physical properties of a large number of samples of naturally occurring porous media and applying regression analysis to develop for one physical property in terms of other rock properties is the best approach. REVIEW LITERATURE The three physical properties used as dependent variables for correlating purposes were porosity, permeability and formation factor. Since formation factor is more difficult to determine, a brief review of the literature is provided on this property. The first work on determining formation factors was published by Archie in 1942. He defined this property of a porous medium as Ro ...............................(1) F =RW where Ro is the resistivity of the porous medium when completely saturated with a brine of resistivity Rw. Archie found the best correlation between formation factor and porosity was the following equation, F = - m..................................... (2) where is the porosity fraction and m is the constant characteristic of the rock. The value of m was 1.3 for unconsolidated sand packs, and ranged from 1.8 to 2.0 for consolidated sandstones. In 1950 Patnode and Wyllie and De Witte observed that the formation factor as determined by Eq. 1 was valid only when the porous medium contained no conductive solids such as clay or shale. When conductive solids are -present the formation factor is also dependent on the resistivity of the saturating fluid. Therefore, in samples containing conductive solids the formation factor decreased as resistivity of the saturating fluid increased. Because of this, the measured formation factor was called the apparent formation factor and was designated Fa. Patnode and Wyllie proposed the following equation. SPEJ P. 266ˆ

Effect of Saturation on Mobility of Low Liquid-Vapor Ratio Fluids

Abstract Laboratory research has been conducted to evaluate the characteristic effects of condensate saturation on the mobility of gas in typical reservoir rocks. A pump with two pistons provided phases in equilibrium at controlled flow rates and constant liquid-vapor volume ratios. Core samples were tested in a holder that permitted sealing steady-state phases in the pore spaces under flow test pressures for weighing with sufficient precision to give an accurate measure of the attained saturations. Parameters of the study were pressure, apparent velocity, flowing liquid-vapor volume ratio, fluid composition, core material and length-to-diameter ratio. Tests were conducted at 515 and 1,515 psia to determine the effect of pressure on the mobility-saturation relationship. Influence of the apparent velocities 0.30, 0.15 and 0.07 cm/ sec and of five liquid-vapor volume ratios from 0.0001 to 0.01 was determined at 515 psia. The principal fluid system was nitrogen and and separator liquid from a Gulf Coast condensate, but the effect of a condensate of different viscosity was also determined. The significance of a possible concentration of liquid near the outlet end of the test cores was investigated. Core materials included a consolidated sandstone and a low-permeability limes tone. Relative mobility and liquid-vapor volume ratio relationships are concluded to be dependent on pressure, saturation and, to a lesser extent, on velocity. For each porous medium and fluid there is a minimum saturation essential to two-phase flow, and high velocities of flow have only limited effect on saturations in this range. INTRODUCTION It is now recognized that knowledge of the availability of a reservoir gas - the period that gas may be recovered from a reservoir at a given rate - is as important as the estimate of gas in place. When reservoir conditions are such that pressure decline owing to production will result in retrograde condensation, liquid saturation can increase in the structure around the production well in a way that may restrict flow capacity, and hence future availability.1 Based on a numerical solution of transient radial flow of single-phase gas-condensate fluids,2 a program for computing the accumulation of condensate in a reservoir and the effect of this condensate on deliverability has been developed.3 During this development a need evolved for data that described the influence of pressure, velocity of flow and condensed liquid on mobility as recovery progressed. This paper presents the results of experimental investigation to obtain insight into the mobility relationship at reservoir pressures of gas-condensate fluids. A core holder for flow tests at reservoir pressure was developed to weigh the core and its fluid contents under pressure to determine saturation. A specially constructed pump was used to drive a two-phase fluid through the core until a steady state prevailed. The core was used as a differential device, and properties measured were intensive rather than extensive. APPARATUS Fig. 1 shows a schematic representation of the major pieces of equipment used in the mobility determination. The weighable core holder is connected to a two-piston, constant-displacement pump. Attainment of steady-state flow is indicated by stability of the flow differential read from the high-pressure manometer. WEIGHABLE CORE HOLDER An important part of the data needed was the mobility-saturation relationship. This required that mobilities and saturations be measured at pressures, flow velocities and liquid-vapor volume ratios characteristic of condensate reservoirs. WEIGHABLE CORE HOLDER An important part of the data needed was the mobility-saturation relationship. This required that mobilities and saturations be measured at pressures, flow velocities and liquid-vapor volume ratios characteristic of condensate reservoirs.

Effect of Interfacial Tension on Displacement Efficiency

Abstract Immiscible displacement tests were performed in a consolidated sandstone core over the interfacial tension range from less than 0.01 to 5 dynes/cm to better define how interfacial tension (IFT) reduction can lead to increased oil recovery. Data obtained were displacement efficiency at breakthrough vs IFT for both drainage and imbibition conditions. These tests simulate water flooding under oil-wet and water-wet conditions, respectively. Results of the study have shown that displacement efficiency under both oil-wet and water-wet conditions can be markedly improved by a sufficient reduction in IFT. In the particular porous media used and for the low pressure gradients employed, the IFT must be reduced to a value less than about 0.07 dynes/cm to achieve increased recovery at the time of breakthrough of the injected phase. Below 0.07 dynes/cm, further small reductions in IFT result in large increases in displacement efficiency. Observed increases in recovery were obtained at pressure gradients which are well below those which can exist in the interwell area of a reservoir under water flood. The effect of pressure gradient on recovery is discussed. INTRODUCTION A residual oil saturation remains in rock which has been water flooded because, under usual reservoir conditions, the driving force which can be generated is inadequate to expel oil trapped by capillary forces. Since these capillary forces can be reduced by reducing the IFT a frequently studied method 1-5 of increasing oil recovery has been the use of surfactants to reduce the water-oil interfacial tension. Mungan1 observed improved recovery in both water-wet and oil-wet systems at 1.1 dyne/cm IFT, finding that the amount of improvement was greater in oil-wet systems. Moore and Blum,2 working with visual flow cell micro-models, concluded that recovery cannot be improved in water-wet systems by injecting surfactant solutions. They calculated that, for a pressure gradient of 1 psi/ft in their model, the IFT must be reduced to 0.03 dynes/cm to release oil trapped under water-wet conditions. Berkeley et al.3 indicated that, at representative field flooding rates, the IFT must be reduced to 0.001 dyne/cm to improve recovery. Thus, there is a wide variation of opinion about the IFT levels needed to improve recovery under field conditions. These previous investigators all have used as their experimental method the addition of surfactants to the injected water. The use of surfactant solutions to reduce IFT creates two experimental problems:the loss of surfactant through adsorption on reservoir rock can obscure the true IFT value which exists at the displacement front, andat very low values of IFT emulsification of oil and water commonly occurs. It is difficult, therefore, to determine whether the increased recovery is caused by IFT reduction as such, or is instead caused by emulsification. Also the properties of the available surfactants limit the IFT range which can be studied. In the present study the purpose is to better define how interfacial tension reduction can lead to increased oil recovery. A matter of great interest is the amount of recovery improvement potentially achievable in this way. The study was made using very low pressure gradients which was well within the range achievable by water flooding in the interwell region of petroleum reservoirs. A unique experimental approach was chosen to avoid adsorption and emulsification problems, and to allow convenient control of IFT. The fluid phases used were the equilibrium vapor and liquid phases of the methane-n-pentane system. The interfacial tension level was varied by changing the equilibrium pressure of the methane-pentane system over the range from 1,200 psia to near the critical pressure (2,420 psia). All tests were performed at a controlled temperature of 100F. The IFT-vs-pressure relationship for the methane-pentane system was based on the data of Stegemeier and Hough,6 and on new data obtained in this study. With this experimental approach it has been possible to study displacement at lower values of IFT than have been previously investigated.

Variations in Permeability and Porosity of Synthetic Oil Reservoir Rock-Methods of Control

Abstract Synthetic rock with predictable porosity and permeability bas been prepared from mixtures of sand, cement and water. Three series of mixes were investigated primarily for the relation between porosity and permeability for certain grain sizes and proportions. Synthetic rock prepared of 65 per cent large grains, 27 per cent small grains and 8 per cent Portland cement, gave measurable results ranging in porosity from 22.5 to 40 per cent and in permeability from 0.1 darcies to 6 darcies. This variation in porosity and permeability was caused by varying the amount of blending water. Drainage- cycle relative permeability characteristics of the synthetic rock were similar to those of natural reservoir rock. Introduction The fundamental behavior characteristics of fluids flowing through porous media have been described in the literature. Practical application of these flow characteristics to field conditions is too complicated except where assumptions are overly simplified. The use of dimensionally scaled models to simulate oil reservoirs has been described in the literature. These and other papers have presented the theoretical and experimental justification for model design. Others have presented elements of model construction and their operation. In most investigations the porous media have consisted of either unconsolidated sand, glass beads, broken glass or plastic-impregnated granular substances-materials in which the flow behavior is not identical to that in natural reservoir rock. The relative permeability curves for unconsolidated sands differ from those for consolidated sandstone. The effect of saturation history on relative permeability measurements A discussed by Geffen, et al. Wygal has shown quite conclusively that a process of artificial cementation can be used to render unconsolidated packs into synthetic sandstones having properties similar to those of natural rock. Many theoretical and experimental studies have been made in attempts to determine the structure and properties of unconsolidated sand, the most notable being by Naar and Wygal. Others have theorized and experimented with the fundamental characteristics of reservoir rocks. This study was conducted to determine if some general relationship could be established between the size of sand grains and the porosity and permeability in consolidated binary packs. This paper presents the results obtained by changing some of the factors which affect the porosity and permeability of synthetically prepared sandstone. In addition, drainage relative permeability curves are presented. EXPERIMENTAL PROCEDURE Mixtures of Portland cement with water and aggregate generally are designed to have certain characteristics, but essentially all are planned to be impervious to water or other liquids. Synthetic sandstone simulating oil reservoir rock, however, must be designed to have a given permeability (sometimes several darcies), a porosity which is primarily the effective porosity but quantitatively similar to natural rock, and other characteristics comparable to reservoir rock, such as wettability, pore geometry, tortuosity, etc. Unconsolidated ternary mixtures of spheres gave both a theoretically computed and an experimentally observed minimum porosity of about 25 per cent. By using a particle-distribution system, one-size particle packs had reproducible porosities in the reproducible range of 35 to 37 per cent. For model reservoir studies of the prototype system, a synthetic rock having a porosity of 25 per cent or less and a permeability of 2 darcies was required. The rock bad to be uniform and competent enough to handle. Synthetic sandstone cores mere prepared utilizing the technique developed by Wygal. Some tight variations in the procedure were incorporated. The sand was sieved through U.S. Standard sieves. SPEJ P. 329ˆ

A Study of Formation Plugging With Bacteria

Abstract This study investigated the nature of formation plugging with bacteria and attempted to relate its characteristics to physical rock properties. Fifteen core samples of four specific formation types were defined and plugged using a commonly occurring, uniform sized dead bacteria, Bacillus subtilis. Two of the formation types were fairly uniform-grained sandstones and two were heterogeneous carbonates. The injection rate and concentration of solids in the brine were held constant during the test runs. The pore geometry factor G was a significant petro-physical rock characteristic for correlation with depth of plugging, but lacked importance as a parameter for rate of plugging. Although the G factor may not completely describe porous rock geometry for plugging predictions, for reservoirs with multi-pore systems, there is evidence that the pore geometry factor might form a basis for establishing injection water specification in more homogeneous reservoirs with only primary porosity development. Introduction GENERAL PURPOSE Injecting water into oil-bearing formations to increase recovery is common practice in the petroleum industry. One of the most serious operational problems involved with water injection wells is the tendency of the porous rock immediately adjacent to the injection wellbore to plug partially. This results in increased injection pressures and/or a decrease in the rate of injection. This plugging in injection wells can result from a number of causes, including bacteria contained in the injected water. The purpose of this work was to investigate the nature of injection plugging with bacteria and to attempt to relate its characteristics to physical rock properties. Many variables exist in research of this type, so, to reduce them, injection rate and concentration of bacteria in brine were held constant. The bacteria used for plugging was a uniform-sized, dead bacteria, Bacillus subtilis, a micro-organism commonly found in water, air and soils. Four specific porous rock types were plugged-two consolidated sandstones and two heterogeneous carbonates. The experimental work involved two distinct phases. The first concerned determining the physical rock properties and the second was the experimental work of actually plugging the selected core samples. PORE GEOMETRY FACTOR Capillary pressure is necessary to displace a wetting fluid from a capillary opening with a nonwetting fluid. The factors which govern capillary pressure are the surface or interfacial tension of the fluids involved, the system wettability and the equivalent pore radius. Thus: (1) Thomeer used the idea that the location and shape of the capillary pressure curve reflect characteristics of the pore structure of any porous media sample. He presented the mathematical description of capillary pressure curves and of indicated differences in pore geometry of samples. (2) where G = pore geometry factorpc = capillary pressurepd = displacement pressure(Vb)pc = fractional bulk volume occupied by thedisplacing fluid at any capillary pressure(Vb)px = fractional bulk volume occupied by thedisplacing fluid at infinite pressure ortotal inter-connected pore volumes. The shape of the curve is defined by the pore geometry factor G. The curve shape is related directly to the sorting and interconnection of the pores of the sample. The location of an infinite number of curves can be defined by the same asymptotes. However, these curves differ in shape, each curve being described by a specific value of G. Thus, the description of a curve is unique when, in addition to the position of its asymptotes, its shape is defined. These curves can be used graphically to determine the characteristic parameters of any arbitrarily located curve. Those parameters that can be approximated from any capillary pressure curve are: total interconnected pore volume, represented by (Vb)px; extrapolated displacement pressure, the abscissa axis; and pore geometry factor, by the curve shape. PROPERTIES OF BRINE AND BACTERIA The fluid used throughout this study was an aqueous solution of sodium chloride, 25,000 ppm by weight. The addition of salt to fresh water was intended to eliminate clay swelling in the sandstone cores and to retard leaching in the limestone cores. JPT P. 201ˆ

Effects of Pressure and Fluid Saturation on the Attenuation of Elastic Waves in Sands

Abstract The velocity and attenuation of elastic waves in sandstones were measured as a function of both pressure and fluid saturation. A large change occurs in these quantities if water is added and the rock is not compressed, but the change is small if the rock is subjected to a large overburden pressure. Measurements were made by vibrating cylindrical samples in both the extensional and torsional modes at frequencies up to 30,000 cycles/sec. Formulas were derived which enable the attenuation of dilatational waves in dry rocks to be deduced from the data. Similar experimental methods were used to investigate the properties of unconsolidated sands. Velocities were found to vary with the 1/4 power of the overburden pressure and attenuations to decrease with the 1/6 power. The effects of grain size, amplitude and fluid saturation were studied. Formulas by which the effects produced by a jacket around the sample may be calculated were derived. The practical application of these results to formation evaluation is discussed. Introduction The attenuation of elastic waves in the earth has been of interest to the seismologist and geophysicist for many years, but only recently to the petroleum engineer. Engineering interest has been brought about by the success of velocity logging devices, for it is possible by modification of these instruments to measure the attenuation of sound waves in addition to their velocity and, hence, deduce the mobility of formation fluids as well as the porosities of the rocks which contain them. The main problem is to decide whether field measurements can be made with sufficient accuracy to be of practical use. This problem can only be solved after we know the magnitude of the attenuations which are typical of the earth at various depths. The logarithmic decrement of a fluid-saturated rock is the sum of a "sloshing" decrement and a "jostling" decrement, the former caused by the mobility of the fluid contained within the rock and the latter by the granular framework of the rock. Sloshing decrements can be calculated using Biot's theory, but the jostling losses are less well understood. The present paper reports an experimental investigation of jostling losses in consolidated and unconsolidated sands, particularly with respect to the effect of overburden pressure and fluid saturation. Born showed that the decrement of a sandstone may increase dramatically when only a few per cent by weight of distilled water is added, and that the additional loss is proportional to the frequency of vibration. His measurements were made with no compressive stress on the framework of the rock. M. Gondouin investigated similar phenomena for fluid-saturated plasters but also did not compress the samples. In the present paper it is shown that compression of the framework reduces this effect, so that at depth the jostling decrement of a sandstone may be expected to be almost independent of fluid saturation and frequency. Decrements for many sedimentary rocks have been given by Volarovich, but all for the state of zero overburden pressure. Anomalously low velocities have been logged in shallow unconsolidated gas sands. Results of the present investigation confirm that these velocities are not caused by correspondingly high attenuations, because the jostling decrement in a packing of sand grains is small and much less than in a consolidated sandstone at the same depth. Velocities in sands have been measured by Tsareva and by Hardin as a function of pressure, but the corresponding decrements do not appear to have been measured previously. The widely used "resonant bar method" of measuring velocities and decrements was employed. Comments on variations of this technique have recently been published by McSkimmin. The main novelty of the present technique was the application of pressure to the samples. It was found possible to do this by placing the apparatus inside a pressure vessel, provided the conditions leading to large additional losses were avoided. These conditions are discussed below. EXPERIMENTAL TECHNIQUE Cylindrical samples were caused to vibrate in both the extensional and torsional mode of vibration and the amplitude of vibration was measured as a function of frequency in the neighborhood of a resonant frequency. The resonant frequency, fr, is related to the corresponding elastic modulus by the formulas where E and N are Young's modulus and the modulus of rigidity, p is the density of the sample, and the wavelength of the vibration. JPT P. 189ˆ

Effect of Overburden Pressure on Some Properties Of Sandstones

Abstract Experimental data demonstrate that physical properties of porous rocks change under pressure. In this paper an assumption is made and proved that under pressure the changes of physical properties such as porosity, density, permeability, resistivity and velocity of elastic waves are controlled to a large extent by the pore compressibility of rocks. It is also shown that the pore compressibility of rocks can be determined, within the range of pressures from 0 to 20,000 psi, by knowing the maximum pore compressibility and the magnitude of the pressure. Mathematical equations were developed which permit one to define changes in physical properties of porous rocks under pressure. These equations were verified by experimental data obtained from the study of sandstones. Introduction In studying the behavior of porous rocks under pressure in the field of petroleum technology, the most interesting aspect is the observation of those properties which characterize the rocks as possible reservoirs for example, porosity, permeability, resistivity, density and be velocity of elastic waves. The literature dealing with this problem mainly contains data concerning the study of only one or at most two of these parameters, but not of the group as a whole. An attempt is made in this paper to find general equations involving each of these parameters, which will permit the study of the behavior of rocks under pressure. All experimental data used here were obtained from the investigation of consolidated sandstones. EXPERIMENTAL In addition to the use of published experimental data, an experiment was carried out which studied the main physical properties of sandstones under pressure. Two homogeneous quartz sandstones were chosen for this purpose:the Torpedo sandstone bona Kansas, andthe Medina sandstone from Ohio. The porosity of the Torpedo sandstone was 20.2 per cent, and that of the Medina 8.7 per cent. Permeabilities were 45 md and less than 1 md, respectively. Each sandstone contained about 5 per cent clay minerals, consisting mostly of kaolinite and chlorite, which were distributed quite evenly throughout the samples. One cylindrical sample 2 in. in diameter and 5 in. in length was cut from each sandstone and then saturated in a vacuum with a 3N solution of NaCl. This high concentration was used in order to obtain true formation factors and to decrease the swelling of the clay minerals. The methods of mounting the samples and measuring the changes in porosity and resistivity were practically the same as those described by Fatt and Mann. Changes of resistivity under pressure were studied for sandstones with 100 per cent water saturation, and for sandstones with the irreducible water saturation. The irreducible saturation was obtained by enclosing the saturated rock samples in relatively fine silicate powder so as to remove the water by capillary action. This procedure is described by Orkin and Kuchinski. Changes of permeability with pressure were determined at room temperature using nitrogen as the flowing medium. In studying the effects of pressure, one series of measurements was made using an internal pore pressure Pi equal to the atmospheric pressure, while the overburden pressure P. ranged from 0 to 20,000 psi. A second series of measurements was used over the same range of overburden pressure, but with an internal pore pressure of 1,800 psi When the results were compared on the basis of net overburden pressure (P, - 0.85 Pi ), there was practically no difference for these two sandstones. The origin of the factor 0.85 in the expression for net overburden pressure is given by Brandt, Fatt and Geertsma. SPEJ P. 360^

The Effect of Fluid Properties and Stage of Depletion On Waterflood Oil Recovery

Abstract An experimental study has been made to determine the optimum flooding pressures for four different oils. The oil formation volume factors ranged fro in 1.08 to 2.13, and solution gas-oil ratios ranged from about 200 cu ft/bbl to 2,250 cu ft/bbl. Viscosities ranged from 0.38 to 0.95 cp at the respective bubble points of the fluids and from 0.7 to 20 cp at atmospheric pressure. Water floods were conducted at various pressure levels from run to run. The recovery as a junction of flooding pressure was found to be different for each fluid, with optimum gas saturations ranging fro in 7 up to 35 per cent. The data indicate that substantially higher recoveries may be obtained if water floods are conducted at an optimum pressure and that this optimum pressure is a function of fluid properties. The same core was used for all tests, and the reproduction of saturations for various runs indicates that wettability in the predominantly water-wet core did not change. Introduction A paper was presented by Bass and Crawford which described an experimental study of the effects of flooding pressure and rate on oil recovery by water flooding. This work was conducted using high-pressure models operated in a manner similar to that of an actual reservoir, with gas saturations being obtained by a solution-gas-drive mechanism. They found that the greatest oil recovery was obtained for the system studied by flooding in the presence of a 5 to 7 per cent gas saturation. Another experimental study simulating field conditions was presented by Richardson and Perkins. They used an unconsolidated sand pack containing kerosene- natural gas fluid and interstitial water. They flooded at various pressures and flooding rates. For their system it was found that the recovery was independent of the pressure level at which the water flood was performed. Kyte, et al, found that oil recovery by water flooding was increased as the free gas saturation at waterflood initiation was increased. However, after the initial gas saturation was increased above 15 per cent, the increase in oil recovery tended to level off. All of their runs were made at the same pressure using a light oil saturated with helium. The desired gas saturation was obtained by injecting helium into the core. Dyes made calculations which showed that an optimum gas saturation of 12 to 14 per cent may result in an increase in oil recovery of 7 to 12 per cent over that obtained by flooding at the bubble-point pressure. Others have also found that the presence of a free gas saturation may increase the waterflood oil recovery. In each case shrinkage was small and changes in fluid properties with respect to pressure were small. A careful review of the literature reveals that at the present time there is a wide difference of opinion on the factors affecting waterflood recoveries. This diversity of opinion is probably due to the fact that very little research has been done which has taken into account the many variables existing in an actual field being water flooded. Since the literature contains little information on high-pressure waterflooding studies using various types of reservoir fluids, it was believed appropriate that such a study should be made. EQUIPMENT AND PROCEDURE All tests were made using the same consolidated sandstone core. Torpedo sandstone was used to turn a cylindrical core 13.5-in. long and with a 2.92-in. average diameter. The core had a porosity of 28 per cent and a permeability to brine of 146 md. This brine was made up by adding 20,000-ppm sodium chloride and 30,000-ppm sodium nitrite to distilled water. This was used as connate water and flooding water. No fresh water was ever brought in contact with the core, as tests showed the sandstone contained argillaceous material which swelled in the presence of fresh water and plugged the stone. The core was sealed in a section of 6-in. N–80 tubing with Woods metal filling the annulus. The core was mounted horizontally; an injection well was placed in the center of one end and a production well in the center of the other. Pressure control was maintained by placing a back-pressure regulator (upstream control) on the producing well. The "live" oil was stored in a separate bottle and water was injected into this bottle to displace the oil for saturating the core using a two- cylinder standard-proportioning pump. This same pump was used for water flooding the core at a constant rate. JPT P. 1165^

COMPARISON OF CORE ANALYSIS AND DRAWDOWN-TEST RESULTS FROM A WATER-BEARING UPPER PENNSYLVANIAN SANDSTONE OF CENTRAL OKLAHOMA / Comparaison de l'analyse d'échantillons et des résultats de rabattements pour une couche perméable de grès du Pensylvanien Supérieur dans l'Oklahoma Central

Abstract Drawdown-test data from a brine-saturated consolidated sandstone reservoir in central Oklahoma show that permeability can be determined accurately from laboratory measurement of small core samples. Such confirmation is significant because permeability values determined by core analyses are frequently considered not representative, at least quantitatively, of reservoir conditions. Yet such analyses are often the only way to obtain the permeability value necessary to predict the performance of a reservoir. The field value for permeability was computed by applying the Theis typecurve solution of the non-equilibrium formula to drawdown data from 64 wells in an 8-acre area surrounding a single discharging well. The laboratory value was based on complete cores from 39 of these wells. For objective analysis, the gross reservoir thickness was defined as that entire interval in which flow was confiined, regardless of the permeability of the included rock strata. This thickness was measured directly from the cores. Each plug was saturated with reservoir water and permeability was measured with a constant-head discharging apparatus. Both laboratory and drawdown-test methods show the reservoir to have a permeability of about 0.4 darcy and a mean transmissibility (permeability x thickness) of about 3.4 darcy-ft.

Three-Phase Imbibition Relative Permeability

Abstract An equation for three-phase (water, oil, gas) imbibition oil permeability is developed, assuming the water to be the dominant wetting fluid. Oil isoperms are obtained for consolidated sandstones characterized by. The evolution of an oil-gas system imbibing water from is shown to proceed along a line of constant oil saturation with increasing oil permeability and decreasing gas saturations. When the gas saturation cannot be reduced further, the system evolves along a line of constant with decreasing oil saturation and permeability. The initial gas saturation is shown to reduce markedly the effect of complete wetting by either oil or water on flow performance. Introduction Imbibition oil isoperms are required for performance prediction when a well is producing water, oil and gas. This situation occurs in multiphase displacements such as underground combustion, steam injection and the water flooding of highly depleted reservoirs. In a recent paper, a model was presented for the prediction of two-phase imbibition characteristics. This paper extends the imbibition model to the case of three phases by assuming that the water is the dominant wetting fluid. The following results were obtained from the model:an analytical expression of oil isoperms;oil isoperms as functions of reduced water, oil and gas saturations, valid for all sandstones having a capillary pressure curve which can be approximated by; andevaluation of the three-phase flow performance as dictated by complete wetting by either oil or water. The agreement between predicted and observed oil recovery in the presence of a gas phase, reported in Ref. 1, is a partial support for the present development. However, experimental data are not available at this time to check fully the model predictions. Perhaps this paper will stimulate the collection of such data. THEORETICAL The imbibition model of a porous medium has been described previously, and the reader is referred to the paper of Naar and Henderson for details. In brief, the model is formed by the random interconnection of straight capillaries, with a provision for the blocking of the non-wetting phase by the invading wetting fluid.

Mechanism of Alcohol Displacement of Oil from Porous Media

Abstract Alcohol floods of consolidated sandstone cores have shown the process to be strongly dependent on the phase behavior of the particular alcohol-oil-water system used. This means that in many cases the mechanism does not conform to the idea of a piston-like displacement. Instead, it is found that by changing the alcohol it is possible to change the relative velocities of the oil and water and, in fact, the entire mechanism of the process. The effects of rate, viscosity, initial saturation, distance travelled and hysteresis of relative permeability on the alcohol flooding mechanism are discussed. Introduction Reasons for interest in the use of alcohol to miscibly displace oil and water from a porous medium appear in the existing literature. The mechanism of the displacement has been considered and the apparent implications formulated into a theory which presumably would enable one to predict the essential features of the process. Unfortunately, most of the reported experiments have been performed with unconsolidated or artificially consolidated sands. With these systems some of the noteworthy facets of the process are obscured and resulting data appear uncertain. It is the purpose of this paper to show how the use of consolidated sandstones has led to revision of the mechanism and, hence, the theory of alcohol flooding. The practical result is increased pessimism toward the possibilities of commercial application of the simplest form of the alcohol-slug process. However elucidation of the mechanism has made it possible to define the essential characteristics of a system of slugs which will behave in a nearly piston-like fashion and, thus, yield the best possible result. Equilibrium Phase Behavior Fig. 1 is a diagram of the ternary system isopropyl alcohol (IPA)-Soltrol-calcium chloride brine. Brine was used to prevent plugging of the core and calcium chloride was used because sodium chloride brine exhibits a solid phase with Soltrol and IPA. If alcohol is added in increments to the immiscible mixture of water and oil represented by Point A, the path followed by the successively equilibrated samples will be on the Line ABC and pass from the immiscible region to the miscible region by crossing the binodal curve at B. Consider the intersection D of this path with the tie Line EF. The quantity of oleic phase is proportional to the Segment ED and the quantity of the aqueous phase is proportional to DF. Compositions of the two phases are specified by Points E and F. It is clear that in the case shown the oleic phase is diminishing and entirely disappears when miscibility is achieved.

Pin-Point Sandfracturing - A Method of Simultaneous Injection into Selected Sands

Abstract The conventional sandfracturing techniques first adopted by the Lagunillas Land Dist. of Cia. Shell de Venezuela in its Eocene wells, which had been perforated with four holes/ft over the full NOS interval, resulted in production increases which averaged some 700 per cent. However, recent developments in completion technique not only have reduced completion costs, but also have resulted in a further appreciable increase in production. Production rates of the new completions over the first year after sand fracturing are some 60 to 90 per cent higher than those of the "conventional" completions. It is believed that, by having a limited number of perforations and always providing an injection capacity which theoretically is greater than the total capacity of the perforations, there is a greater likelihood of fracturing all sands simultaneously. It is estimated that the technique reduces completion costs by $3,700. Introduction Productive prospects have been known to exist in the Eocene formations on the eastern shore of Lake Maracaibo for some time, but it was not until the successful introduction of sandfracturing as a stimulation technique that these could be economically exploited. Cia. Shell de Venezuela's Eocene land activity has, in the main, been concentrated in the Lagunillas, Tia Juana and (to a lesser extent) Cabimas fields; (these three fields comprise the company's Lagunillas Land Dist. By Feb., 1959, a total of 155 Eocene wells had been completed as economic producers after receiving a sandfracturing stimulation treatment. The productive shallow Eocene (B.1 sand), encountered between 1,000 and 3,000 ft, has gross intervals from 50 to 1,000 ft and is composed of interbedded shales and fine- to medium-grained consolidated sandstones. The sandstones make up, on the average, some 50 per cent of the section, but permeability (as shown by the Microlog) is restricted to some 60 per cent of the total sandstone development. The shallow Eocene is productive in the Lagunillas, Main Tia Juana and Cabimas fields.

Pore Structure in Sandstones by Compressible Sphere-Pack Models

Porosity and flow measurements made on packs of rubber spheres under compression indicate that ideal sphere packs do not model the flow properties of consolidated sandstones. Packs of rubber cubes have plate-like pore spaces. Under compression brine-saturated packs of rubber cubes display the same rapid increase in electrical conductivity observed when brine-saturated sandstones are compressed. This observation leads to the hypothesis that pore spaces in consolidated sandstones are plate-like, that is, they have two large and one small dimension. Compression of consolidated sandstone causes collapse of these plate-like pores.

Formation Factors of Unconsolidated Porous Media: Influence of Particle Shape and Effect of Cementation

Abstract The literature reveals that scant attention has been paid to the systematic experimental determination of the formation factors of unconsolidated porous media. No experiments appear to have been made on the effect of increasing cementation on the formation factor of an initially unconsolidated porous medium. Measurements have accordingly been made of formation factors as a function of porosity for aggregates of spheres in the porosity range 12–56 per cent and of cubes, cylinders, discs and triangular prisms in the porosity range 30–45 per cent. The results are examined in the light of the theoretical equations of Clerk Maxwell, Fricke and Slawinski. Aggregates of unconsolidated spheres and beach sands have been artificially cemented with silica and the formation factor-porosity relationships determined. A theory is outlined which seeks to explain the results obtained and which postulates that formation factor and porosity data for consolidated sandstones may be used to determine the original porosity of the unconsolidated sands from which the consolidated sandstones were derived. Introduction All schemes of electric log interpretation implicitly or explicitly require the use of formation resistivity factors or, as they are now generally called, formation factors. The originator both of the concept of formation factor and of the use of formation factor data in electric log interpretation was Archie. More recently it has been suggested that formation factors are of value in describing fluid flow in porous media. A full discussion of this problem together with adequate references has given by Wyllie and Spangler. In spite of the theoretical and practical importance of the subject, there appear to be remarkably few basic formation factor data in the petroleum literature. A wider search reveals that this situation is not confined to the literature of the petroleum industry. At various times over the last century, attempts have been made to compute the theoretical relationship between the formation factor and porosity of simple systems of unconsolidated particles. However, the formulae derived are not all identical and the experimental evidence adduced in support of each is not wholly convincing. Most of the experimental work has been carried out on systems of unconsolidated spheres, although some attention has been given to systems of spheroids and cylinders. Other simple shapes have received neither theoretical nor experimental investigation. The writers feel that a better understanding of the formation factors of complex systems of practical importance requires a firm foundation of reliable experimental data applicable to simple systems. Accordingly, they have reviewed the relevant literature and have determined experimentally the relationship between the formation factor and porosity of unconsolidated aggregates of particles of regular geometrical shapes. Some experiments have also been carried out to investigate the effect of cementation on the formation factor-porosity relationship.

Renal aspects of experimental and clinical hypertension: Corcoran, A. C., and Page, I. H.: J. Lab. & Clin. Med. 26: 1713, 1941

New data relating to the kinetics and adsorption isotherms of asphaltene in consolidated sandstone core samples are reported. The data were obtained from the measurements of electrokinetics of consolidated sandstone core samples in asphaltene/toluene solutions and petroleum oils. The numerical reduction in the (negative) zeta potential of the sandstone samples were attributed to the adsorption of positively charged molecules of asphaltenes. The hydrodynamics thickness δ of adsorption of asphaltene were followed by monitoring the pressure increase that occurred as the adsorbed layer restricted the rock pores and applying Poiseuille's equation. The flow rates indicated a plateau of asphaltene adsorption at a pore blocking thickness of about δ/r = 0.3, which was also the point at which the streaming current reached a plateau. After increasing to about 30% of the pore radius, the adsorbed layer thickness δ stopped growing either with time or with concentration of asphaltene in the flowing liquid. Alternative hypotheses involving asphaltene adsorption isotherms have been investigated. A theoretical treatment advanced describing particle adsorption in the same terms as molecular adsorption and the Langmuir isotherm, with the free energy of asphaltene adsorption on the rock surface (modeled on silica) calculated on the basis of van der Waals attraction. Acceptable agreement was obtained with the electrokinetic measurements.