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By Harry W. Brown

This paper presents results of static capillary pressure measprements made both by the restored-state and by the mercury-injection methods, and of dynamic capillary pressure measurements made by the Hassler technique. The results indicate a variation from sample to sample of the factor used to convert capillary pressure obtained by mercury injection to those applicable to a water-gas system. Static capillary pressures measured by the restored-state method were found to be in close agreement with dynamic capillary pressures, indicating that data obtained from static measurements may be utilized with confidenre in the solution of dynamic problems of fluid flow. Experimental data are presented on the use of "J-curves" for the correlation of capillary pressure-saturation relations for a number of cores from a particular geologic formation. It is shown that the correlation was improved in some cases by reqtricting it to rertain lithologic classifications. INTRODUCTION The Meaning and Importance of Capillary Pressure The coexistence of two or more immiscible fluids within the voids of a porous medium, such as reservoir rock, gives rise to capillary forces. Because of the interfacial tension existing at the boundary between two immiscible fluids in a pore space, the interface is curved, and there is a pressure difference across the interface. This pressure difference is termed the capillary pressure. The magnitude of the capillary pressure between two immiscible fluids which together fill a porous medium depends upon several factors: the textural properties of the medium, the wettability of the medium, the interfacial tension between the fluids, the respective saturations of the fluids, and the manner in which these saturations are attained. For a given pair of immiscible fluids in a particular sample of reservoir rock, the capillary pressure is a unique function of the fluid saturation, provided that the saturation of the fluid which wets the rock has previously been decreased unidirectionally from an initially complete saturation. Similarly, for a given pair of fluids at a particular saturation which has been achieved by a

Jan 1, 1951

By R. A. Morse, W. W. Owens, D. R. Parrish, T. M. Geffen

Laboratory studies of several factors affecting measurements of relative permeability were made using the three-section plastic-covered core technique. Results show that the core assembly, properly constructed, will perform as a single unit, and that the testing technique will, under suitable conditions of pressure gradient, gas expansion, and migration of partial water saturation, permit measurement of flow characteristics not affected by technique. Wettability equilibrium is readily established in cores exhibiting strong wetting preference to water or oil when initially saturated with water. Laboratory tests must be conducted so that saturation changes represent those that occur in the reservoir. Immediate implications of saturation history are (1:) that the possibility exists of increasing the displacement efficiency of solution gas drive reservoirs over the natural process, and (2) residual gas saturations following water flooding in gas or gas condensate reservoirs will be 15 to 50 per cent pore space rather than 1 to 11 per cent as generally believed. INTRODUCTION Solutions of petroleum reservoir problems pertaining to production performance require the use of true relative permeability characteristics. 'This relationship of fluid conductivity and saturation has been obtained by reservoir engineers in four ways, namely: 1. From past gross reservoir performance and the extrapolation of this data based on experience,1,2 2. By using published fluid flow relationships obtained in laboratory studies on general type porous materials,3, 4, 5 3. By attempting a mathematical derivation of flow behavior," using some experimentally obtained characteristics of reservoir rocks, and 4. By laboratory flow tests using representative rock samples of a reservoir. The first three methods listed above have shortcomings which make their use limited or questionable. Production characteristics of only certain processes are obtained from field data and these are not available at the beginning of a reservoir's producing life, at which time they are desirable. It is fortuitous if general fluid flow characteristics obtained experimentally have accurate application to specific field problems. Also, it is felt that at this time there is not sufficient knowledge of the flow behavior of oil, water, and gas in porous materials to enable applicable analytical description of this to be made based on other measured rock characteristics. Measurement of relative permeability in the laboratory offers the only direct method subject to adequate checking for determination of flow characteristics applicable to field problems. Primarily, this paper deals with laboratory experiments to establish the effects of several factors on the measurement of relative permeability and the practical significance of this knowledge. Laboratory flow tests are essentially model studies; the gross reservoir being represented by a small rock sample. It is necessary to simulate in experiments all the factors of importance which influence flow in the reservoir, as well a.; to eliminate effects peculiar to the model studied to assure measurement of valid flow behavior. Factors which affect the measurement and behavior of fluid flow in porous materials have been studied by other investigators.3,7,8,9,10,11 This analysis is not intended to evaluate fully all factors involved, but to establish first the validity of measurements by the technique used and then study flow behavior under various conditions. The studies reported are as follows: 1. Effects of pressure gradient, 2. Effects of gas expansion in tests conducted at near atmospheric pressure, 3. Effects of migration of a partial water saturation in oil-gas-water systems, 4. Effects If wettability characteristics of the system. and 5. Effects of the fluid saturation history. The first three are important only in laboratory measure-

Jan 1, 1951

By D. R. Parrish, T. M. Geffen, R. A. Morse, W. W. Owens

Laboratory studies of several factors affecting measurements of relative permeability were made using the three-section plastic-covered core technique. Results show that the core assembly, properly constructed, will perform as a single unit, and that the testing technique will, under suitable conditions of pressure gradient, gas expansion, and migration of partial water saturation, permit measurement of flow characteristics not affected by technique. Wettability equilibrium is readily established in cores exhibiting strong wetting preference to water or oil when initially saturated with water. Laboratory tests must be conducted so that saturation changes represent those that occur in the reservoir. Immediate implications of saturation history are (1:) that the possibility exists of increasing the displacement efficiency of solution gas drive reservoirs over the natural process, and (2) residual gas saturations following water flooding in gas or gas condensate reservoirs will be 15 to 50 per cent pore space rather than 1 to 11 per cent as generally believed. INTRODUCTION Solutions of petroleum reservoir problems pertaining to production performance require the use of true relative permeability characteristics. 'This relationship of fluid conductivity and saturation has been obtained by reservoir engineers in four ways, namely: 1. From past gross reservoir performance and the extrapolation of this data based on experience,1,2 2. By using published fluid flow relationships obtained in laboratory studies on general type porous materials,3, 4, 5 3. By attempting a mathematical derivation of flow behavior," using some experimentally obtained characteristics of reservoir rocks, and 4. By laboratory flow tests using representative rock samples of a reservoir. The first three methods listed above have shortcomings which make their use limited or questionable. Production characteristics of only certain processes are obtained from field data and these are not available at the beginning of a reservoir's producing life, at which time they are desirable. It is fortuitous if general fluid flow characteristics obtained experimentally have accurate application to specific field problems. Also, it is felt that at this time there is not sufficient knowledge of the flow behavior of oil, water, and gas in porous materials to enable applicable analytical description of this to be made based on other measured rock characteristics. Measurement of relative permeability in the laboratory offers the only direct method subject to adequate checking for determination of flow characteristics applicable to field problems. Primarily, this paper deals with laboratory experiments to establish the effects of several factors on the measurement of relative permeability and the practical significance of this knowledge. Laboratory flow tests are essentially model studies; the gross reservoir being represented by a small rock sample. It is necessary to simulate in experiments all the factors of importance which influence flow in the reservoir, as well a.; to eliminate effects peculiar to the model studied to assure measurement of valid flow behavior. Factors which affect the measurement and behavior of fluid flow in porous materials have been studied by other investigators.3,7,8,9,10,11 This analysis is not intended to evaluate fully all factors involved, but to establish first the validity of measurements by the technique used and then study flow behavior under various conditions. The studies reported are as follows: 1. Effects of pressure gradient, 2. Effects of gas expansion in tests conducted at near atmospheric pressure, 3. Effects of migration of a partial water saturation in oil-gas-water systems, 4. Effects If wettability characteristics of the system. and 5. Effects of the fluid saturation history. The first three are important only in laboratory measure-

Jan 1, 1951

By B. H. Caudle, R. L. Slobod, E. R. Brownscombe

An earlier publication has discussed three methods lor obtaining relative permeability data on small core sample-: and the apparatus and technique for the capillary pressure displacement method. This paper describes the apparatus and technique for the solution gas and the dynamic displacement methods and presents a routine procedure for obtaining oil-gas and water-oil relative permeability data. Theoretical and experimental considerations are presented to show that the end effect commonly associated with the dynamic flow mechanism is extremely small where constant rates are employed in the flowing phase. An effect of flow rate on relative permeabilities obtained by the dynamic system is found only when gas is one of the flowing phases and this effect is ascribed to a form of channeling in the capillary system. The apparatus and procedure* used to obtain relative permeability data with three phases flowing are described and some preliminary results of the use of this method are shown. INTRODUCTION In a previous publication from this laboratory there appeared a brief discussion of the concepts behind three basic methods for obtaining relative permeability data.' These three methods were called the capillary pressure displacement method. the solution gas displacement method, and the dy. namic displacement method — the names being suggestive of the type of process used for obtaining the desired saturation prior to making the permeability measurements. In the same publication, the apparatus and technique for the capillary pressure displacement method were described and some typical results obtained by this method were presented. This paper will present: 1. The routine procedure used to obtain complete relative permeabilitv data (In small core samples with two phasec flowing; 2. The experimental techniques for the solution gas and dynamic displacement methods for obtaining relative permeability data; 3. The results of some studies on the mechanism of fluid flow through consolidated porous media; and, 4. The preliminary results on the determination of relative permeability for a system in which three phases are flowing. TECHNIQUE AND APPARATUS FOR THE DETERMINATION OF RELATIVE PERMEABILITY WITH TWO PHASES FLOWING In order to obtain relative permeability data on a small core sample which will describe the various phases of reservoir depletion. it is necessary that the methods used duplicate, as closely as possible, the various mechanisms involved in rescbrvoir depletion. It is important that. in any type of relative permedbility determination. the core be originally at virgin reservoir conditions with respect to the fluids within the pore *paces. (for example. oil used to displace water from core until connate water saturation estahlished). and that the subsequent saturation changes in the core be analagous to tile reservoir depletion mechanism for which the data are to he used. PROCEDURE OF DETERMINING RELATIVE PERMEABILITY DATA WITH TWO PHASES FLOWING A standardized procedure has been set up for obtaining relative permeability data and other information on small core samples. This procedure essentially consists of 11 steps as shown below: 1. Determination of tile capillary pressure curve.'! This information is used to help select samples for relative permeability determinations and to charactrrize. in general. the pore size distribution of the sample. 2. Determination of the specific permeabilities to air, oil. and water. These values are those on which the relative pern~eahility calculations are based. 3. Reduction of the core to connate water by an oil drive using the high speed centrifuge. 1. Determination of the critical gas saturation value and the associated relative permeability to oil by the solution gas drive method. 5. Determination of the relative permeabilities to oil and gab in the region where both phases are flowing by the capillary presqure method. 6. Reduction of the sample to residual oil in the centrifuge by an air drive. and the determination of the relative permeability to gas at this point.

Jan 1, 1951

By R. L. Slobod, B. H. Caudle, E. R. Brownscombe

An earlier publication has discussed three methods lor obtaining relative permeability data on small core sample-: and the apparatus and technique for the capillary pressure displacement method. This paper describes the apparatus and technique for the solution gas and the dynamic displacement methods and presents a routine procedure for obtaining oil-gas and water-oil relative permeability data. Theoretical and experimental considerations are presented to show that the end effect commonly associated with the dynamic flow mechanism is extremely small where constant rates are employed in the flowing phase. An effect of flow rate on relative permeabilities obtained by the dynamic system is found only when gas is one of the flowing phases and this effect is ascribed to a form of channeling in the capillary system. The apparatus and procedure* used to obtain relative permeability data with three phases flowing are described and some preliminary results of the use of this method are shown. INTRODUCTION In a previous publication from this laboratory there appeared a brief discussion of the concepts behind three basic methods for obtaining relative permeability data.' These three methods were called the capillary pressure displacement method. the solution gas displacement method, and the dy. namic displacement method — the names being suggestive of the type of process used for obtaining the desired saturation prior to making the permeability measurements. In the same publication, the apparatus and technique for the capillary pressure displacement method were described and some typical results obtained by this method were presented. This paper will present: 1. The routine procedure used to obtain complete relative permeabilitv data (In small core samples with two phasec flowing; 2. The experimental techniques for the solution gas and dynamic displacement methods for obtaining relative permeability data; 3. The results of some studies on the mechanism of fluid flow through consolidated porous media; and, 4. The preliminary results on the determination of relative permeability for a system in which three phases are flowing. TECHNIQUE AND APPARATUS FOR THE DETERMINATION OF RELATIVE PERMEABILITY WITH TWO PHASES FLOWING In order to obtain relative permeability data on a small core sample which will describe the various phases of reservoir depletion. it is necessary that the methods used duplicate, as closely as possible, the various mechanisms involved in rescbrvoir depletion. It is important that. in any type of relative permedbility determination. the core be originally at virgin reservoir conditions with respect to the fluids within the pore *paces. (for example. oil used to displace water from core until connate water saturation estahlished). and that the subsequent saturation changes in the core be analagous to tile reservoir depletion mechanism for which the data are to he used. PROCEDURE OF DETERMINING RELATIVE PERMEABILITY DATA WITH TWO PHASES FLOWING A standardized procedure has been set up for obtaining relative permeability data and other information on small core samples. This procedure essentially consists of 11 steps as shown below: 1. Determination of tile capillary pressure curve.'! This information is used to help select samples for relative permeability determinations and to charactrrize. in general. the pore size distribution of the sample. 2. Determination of the specific permeabilities to air, oil. and water. These values are those on which the relative pern~eahility calculations are based. 3. Reduction of the core to connate water by an oil drive using the high speed centrifuge. 1. Determination of the critical gas saturation value and the associated relative permeability to oil by the solution gas drive method. 5. Determination of the relative permeabilities to oil and gab in the region where both phases are flowing by the capillary presqure method. 6. Reduction of the sample to residual oil in the centrifuge by an air drive. and the determination of the relative permeability to gas at this point.

Jan 1, 1951

By E. S. Messer

A knowledge of the magnitude of the irreducible inter.;titial water in a porous medium is so important to petroleum engineering that its determination has become routine in core analyses. The method of determination, being a production problem, should encompass the basic requirements of simplicity in technique and calculations, with reproducible results obtainable in a short interval of time. The results of the evaluation tests outlined in this report indicate that the evaporation method for determining the irreducible water is a technique which meets the requirements. The procedure consists, as the name implies. of permitting the saturant in the pore spaces to evaporate until only an irreducible volume remains. The determination of this volume can be made either graphically or by a mathematical comparison of fluid flows; the time required for each determination being dependent on the fluid used. When fluids other than those having reservoir characteristics were used, a volume factor had to be calculated which was based on the relative volume of various liquids adsorbed on grain surfaces and retained in pores. This factor made possible the calculation of an irreducible water volume when more volatile fluids such as toluene and benzene were used as the saturants. Also presented is the theoretical discussion necessary for the calculation of the capillary pressure as determined from the evaporation curve. A comparison is made between the calculated values and those obtained by experimental means. INTRODUCTION In all geological formations there exists, in the pore spaces of the rock structure, water that is held in a state of equilibrium between capillary and hydrostatic forces. "Interstitial water" is the term given to this water and is defined as that water coexisting in the pore space with the oil prior to exploitation. The term ''connate water" has often been used synonymously with this term; however, this can be true only by a specific definition since, geologically, it means the water in place at the time the rock structure was formed. The quantity of the interstitial water is a variable factor in any formation, since it depends on the hydrostatic forces present in any multiple-phase system. These forces may become unbalanced by the introduction of an extraneous force such as the raising or lowering of the "water table" or the migration of oil into a water-filled formation. Any unbalanced force results in a change in the interstitial water. There exists, however, an irreducible interstitial water. for a particular sand, that is the fraction of the pore space occupied by water when the capillary pressure at the particular point in question is at an equilibrium with the hydrostatic head of the oil sand in the reservoir. For this discussion the term "irreducible water saturation" will be used in place of "irreducible interstitial water saturation" for the sake of brevity; however, they are understood to be identical. A great amount of work has been devoted to the theory and methods for studying the irreducible water saturation and its related capillary pressure. As a result of the publications of Leverett;' Hassler, Brunner and Deahl;2 Calhoun and Lewis;3 and others, the role of capillary pressure studies is being accepted by the industry as a tool for studying suhsurface phenomena. Many techniques have been developed and published for determining the capillary pressure and irreducible water. In general, these techniques may be grouped into three classifications. One of the first was the capillary pressure method described by Leverett1 and expanded by Bruce and Welge.4 The experimental results were compared with water saturation of cores obtained using oil-base mud. Thornton and Marshall compared the irreducible water saturation of core samples determined by the capillary pressure method and by salinity and reported good agreement between the two methods. The second classification for determining the irreducible water and capillary pressure may be referred to as the "centrifugal force method." The general technique is similar to the capillary pressure method except that the force driving the reservoir fluid from the sample is of a centrifugal nature. A complete description of this method was presented by J. J. . McCullough and F. W. Albaugh.6 A process, the reverse of the capillary pressure method, was presented by W. R. Purcell.7 Mercury under pressure is driven into the pores of the rock and the saturation of the core determined at each applied pressure. The resulting capillary pressure curve is used to evaluate the irreducible water saturation. The techniques mentioned are singular in their approach to the irreducible water saturation. In all cases. an external force was applied to the core. The forces employed in the evaporation method are the vapor pressure of the liquid causing evaporation, the kinetic diffusion forces. adsorptive forces and. to a lesser degree, the viscous forces resisting flow to the surface. The basic definition of irreducible water is that water held in a state of equilibrium between capillary and hydrostatic forces This water has been described by previous investigators as being held in the microcapillaries too small to support fluid flow. Actually, this fluid volume is made up of the water in the microcapillaries and as a film adhering to the surface of the crystals. All capillaries. therefore, possess some liquid as a film, the thickness of the film being dependent on the properties of the fluid and solid. A discussion of experiments with references pertaining to the measurement of this immobile layer next to the solid surface can be found in the text by J. J. Bikerman.8 Eversole and Lahr calculated the thickness of this layer to be in the order of 10 ' to 10' cm for aqueous solutions and glass. Between two quartz surfaces they found the thickness to be 2 x 10 cm. The work of Volkova, on the capillary movement of water and toluene in quartz grains, indicated the thickness of the Immobile layers to be near 10' cm. Since any measurement is an average value, it is easy to understand that an absolute value would depend on the roughness of the surfaces involved and the complexity of the system. A calculated effective pore radius of 2 x 10 cm is obtained at the, irreducible saturation of a porous media in a water-air system when a capillary pressure of 100 psi is applied. Since the separation of the sand grains is of the same approximate magnitude as the immobile layer.

Jan 1, 1951

By E. S. Messer

A knowledge of the magnitude of the irreducible inter.;titial water in a porous medium is so important to petroleum engineering that its determination has become routine in core analyses. The method of determination, being a production problem, should encompass the basic requirements of simplicity in technique and calculations, with reproducible results obtainable in a short interval of time. The results of the evaluation tests outlined in this report indicate that the evaporation method for determining the irreducible water is a technique which meets the requirements. The procedure consists, as the name implies. of permitting the saturant in the pore spaces to evaporate until only an irreducible volume remains. The determination of this volume can be made either graphically or by a mathematical comparison of fluid flows; the time required for each determination being dependent on the fluid used. When fluids other than those having reservoir characteristics were used, a volume factor had to be calculated which was based on the relative volume of various liquids adsorbed on grain surfaces and retained in pores. This factor made possible the calculation of an irreducible water volume when more volatile fluids such as toluene and benzene were used as the saturants. Also presented is the theoretical discussion necessary for the calculation of the capillary pressure as determined from the evaporation curve. A comparison is made between the calculated values and those obtained by experimental means. INTRODUCTION In all geological formations there exists, in the pore spaces of the rock structure, water that is held in a state of equilibrium between capillary and hydrostatic forces. "Interstitial water" is the term given to this water and is defined as that water coexisting in the pore space with the oil prior to exploitation. The term ''connate water" has often been used synonymously with this term; however, this can be true only by a specific definition since, geologically, it means the water in place at the time the rock structure was formed. The quantity of the interstitial water is a variable factor in any formation, since it depends on the hydrostatic forces present in any multiple-phase system. These forces may become unbalanced by the introduction of an extraneous force such as the raising or lowering of the "water table" or the migration of oil into a water-filled formation. Any unbalanced force results in a change in the interstitial water. There exists, however, an irreducible interstitial water. for a particular sand, that is the fraction of the pore space occupied by water when the capillary pressure at the particular point in question is at an equilibrium with the hydrostatic head of the oil sand in the reservoir. For this discussion the term "irreducible water saturation" will be used in place of "irreducible interstitial water saturation" for the sake of brevity; however, they are understood to be identical. A great amount of work has been devoted to the theory and methods for studying the irreducible water saturation and its related capillary pressure. As a result of the publications of Leverett;' Hassler, Brunner and Deahl;2 Calhoun and Lewis;3 and others, the role of capillary pressure studies is being accepted by the industry as a tool for studying suhsurface phenomena. Many techniques have been developed and published for determining the capillary pressure and irreducible water. In general, these techniques may be grouped into three classifications. One of the first was the capillary pressure method described by Leverett1 and expanded by Bruce and Welge.4 The experimental results were compared with water saturation of cores obtained using oil-base mud. Thornton and Marshall compared the irreducible water saturation of core samples determined by the capillary pressure method and by salinity and reported good agreement between the two methods. The second classification for determining the irreducible water and capillary pressure may be referred to as the "centrifugal force method." The general technique is similar to the capillary pressure method except that the force driving the reservoir fluid from the sample is of a centrifugal nature. A complete description of this method was presented by J. J. . McCullough and F. W. Albaugh.6 A process, the reverse of the capillary pressure method, was presented by W. R. Purcell.7 Mercury under pressure is driven into the pores of the rock and the saturation of the core determined at each applied pressure. The resulting capillary pressure curve is used to evaluate the irreducible water saturation. The techniques mentioned are singular in their approach to the irreducible water saturation. In all cases. an external force was applied to the core. The forces employed in the evaporation method are the vapor pressure of the liquid causing evaporation, the kinetic diffusion forces. adsorptive forces and. to a lesser degree, the viscous forces resisting flow to the surface. The basic definition of irreducible water is that water held in a state of equilibrium between capillary and hydrostatic forces This water has been described by previous investigators as being held in the microcapillaries too small to support fluid flow. Actually, this fluid volume is made up of the water in the microcapillaries and as a film adhering to the surface of the crystals. All capillaries. therefore, possess some liquid as a film, the thickness of the film being dependent on the properties of the fluid and solid. A discussion of experiments with references pertaining to the measurement of this immobile layer next to the solid surface can be found in the text by J. J. Bikerman.8 Eversole and Lahr calculated the thickness of this layer to be in the order of 10 ' to 10' cm for aqueous solutions and glass. Between two quartz surfaces they found the thickness to be 2 x 10 cm. The work of Volkova, on the capillary movement of water and toluene in quartz grains, indicated the thickness of the Immobile layers to be near 10' cm. Since any measurement is an average value, it is easy to understand that an absolute value would depend on the roughness of the surfaces involved and the complexity of the system. A calculated effective pore radius of 2 x 10 cm is obtained at the, irreducible saturation of a porous media in a water-air system when a capillary pressure of 100 psi is applied. Since the separation of the sand grains is of the same approximate magnitude as the immobile layer.

Jan 1, 1951

By J. A. Hafford, J. K. Kerver, J. G. Richardson, P. M. Blair, J. S. Osoba

This paper presents the results of laboratory measurements of relative permeabilities to oil and gas on small core samples of reservoir rock by five methods, and describes the influences of such factors as boundary effect, hysteresis, and rate upon these measurements. The five methods used were the "Penn State," the "single core dynamic," the "gas drive," the "stationary liquid," and the "Hassler" techniques. In those methods in which the results are subject to error hecause of the boundary effect, the error may be minimized hy the use of high rates of flow. In order to avoid complexities introduced by hysteresis, it is necessary to approach each saturation unidirectionally. Observed deviations of relative permeabilities with rate can be explained as a manifestation of the boundary effect, and disappear as the boundary effect vanishes. The results indicate that all five methods yield essentially the same relative permeabilities to gas. Of the four methods applicable to the determination of relative permeability to oil, three, the Penn State, single core dynamic, and gas drive, gave relative permeabilities to oil which were in close agreement. The Hassler method gave relative permeabilities to oil which were consistently lower than the results obtained by the other methods. INTRODUCTION The relationship between the effective permeability of a reservoir rock to each of the fluids flowing through it and the corresponding fluid saturation is an important characteristic of the reservoir rock. Knowledge of this characteristic is and gas reservoirs and of the ultimate recovery to be expected extremely important in the prediction of the behavior of oil under various operating conditions. These effective permeabilities are usually expressed as the "relative permeability" to a fluid phase, defined as the ratio of the effective permeability to the permeability of the rock to a single phase at 100 per cent saturation. Relative permeability-saturation relations are not the same for all kinds of reservoir rock, but may vary from formation to formation, and within the different portions of a heterogeneous formation. In studying the performance of a specific reservoir, it is necessary, then, that the relative permeability characteristics of the individual portions of the reservoir be measured. These measurements may be made in the laboratory on small core samples from the reservoir. Various techniques have been proposed for the measurement in the laboratory of relative permeability-saturation relations. In varying degree, difficulties attend the use of all of the methods which have been proposed. It is the purpose of this paper to discuss the factors which influence the measurement of relative permeability, the difficulties encountered in several methods, and to present comparative results obtained by the use of various techniques. FACTORS WHICH INFLUENCE THE MEASUREMENT OF RELATIVE PERMEABILITY It is necessary that the relative permeability data measured in the laboratory yield the same relative permeability-saturation relationships that would govern the flow of fluids through the sample if it were to occupy its original position in the reservoir. Since the core sample upon which the laboratory measurements are made is not surrounded by similar core material as it was in the reservoir, an error in measuring the relative permeabilities may arise from the "boundary effect" which results from a discontinuity in capillary properties of the system at the effluent end of the core. Again, the rates of

Jan 1, 1951

By J. K. Kerver, J. S. Osoba, J. G. Richardson, P. M. Blair, J. A. Hafford

This paper presents the results of laboratory measurements of relative permeabilities to oil and gas on small core samples of reservoir rock by five methods, and describes the influences of such factors as boundary effect, hysteresis, and rate upon these measurements. The five methods used were the "Penn State," the "single core dynamic," the "gas drive," the "stationary liquid," and the "Hassler" techniques. In those methods in which the results are subject to error hecause of the boundary effect, the error may be minimized hy the use of high rates of flow. In order to avoid complexities introduced by hysteresis, it is necessary to approach each saturation unidirectionally. Observed deviations of relative permeabilities with rate can be explained as a manifestation of the boundary effect, and disappear as the boundary effect vanishes. The results indicate that all five methods yield essentially the same relative permeabilities to gas. Of the four methods applicable to the determination of relative permeability to oil, three, the Penn State, single core dynamic, and gas drive, gave relative permeabilities to oil which were in close agreement. The Hassler method gave relative permeabilities to oil which were consistently lower than the results obtained by the other methods. INTRODUCTION The relationship between the effective permeability of a reservoir rock to each of the fluids flowing through it and the corresponding fluid saturation is an important characteristic of the reservoir rock. Knowledge of this characteristic is and gas reservoirs and of the ultimate recovery to be expected extremely important in the prediction of the behavior of oil under various operating conditions. These effective permeabilities are usually expressed as the "relative permeability" to a fluid phase, defined as the ratio of the effective permeability to the permeability of the rock to a single phase at 100 per cent saturation. Relative permeability-saturation relations are not the same for all kinds of reservoir rock, but may vary from formation to formation, and within the different portions of a heterogeneous formation. In studying the performance of a specific reservoir, it is necessary, then, that the relative permeability characteristics of the individual portions of the reservoir be measured. These measurements may be made in the laboratory on small core samples from the reservoir. Various techniques have been proposed for the measurement in the laboratory of relative permeability-saturation relations. In varying degree, difficulties attend the use of all of the methods which have been proposed. It is the purpose of this paper to discuss the factors which influence the measurement of relative permeability, the difficulties encountered in several methods, and to present comparative results obtained by the use of various techniques. FACTORS WHICH INFLUENCE THE MEASUREMENT OF RELATIVE PERMEABILITY It is necessary that the relative permeability data measured in the laboratory yield the same relative permeability-saturation relationships that would govern the flow of fluids through the sample if it were to occupy its original position in the reservoir. Since the core sample upon which the laboratory measurements are made is not surrounded by similar core material as it was in the reservoir, an error in measuring the relative permeabilities may arise from the "boundary effect" which results from a discontinuity in capillary properties of the system at the effluent end of the core. Again, the rates of

Jan 1, 1951

By Herman Dykstra, Irving Fatt

Relative wetting phase permeabilities calculated from capillary pressure-saturation data are compared with measured relative permeability data. The equation relating relative permeability to capillary pressure-saturation data is derived by assuming that a porous medium is analogous to a bundle of capillary tubes. The equation includes a term to correct for the difference between fluid path length and length of core. Relative oil permeability data in the water-oil-gas system are presented, and it is shown that if the water is considered part of he rock matrix, the relative oil permeability curve is typical of a wetting phase relative permeability curve. Apparatus for measuring two and three-phase relative permeabilities are described. INTRODUCTION The difficulty in measuring relative permeability of cores has made it desirable to have a correlation between relative permeability and some more easily measured property of porous media. Such an easily measured property is the capillary preisure-saturation relation. In the past there has been a tendency to separate the capillary pressure concept from the very complex pore geometry and to consider that the capillary pressure-saturation curve give? only some characteristic distribution of interfacial curvature between two fluids.' Recently, however, it has been realized that if capillary pressure data are to yield information concerning pore size distribution2 and fluid flow in porous media. the pore must be assumed to have a simple shape such as a cylinder or a sphere. Childs and George' showed that relative water permeability could be calculated from the capillary pressure-water saturation curve by assuming that the pores are cylinders in which the fluid flowing obeys Poiseuille's Law, and that the capillary preisure curve indicated the size and number of pores. Purcell5 derived an equation relating the permeability of a porous medium to the capillary pressure curve by assuming the porous medium to he analogous to a bundle of capillary tubes. Gates and Lietz6 calculated relative permeability by an equa-tion derived from Purcell's equation. In this paper an equation is derived giving the relative water permeability as a function of water saturation by as-sulning that the core sample can be represented by a bundle of capillary tubes in which the fluid path length is not the same as the bulk length, and in which the fluid path length varies with saturation. THEORY For a bundle of N capillary tubes the flow through dN tubes will be dQ = qav dN ..........(1) where Q is the total flow rate through all the tubes and q., is the aberage flow rate through the tubes in the interval dN. If the interval dN is made small the average flow rate through a tube in the interval dN is given by Poiseuille's Law, 8 nl where ?P is the pressure drop across the tube of length 1 and radius r, and µ is the viscosity of the fluid. Substituting for qav in Equation (1), dQ =pr4 ? P/8µl dN.........(3) Darcy's Law for linear flow of an incompressible fluid in a porous medium is Q = KA?P/µL...........(4) where K is the permeability and ?P is the pressure drop across a bundle of tubes which has replaced the porous medium of length L and cross-sectional area A. Differentiating Darcy's Law with A, ?P, µ, and L constant, dQ = A?P/µL dK.........(5) Equating (3) and (5) gives dK------------dN.........(6) 8Al If the pores are assumed to be cylinders dV =pr2ldN..........(7) where V is the volume of flowing fluid in the pores. Substituting for dN in Equation (6) gives dK = —dV..........(8) 8AI' By definition the saturation, S, of the core is v v S =V/Vp..........(9) Vv -PAL

Jan 1, 1951

By Irving Fatt, Herman Dykstra

Relative wetting phase permeabilities calculated from capillary pressure-saturation data are compared with measured relative permeability data. The equation relating relative permeability to capillary pressure-saturation data is derived by assuming that a porous medium is analogous to a bundle of capillary tubes. The equation includes a term to correct for the difference between fluid path length and length of core. Relative oil permeability data in the water-oil-gas system are presented, and it is shown that if the water is considered part of he rock matrix, the relative oil permeability curve is typical of a wetting phase relative permeability curve. Apparatus for measuring two and three-phase relative permeabilities are described. INTRODUCTION The difficulty in measuring relative permeability of cores has made it desirable to have a correlation between relative permeability and some more easily measured property of porous media. Such an easily measured property is the capillary preisure-saturation relation. In the past there has been a tendency to separate the capillary pressure concept from the very complex pore geometry and to consider that the capillary pressure-saturation curve give? only some characteristic distribution of interfacial curvature between two fluids.' Recently, however, it has been realized that if capillary pressure data are to yield information concerning pore size distribution2 and fluid flow in porous media. the pore must be assumed to have a simple shape such as a cylinder or a sphere. Childs and George' showed that relative water permeability could be calculated from the capillary pressure-water saturation curve by assuming that the pores are cylinders in which the fluid flowing obeys Poiseuille's Law, and that the capillary preisure curve indicated the size and number of pores. Purcell5 derived an equation relating the permeability of a porous medium to the capillary pressure curve by assuming the porous medium to he analogous to a bundle of capillary tubes. Gates and Lietz6 calculated relative permeability by an equa-tion derived from Purcell's equation. In this paper an equation is derived giving the relative water permeability as a function of water saturation by as-sulning that the core sample can be represented by a bundle of capillary tubes in which the fluid path length is not the same as the bulk length, and in which the fluid path length varies with saturation. THEORY For a bundle of N capillary tubes the flow through dN tubes will be dQ = qav dN ..........(1) where Q is the total flow rate through all the tubes and q., is the aberage flow rate through the tubes in the interval dN. If the interval dN is made small the average flow rate through a tube in the interval dN is given by Poiseuille's Law, 8 nl where ?P is the pressure drop across the tube of length 1 and radius r, and µ is the viscosity of the fluid. Substituting for qav in Equation (1), dQ =pr4 ? P/8µl dN.........(3) Darcy's Law for linear flow of an incompressible fluid in a porous medium is Q = KA?P/µL...........(4) where K is the permeability and ?P is the pressure drop across a bundle of tubes which has replaced the porous medium of length L and cross-sectional area A. Differentiating Darcy's Law with A, ?P, µ, and L constant, dQ = A?P/µL dK.........(5) Equating (3) and (5) gives dK------------dN.........(6) 8Al If the pores are assumed to be cylinders dV =pr2ldN..........(7) where V is the volume of flowing fluid in the pores. Substituting for dN in Equation (6) gives dK = —dV..........(8) 8AI' By definition the saturation, S, of the core is v v S =V/Vp..........(9) Vv -PAL

Jan 1, 1951

By W. J. Leas, L. A. Rapoport

As a preliminary, consicleration is given to the conventional definition of relative permeability and to the conditions governing the simultaneous flow of oil and gas through porous media. For the conditions of flow prevailing throughout most of a gas drive reservoir, the oil and gas can reasonably be supposed to be in capillary equilibrium with each other. Under these conditions, and these conditions only, the relative permeability to liquid can be expressed as a function of saturation. The relative permeability to liquid in that case is dependent upon the distribution of fluids which itself is shown to be related to the capillary pressure, and, in turn, to the saturation. As a consequence, relative permeability to liquid can be expressed in terms of the volume and surface area of a network of liquid channels bounded by the rock and the gas phase. While the volume of this network can be evaluated accurately, the surface area cannot. However, for any such volume, maximum and minimum values of the corresponding surface area can be calculated from capillary pressure data. It is then possible to establish for any saturation the limits within which the value of the relative permeability to liquid must lie. As a consequence of the theoretical development, the validity of an experimental method for measuring relative permeability to liquid which utilizes a stationary gas phase is demonstrated. In this method capillary barriers are cemented to the ends of the core sample to permit the maintenance of capillary equilibrium between the two phases. At the same time, this procedure eliminates undesirable secondary phenomena such as end effects, fissure effects, etc., the presence of which adversely affect the results of other laboratory methods. The results obtained by theoretical calculations, and experimentally, are discussed. In view of the overall precision that can presently be obtained in reservoir calculations, the agreement between the calculated and measured relative permeability to liquid data can be considered satisfactory. In conclusion, for reasons of economy and simplicity, the procedure of calculating limiting relative permeability to liquid curves from capillary pressure data is indicated for general engineering purposes. It is shown that the above procedure can easily be extended to the cases where connate water is present. Its use for reservoir studies is particularly recommended in conjunction with the method for measuring relative permeability to gas' which simultaneously yields the capillary pressure data necessary for the calculations. THEORETICAL Definition of Relative Permeabilities — Basic Equations for Heterogeneous Flow The equations by which the relative permeability concept is defined and upon which the formulation of all of the gas-oil flow problems rests at the present time are expressed as: V, = — Grad PL = — Grad PL ....(la) PL µL, k k KG VG = —K - Grad PG k- Grad Pc .... (lb) Mo where ,. and G refer to liquid and gas; V is the volumetric rate of flow per unit gross area. µ the viscosity, Grad P the potential gradient. and k the specific permeability of the porous medium.* (For horizontal flow, Grad P becomes the pressure gradient; otherwise, gravity must be included.) According to these expressions, each of the constituent phases is considered similar to a homogeneous system where the volumetric rate of flow is proportional to the pressure gradient, and for each of which the constants of proportionality, k, and kG, are termed effective permeabilities. by analogy to the specific permeability as defined by Darcy's law in its original form. In order to obtain a convenient basis of comparison, the effective permeabilities are referred to the specific permeability, k, of the considered porous medium, with the help of the relations: k1. = KI. k kQ = Kn k..........(2) K,. and Kr. are defined as the relative permeabilities to the liquid and to the gas phase respectively, and frequently expressed in per cent of specific permeability. It may be seen that Equations (1); which appear to be a direct generalization of Darcy's law, correspond to the assignment at any given time of a set of "local" permeabilities to each point of the porous medium, and represent in a differential form the two fluid flow system as a simple superposition of the individual single flow systems. The above interpretation implies that the effective or relative permeabilities are independent of pressure or rate of flow,

Jan 1, 1951

By L. A. Rapoport, W. J. Leas

As a preliminary, consicleration is given to the conventional definition of relative permeability and to the conditions governing the simultaneous flow of oil and gas through porous media. For the conditions of flow prevailing throughout most of a gas drive reservoir, the oil and gas can reasonably be supposed to be in capillary equilibrium with each other. Under these conditions, and these conditions only, the relative permeability to liquid can be expressed as a function of saturation. The relative permeability to liquid in that case is dependent upon the distribution of fluids which itself is shown to be related to the capillary pressure, and, in turn, to the saturation. As a consequence, relative permeability to liquid can be expressed in terms of the volume and surface area of a network of liquid channels bounded by the rock and the gas phase. While the volume of this network can be evaluated accurately, the surface area cannot. However, for any such volume, maximum and minimum values of the corresponding surface area can be calculated from capillary pressure data. It is then possible to establish for any saturation the limits within which the value of the relative permeability to liquid must lie. As a consequence of the theoretical development, the validity of an experimental method for measuring relative permeability to liquid which utilizes a stationary gas phase is demonstrated. In this method capillary barriers are cemented to the ends of the core sample to permit the maintenance of capillary equilibrium between the two phases. At the same time, this procedure eliminates undesirable secondary phenomena such as end effects, fissure effects, etc., the presence of which adversely affect the results of other laboratory methods. The results obtained by theoretical calculations, and experimentally, are discussed. In view of the overall precision that can presently be obtained in reservoir calculations, the agreement between the calculated and measured relative permeability to liquid data can be considered satisfactory. In conclusion, for reasons of economy and simplicity, the procedure of calculating limiting relative permeability to liquid curves from capillary pressure data is indicated for general engineering purposes. It is shown that the above procedure can easily be extended to the cases where connate water is present. Its use for reservoir studies is particularly recommended in conjunction with the method for measuring relative permeability to gas' which simultaneously yields the capillary pressure data necessary for the calculations. THEORETICAL Definition of Relative Permeabilities — Basic Equations for Heterogeneous Flow The equations by which the relative permeability concept is defined and upon which the formulation of all of the gas-oil flow problems rests at the present time are expressed as: V, = — Grad PL = — Grad PL ....(la) PL µL, k k KG VG = —K - Grad PG k- Grad Pc .... (lb) Mo where ,. and G refer to liquid and gas; V is the volumetric rate of flow per unit gross area. µ the viscosity, Grad P the potential gradient. and k the specific permeability of the porous medium.* (For horizontal flow, Grad P becomes the pressure gradient; otherwise, gravity must be included.) According to these expressions, each of the constituent phases is considered similar to a homogeneous system where the volumetric rate of flow is proportional to the pressure gradient, and for each of which the constants of proportionality, k, and kG, are termed effective permeabilities. by analogy to the specific permeability as defined by Darcy's law in its original form. In order to obtain a convenient basis of comparison, the effective permeabilities are referred to the specific permeability, k, of the considered porous medium, with the help of the relations: k1. = KI. k kQ = Kn k..........(2) K,. and Kr. are defined as the relative permeabilities to the liquid and to the gas phase respectively, and frequently expressed in per cent of specific permeability. It may be seen that Equations (1); which appear to be a direct generalization of Darcy's law, correspond to the assignment at any given time of a set of "local" permeabilities to each point of the porous medium, and represent in a differential form the two fluid flow system as a simple superposition of the individual single flow systems. The above interpretation implies that the effective or relative permeabilities are independent of pressure or rate of flow,

Jan 1, 1951

By W. L. Prehn, Adele Chambers, R. L. Slobod

The centrifuge has been found to be an extremely useful tool for determining capillary pressure curves and for establishing connate water and residual oil in small core plugs. The use of the centrifuge for determining the properties of small core plugs has been discussed in the literature,',' but practically no experimental evidence has been presented justifying the use of this method in preference to other methods (mainly disc method) now in use. Data have been accumulated and are now presented demonstrating the advantages of the centrifugal method, some of which are: (1) rapid establishment of equilibrium, (2) excellent precision yielding very reproducible results, (3) availability of high pressure differences between phases, (4) simple operational procedure, and (5) ability to establish connate water, residual oil, or to obtain complete capillary pressure curve in one day or less. A commercially available centrifuge capable of speeds up to 3,800 rpm, and a high speed attachment providing a maximum rate of rotation of 18,000 rpm were used in this work in conjunction with core holding tubes designed specifically for this application. In view of the outstanding advantages associated with the use of the centrifuge the conclusion has been drawn that this method should be used in place of the more tedious, slower, and less reliable disc method for determining capillary pressure curves and for establishing connate water and residual oil in small core plugs. INTRODUCTION The need for accurate values of connate water, residual oil, and capillary pressure curves in reservoir engineering has been recognized for many years, and the extent of the effort devoted toward solving these problems is reflected in the large number of papers3-" which have appeared in the literature during the past decade. Most of the methods discussed in the recent literature employ a porous disc as a semi-permeable membrane to separate two immiscible phases and make pos-ible the application of an explicit difference in pressure between two phases in the core. Thus, in the determination of the capillary pressure curve the wetting phase (water) is displaced by the non-wetting phase (air or oil). Several investigators1,2 have used centrifugal forces to develop pressure differences between phases. As a result of the first work' in this field the conclusion was reached that "the more rapid centrifugal method for measuring irreducible saturation may have equal value, (compared to use of discs) but more work is required to establish this point." This work was followed in 1945 by a more detailed study2 in which the concepts of this experimental work were more clearly enunciated. A method for calculating saturation for any given speed of rotation based on the observed volume of water displaced was developed and a wider application of the method was suggested. The absence of any subsequent pertinent literature on this subject is interpreted as indicating that no additional work has been completed to substantiate or deny the earlier claims and suggestions of promise contained in the original papers on this subject. One purpose of this report is to provide evidence designed to establish the practical value of centrifugal methods in determining core properties such as connate water and capillary pressure curves. It is also our purpose to suggest a broadening of the scope of this tool to include determinations of residual oil by gas or water drives. THEORY AND PRACTICE IN USE OF CENTRIFUGE Hassler and Brunner2 have clearly presented the basic concepts involved in the use of the centrifuge by relating the performance of a small core in a field of high acceleration to the

Jan 1, 1951

By R. L. Slobod, W. L. Prehn, Adele Chambers

The centrifuge has been found to be an extremely useful tool for determining capillary pressure curves and for establishing connate water and residual oil in small core plugs. The use of the centrifuge for determining the properties of small core plugs has been discussed in the literature,',' but practically no experimental evidence has been presented justifying the use of this method in preference to other methods (mainly disc method) now in use. Data have been accumulated and are now presented demonstrating the advantages of the centrifugal method, some of which are: (1) rapid establishment of equilibrium, (2) excellent precision yielding very reproducible results, (3) availability of high pressure differences between phases, (4) simple operational procedure, and (5) ability to establish connate water, residual oil, or to obtain complete capillary pressure curve in one day or less. A commercially available centrifuge capable of speeds up to 3,800 rpm, and a high speed attachment providing a maximum rate of rotation of 18,000 rpm were used in this work in conjunction with core holding tubes designed specifically for this application. In view of the outstanding advantages associated with the use of the centrifuge the conclusion has been drawn that this method should be used in place of the more tedious, slower, and less reliable disc method for determining capillary pressure curves and for establishing connate water and residual oil in small core plugs. INTRODUCTION The need for accurate values of connate water, residual oil, and capillary pressure curves in reservoir engineering has been recognized for many years, and the extent of the effort devoted toward solving these problems is reflected in the large number of papers3-" which have appeared in the literature during the past decade. Most of the methods discussed in the recent literature employ a porous disc as a semi-permeable membrane to separate two immiscible phases and make pos-ible the application of an explicit difference in pressure between two phases in the core. Thus, in the determination of the capillary pressure curve the wetting phase (water) is displaced by the non-wetting phase (air or oil). Several investigators1,2 have used centrifugal forces to develop pressure differences between phases. As a result of the first work' in this field the conclusion was reached that "the more rapid centrifugal method for measuring irreducible saturation may have equal value, (compared to use of discs) but more work is required to establish this point." This work was followed in 1945 by a more detailed study2 in which the concepts of this experimental work were more clearly enunciated. A method for calculating saturation for any given speed of rotation based on the observed volume of water displaced was developed and a wider application of the method was suggested. The absence of any subsequent pertinent literature on this subject is interpreted as indicating that no additional work has been completed to substantiate or deny the earlier claims and suggestions of promise contained in the original papers on this subject. One purpose of this report is to provide evidence designed to establish the practical value of centrifugal methods in determining core properties such as connate water and capillary pressure curves. It is also our purpose to suggest a broadening of the scope of this tool to include determinations of residual oil by gas or water drives. THEORY AND PRACTICE IN USE OF CENTRIFUGE Hassler and Brunner2 have clearly presented the basic concepts involved in the use of the centrifuge by relating the performance of a small core in a field of high acceleration to the

Jan 1, 1951

By H. Landsberg

Biological as well as geological research has made very successful use of the qualities that the physicists have detected in radioactive substances. Outstanding examples for the vast new fields opened in this part of the border-land between the disciplines of geology and physics are the "radio thermal geology" [July, 1909, see 1 of "References" at end of paper] and all that is connected with the use of the radioactive disintegration clock for the age-determination of rocks and minerals [2]. In structural geology, not unlike to recent bi-ological uses of radioactive material, their "tracer" properties were helpful. Changes in Radon concentra-tion in soil-air, especially accumulations, led to hidden crevices and fault-zones. High contents of Radon in spring-water gave clues as to the types of rocks they had flowed through [3, 4). One specific application of the small admixtures of radioactive material, however, has only lately found some atten-tion and that is their use in linking beds of sedi-mentary strata otherwise only poorly identified be-cause of the lack of fossils or other characteristic properties. To be useful for this purpose, two con-ditions have to be fulfilled: (1) The amount of radioactive material per unit-weight of rock in a given horizon should be uniform over a large area; (2) this same amount should change fairly rapidly in the vertical succession of layers.

Jan 1, 1940

By Lachlan Gilchrist

MEASUREMENTS of resistivity by methods involving the use of two current electrodes and two potential electrodes in general collinear with the current electrodes have been made extensively in geophysical investigations. In the method developed by Wenner and made use of by Gish and Rooney, and later in a modified form by Lee, the distance between the current electrodes is divided into three equal parts by the potential electrodes. In one of the methods developed by Schlumberger prospecting methods and by Koenigsberger, one current electrode is placed at considerable distance from the other and potential measurements are made in the immediate neighborhood of one of the current electrodes. The method is described as the single current electrode method, and the effect of the distant current electrode is considered negligible or a correction is made for the effect in the calculation of the resistivity. Usually the correction that is introduced is based on the calculated effect for measurements made in a homogeneous conducting material. The useful application of these methods in prospecting for minerals, of course, is in regions where nonhomogeneous conditions exist. In many of these conditions it is very doubtful whether the effect of the distant current electrode may be neglected, except for measurements in the immediate neighborhood of the "single" current electrode, and corrections based on homogeneity of the medium will necessarily be inadequate. In order to obtain a degree of symmetry that would preclude the necessity for corrections for the distant electrode and that would simplify interpretation, it appeared desirable to use a central current electrode and a set of distant end current electrodes symmetrically placed about the central electrode as shown in Fig. 1 and to provide by means of auxiliary resistances that the currents passing into the earth at the distant end electrodes should be equal. Circumstances did not permit the operation of this plan in complete detail but a degree of symmetry was obtained by using a central current electrode and two distant collinear end current electrodes and by taking measurements along a line passing through

Jan 1, 1931

By John Cogan

Field observations were made of rock phenomena in shale, dolomite, and fractured quartzite in the Burgin Mine, Eureka, Utah. Draft closure rates were measured with extensometers and convergence gages. In addition the effects of hydraulic props upon the retardation of closure was also monitored. Drift closure rates were found to be constant and to vary between 0.32 x 10-8 min-1 for dolomite and 23.8 x 10-8 min-1 for soft shale. The installation of props set at constant load served to retard the closure rates. General results show closure to occur at a constant rate for all cases, to be non-uniform around the drift openings, and to be increasingly retarded toward a zero rate by increases in prop load.

Jan 1, 1979

By C. R. Hocott

THE viscosity of the oil in the reservoir is one of the properties that influence its movement through the sand to producing wells. Measurements of viscosity, therefore, are pertinent to problems associated with well behavior and with the estimation of recoveries, and afford an indirect means for partial evaluation of various methods of controlling reservoir behavior. The effect of dissolved gases on the viscosity of crude oil has been determined,1,2 but no data have been published on the viscosity of repre-sentative samples of reservoir oils. This paper describes a simple instrument that has been used to determine the viscosities of a number of subsurface oil samples at the temperatures and pressures existing in the reservoirs, and presents the results of the determinations for typical fields.

Jan 1, 1940

By G. Blight

As part of an investigation of possible water-saving measures at Anglo American Platinum's Mogalakwena Mine in Limpopo, South Africa, a study was made of conditions on the wet beaches of two adjacent tailings dams, each serving a separate plant on the mine. For one of the dams, a special catamaran was designed and constructed to enable the full length of wet beaches to be accessed and sampled immediately after a layer of tailings had been deposited. For the other dam, the wet beach was accessed using conveyor belting and scaffold planks. The length of the beaches was 400 m on the first dam, and 200 m on the second, and each was sampled at 50 m intervals. The parameters reported in this paper, for both beaches, are: > Water content profiles along each beach from the surface to as deep as 2.5 m, at times ranging from 12 hours to 6 weeks from the end of deposition > Particle size distributions at the surface, down the full length of the beaches > Measurements of feed relative density, tonnage and volume, decant and drain flow volumes, as well as rainfall and evaporation for both dams. The surface water contents shortly after deposition have been used to establish the relative density of the settled, decanted tailings and its variation down the beach. This data, combined with the decant and drainage flows, is used to establish the calculated and actual water recoveries from both dams.

Jan 1, 2012