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By B. B. Wood, M. J. Rzasa, E. W. Hough

An apparatus for the determination of fluid-fluid interfacial tension by the pendant drop method has been constructed. The apparatus is refined beyond those previously described in that the samples are introduced into an evacuated windowed cell without contacting air or mercury. Interfacial tension data are reported for the water-methane system between 74 and 280°F and 15 and 15,000 psi. The variation of wettability of the stainless-steel dropper tip with pressure and temperature was observed incidentally to the measurements. INTRODUCTION The most refined previous apparatus --for the determination of fluid-fluid interfacial tension at reservoir conditions was built by Hauser and Michaels.' These authors used the pendant drop method, previously investigated by Andreas, Hauser, and Tucker.' Recently, Fordham3 has made the pendant drop method an absolute one by numerical integration of the differential equation of drop shape. It is necessary to know the difference in density of the two fluids and the acceleration due to gravity in order to evaluate the interfacial tension from measurements of drop dimensions. Contact angle is not involved in the measurements by this method. Some precise tests of the method have been made at atmospheric pressure and 77°F by Douglas," who found agreement with established values to within about 0.1 per cent for water and air, cyclohexane and air, benzene and air, and benzene and water. No values of interfacial tension from the recent pendant drop apparatusJ have been published by Hauser and Michaels. However, values for the water-benzene and water-decane systems are given in Michaels' thesis5 or Dressures from 15 .to 10,000 psi and temperatures from 73 to 268ºF. Some determinations on gas-oil and gas-water systems in the range of 15 to 4,000 psi and 78 to 178°F have been made by Hozott,' by the drop-volume method. The capillary rise method has been used to investigate the interfacial tension in gas-oil systems at 88°F to several thousand psi by Swartz.7 Other determinations in gas-oil systems at pressures under 1,000 psia have been made by Jones: and Beecher and Parkhurst.9 The scarcity of data for pressures above 5.000 psi is apparent. APPARATUS An assembly drawing of the working section of the interfacial tenqion apparatus is given in Fig. 2. 'The endanant drop (A) is housed in a pressure chamber having glass windows (B). An agitator (6) is provided. The metal parts of the apparatus coming into contact with the sample are made of AISI: Type 316 steel. Drain grooves are provided around the whdows so that the sample in contact with the O-rings is not returned to the working section when the pressure is reduced. A schematic arrangement of the apparatus is given in Fig. 3. The working section containing the pendant drop (A) is filled by samples from bombs (B) with the aid of the vacuum system (C). The O-ring sealed pistons (D) used to separate the sample from the hydraulic fluid are shown together with the pressure production and measurement system (E). A front view of the apparatus is shown in Fig. 1. Most of the hydraulic system is at the top of the panel. The pump and displacement piston are at the lower right. The Variacs for the air bath heaters. the camera. and the vacuum gauge are a1so visible on the panel. The working section together with a window closure and a drop-forming tip closure are shown in Fig. 9. The carbon arc light source with filter is visible in the upper part of the picture. Two sides of the air bath with the impeller and a part of the convection shield can also be seen. The assembled air bath is shown in Fig. 10.

Jan 1, 1951

By E. W. Hough, B. B. Wood, M. J. Rzasa

An apparatus for the determination of fluid-fluid interfacial tension by the pendant drop method has been constructed. The apparatus is refined beyond those previously described in that the samples are introduced into an evacuated windowed cell without contacting air or mercury. Interfacial tension data are reported for the water-methane system between 74 and 280°F and 15 and 15,000 psi. The variation of wettability of the stainless-steel dropper tip with pressure and temperature was observed incidentally to the measurements. INTRODUCTION The most refined previous apparatus --for the determination of fluid-fluid interfacial tension at reservoir conditions was built by Hauser and Michaels.' These authors used the pendant drop method, previously investigated by Andreas, Hauser, and Tucker.' Recently, Fordham3 has made the pendant drop method an absolute one by numerical integration of the differential equation of drop shape. It is necessary to know the difference in density of the two fluids and the acceleration due to gravity in order to evaluate the interfacial tension from measurements of drop dimensions. Contact angle is not involved in the measurements by this method. Some precise tests of the method have been made at atmospheric pressure and 77°F by Douglas," who found agreement with established values to within about 0.1 per cent for water and air, cyclohexane and air, benzene and air, and benzene and water. No values of interfacial tension from the recent pendant drop apparatusJ have been published by Hauser and Michaels. However, values for the water-benzene and water-decane systems are given in Michaels' thesis5 or Dressures from 15 .to 10,000 psi and temperatures from 73 to 268ºF. Some determinations on gas-oil and gas-water systems in the range of 15 to 4,000 psi and 78 to 178°F have been made by Hozott,' by the drop-volume method. The capillary rise method has been used to investigate the interfacial tension in gas-oil systems at 88°F to several thousand psi by Swartz.7 Other determinations in gas-oil systems at pressures under 1,000 psia have been made by Jones: and Beecher and Parkhurst.9 The scarcity of data for pressures above 5.000 psi is apparent. APPARATUS An assembly drawing of the working section of the interfacial tenqion apparatus is given in Fig. 2. 'The endanant drop (A) is housed in a pressure chamber having glass windows (B). An agitator (6) is provided. The metal parts of the apparatus coming into contact with the sample are made of AISI: Type 316 steel. Drain grooves are provided around the whdows so that the sample in contact with the O-rings is not returned to the working section when the pressure is reduced. A schematic arrangement of the apparatus is given in Fig. 3. The working section containing the pendant drop (A) is filled by samples from bombs (B) with the aid of the vacuum system (C). The O-ring sealed pistons (D) used to separate the sample from the hydraulic fluid are shown together with the pressure production and measurement system (E). A front view of the apparatus is shown in Fig. 1. Most of the hydraulic system is at the top of the panel. The pump and displacement piston are at the lower right. The Variacs for the air bath heaters. the camera. and the vacuum gauge are a1so visible on the panel. The working section together with a window closure and a drop-forming tip closure are shown in Fig. 9. The carbon arc light source with filter is visible in the upper part of the picture. Two sides of the air bath with the impeller and a part of the convection shield can also be seen. The assembled air bath is shown in Fig. 10.

Jan 1, 1951

By C. K. Eilerts, J. D. Ham

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 limestone. 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. l 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. 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.

By B. H. Caudle, W. J. Bernard

Factors which influence the success or failure of a waterflood can seldom be determined in the laboratory. For this reason pilot waterfloods are initiated in a repreventative portion of the oil reservoir in question. For a pilot flood to predict quantitatively the recovery to be expected in a field-wide waterflood operation, the pilot area must behave as though it were confined (surrounded by similar areas). In this study, laboratory fluid-flow models were used to determine the simplest pilot pattern, for particular conditions of mobility ratio and initial gas saturation, that would behave as though it were confined. Pilot patterns studied ranged in complexity from a single inverted five-spot to a grouping of nine regular five-spots. Only the innermost producing well in each pattern was studied. Model results showed that the optimum number of wells in the pattern depends upon the oil-water mobility ratio and the expected oil-bank size. Unfavorable mobility ratios will, in general, require more wells in the pilot pattern than will favorable mobility ratios. Pilot patterns in reservoirs which contain a dispersed, flowable, free gas saturation will require fewer wells than for the under-saturated case. The single inverted five-spot pattern was found to be unsatisfactory for predicting behavior of fully developed waterfloods. In particular, it is possible that, in reservoirs which contain a flowable, dispersed gas phase, the oil bank will never be observed at the producers due to the large amounts of free gas which continue to be produced with the oil. INTRODUCTION One method which has been used to predict the performance of a waterflood is the pilot flood. The pilot waterflood is a flood which involves only a small cluster of the reservoir wells and is located in a small, representative portion of the reservoir. The object is that oil produced from the pilot can, in some way, be related to the oil recovery to be expected from a field-wide expansion of the waterflood. However, these field pilot waterfloods have often been unreliable in the prediction of oil recovery in a fully developed waterflood. This unreliability has also been demonstrated in several laboratory studies of pilot floods. Some of the investigators have shown that there are situations in which the pilot flood oil production is far too optimistic with respect to the oil recovery in the fully de- veloped flood. Others4-G have shown that the pilot results can also be pessimistic, especially if the pilot waterflood is initiated in an oil reservoir which has been depleted by primary recovery and is at very low pressure. The major reason for this unreliability of pilot water-floods is the migration of fluids into or out of the pilot area. By the well-known method of images, if straight lines can be drawn to represent vertical planes of symmetry in a porous medium which contains pressure sources and sinks (injectors and producers), then these lines are invariant streamlines, or lines across which there is no potential gradient, and therefore no flow. In an actual reservoir, these lines of symmetry can never be established exactly because of reservoir inhomogeneities and irregular reservoir boundaries. However, if the reservoir is relatively large and contains wells in repetitive patterns, these lines of symmetry are commonly assumed to exist for the pattern units sufficiently far removed from the reservoir boundary. Lines of symmetry for the five-spot injection pattern are shown in Fig. 1. Each five-spot unit in this figure can be considered confined with respect to flow across its boundary. In pilot floods this is not the case. The lines of symmetry for the pilot patterns investigated in this study are shown in Fig. 2. It is obvious that the fluid within these pilots is not confined and is therefore able to migrate into or out of the pilot area. Intuitively, one can see that, if more wells are added to the pilot, the innermost unit tends to behave more and more like the confined pattern. However, there is a practical limit to the number of wells which should be placed in the pilot. This limit is usually determined by economic factors. It was the purpose of this study to use laboratory fluid-flow models to determine which of the previously mentioned pilot patterns will force the innermost producing well to behave as it would in a fully developed waterflood. Since fluid migration is influenced by initial saturation conditions and the mobility ratio, these factors were included in the study. The ultimate objective of this study was to develop data which would allow the operator to choose a pilot pattern and operating conditions that will yield a production history which can be applied directly as an estimate of the performance of each production well of the fully developed waterflood. BASIS FOR THE STUDY The basic problem of field pilot floods is the migration of the reservoir fluids into or out of the pilot area. This problem has been the subject of previously reported model studies on pilot floods. These studies have been concerned mainly with the development of arbitrary "correction factors" to be applied to the simple, unconfined pilot systems such as the single five-spot. The correction factors were intended to adjust the production history of the un-

By R. J. Sandrea, S. M. Farouq Ali

The results of an experimental and theoretical study of the effects of rectilinear impermeable barriers and highly permeable channels on the sweep efficiency and conductivity of a five-spot network are presented. The study was carried out using Hele-Shaw, and conductive sheet analogs for both. normal and inverted flood patterns. A functional relationship was developed which provides quantitative prediction of the above parameters; i.e., sweep efficiency and conductivity, for the nonhomogeneous system. To evaluate this, it is necessary only to measure the interference modulus of the obstacle using a simple expression. The results indicate that impermeable barriers, with an interference modulus greater than zero, always cause a decrease in the conductivity and the sweep efficiency of the pattern. On the other hand, permeability channels do not have a significant effect on these parameters, unless they are located along the streamlines. The study also discusses a method of formulating the difference equations pertaining to the two-dimensional Laplacian in a system containing rectilinear barriers. In addition, a technique is described for tracing the progress of a free surface, using marked particles, in a stream containing discontinuities SuCh as those occurring at the extremities of barriers. The above computational scheme was used in a digital computer program to simulate results of the Hele-Shaw analog. The computed values of sweep efficiency mere in good agreement with the experimental values. INTRODUCTION At the present time waterflooding remains the most widely used technique for the secondary recovery of oil. Among the numerous factors that affect the performance of a waterflood, the areal sweep efficiency constitutes one of the most critical parameters. It is a function only of the geometric distribution of the wells for a homogeneous medium and unit mobility ratio. Geological considerations, however, such as the presence of sealing faults or solution channels in the rock matrix, would generally exert an adverse effect on the areal sweep efficiency of a waterflood network. Surprisingly little information is presently available on the quantitative implications of such permeability interferences. It was the object of this investigation to consider the presence of rectilinear, impermeable and highly permeable interferences in an otherwise homogeneous five-spot pattern, and to analyze their effects on the resulting sweep efficiency and pattern conductivity. The experimental phase of the study was conducted using two different models: the Hele-Shaw flow cell and the field plotter. For experimental convenience, the geometric boundaries of the five-spot were assumed to constitute streamlines even in the case where the interference was asymmetrically placed with respect to a repeated five-spot pattern. A second object of the study was to develop a computational scheme for numerically calculating the pressure distribution in a five-spot flow pattern containing rectilinear, impermeable barriers, and to use this distribution to compute the sweep efficiency. EXPERIMENTAL PROCEDURE HELE-SHAW ANALOG The Hele-Shaw analog was used both as a visual model and for determining the sweep efficiency for systems involving impermeable barriers. The physical limitations of this model as a means of experimentally studying the motion of a fluid in porous medium have been adequately discussed elsewhere.2,7 Likewise, it can be easily verified that the analogy remains valid when a portion of the region between the plates contains an obstacle of the same thickness as the distance between the plates. The model used in this study was composed of

By O. L. Culberson, J. J. McKetta

Experimental and smoothed data are presented for the solubility of methane in water for temperatures of 77, 100, 160. 220. 280, and 340°F at prejsures to 10.000 psia. The minimum solubility phenomenon exists within this temperature range to pressures of 10.000 psia. INTRODUCTION The study of hydrocarhon-water systems has been extended to the determination of the solubility of methane in water at pressures to 10.000 psia. The experimental apparatus, and the technique. are the same as that previously reported.' - In the determination of the solubility of methane in water, only two phases were present at temperatures between 100 and 340°F. these being the vapor phase and the water-rich. liquid phase. The determinations involved the agitation of methane and water in an equilibrium cell. withdrawal of a sample from the liquid phase, and the analysis of the sample. The experimental value; determined in this manner are pre9ented in Table I and in Fig. 1. Since experimental and analytical techniques have improved since the initial experiments with this equipment, it was decided to repeat the 77°F isotherm determinations.' Fig. I shows that the individual results for this isotherm are much

Jan 1, 1951

By J. J. McKetta, O. L. Culberson

Experimental and smoothed data are presented for the solubility of methane in water for temperatures of 77, 100, 160. 220. 280, and 340°F at prejsures to 10.000 psia. The minimum solubility phenomenon exists within this temperature range to pressures of 10.000 psia. INTRODUCTION The study of hydrocarhon-water systems has been extended to the determination of the solubility of methane in water at pressures to 10.000 psia. The experimental apparatus, and the technique. are the same as that previously reported.' - In the determination of the solubility of methane in water, only two phases were present at temperatures between 100 and 340°F. these being the vapor phase and the water-rich. liquid phase. The determinations involved the agitation of methane and water in an equilibrium cell. withdrawal of a sample from the liquid phase, and the analysis of the sample. The experimental value; determined in this manner are pre9ented in Table I and in Fig. 1. Since experimental and analytical techniques have improved since the initial experiments with this equipment, it was decided to repeat the 77°F isotherm determinations.' Fig. I shows that the individual results for this isotherm are much

Jan 1, 1951

By O. L. Culberson, J. J. McKetta

INTRODUCTION The equilibrium constants for methane and for water, and for ethane and water have been calculated from experimental data for the two binary systems.2,3,11,12 These constants are for the two-phase systems for the temperature range of 100" to 340°F and the pressure range of 200 to 10,000 psia. The constants for ethane are greater than those for methane. Equilibrium constants for a natural gas from a natural gas-water system6 are about the same as those for methane. Equilibrium constants for water in all three systems are very nearly the same over the greater part of the range of temperatures and pressures studied. In ideal solutions, the vapor-liquid equilibrium constants for a component should be the same in all such solutions at a given temperature and pressure.5 Few solutions are ideal, and consequently the use of generalized constants often leads to error in situations where they do not actually apply. In decidedly non-ideal systems, it is desirable to have equilibrium constant data for the specific system. Vaporization equilibrium constants may be calculated either by thermodynamic methods or from experimental vapor-liquid equilibrium data. In the thermodynamic calculation. the equilibrium constant K may be shown to be" K = fP,/fl'..........(1) where fPi is the fugacity of the pure component i at the given temperature and at the vapor pressure of the pure component, and fp is the fugacity of pure i in the gaseous state at the temperature and total pressure of the system. At best the thermodynamic calculation results in a K applicable to ideal solutions. Equilibrium constants calculated from Equation (1) have been found to have only limited agreement with experimental values, even though the solutions for which they were calculated approached ideality."'" If the more volatile component is at a temperature above its critical, the accuracy of the equilibrium constant for the component is made more doubtful by the use of the vapor pressure term under such conditions. In order to make the thermodynamic calculation on a component above its critical temperature, one must resort to one of the empirical methods of extrapolation of the vapor pressure to conditions above its critical point.13 Application of the thermodynamic equilibrium constant then to the methane-water or the ethane-water systems would be risky since the systems are non-ideal, and the methane and ethane are above their critical in most petroleum operations. ETHANE-WATER SYSTEM In the temperature range of from 100° to 340°F and for pressures up to 10,000 psia, the vapor-liquid equilibrium data 'References given at end of paper. Manuscript received in the office of the Petroleum Branch March 16, 1951.

Jan 1, 1951

By J. J. McKetta, O. L. Culberson

INTRODUCTION The equilibrium constants for methane and for water, and for ethane and water have been calculated from experimental data for the two binary systems.2,3,11,12 These constants are for the two-phase systems for the temperature range of 100" to 340°F and the pressure range of 200 to 10,000 psia. The constants for ethane are greater than those for methane. Equilibrium constants for a natural gas from a natural gas-water system6 are about the same as those for methane. Equilibrium constants for water in all three systems are very nearly the same over the greater part of the range of temperatures and pressures studied. In ideal solutions, the vapor-liquid equilibrium constants for a component should be the same in all such solutions at a given temperature and pressure.5 Few solutions are ideal, and consequently the use of generalized constants often leads to error in situations where they do not actually apply. In decidedly non-ideal systems, it is desirable to have equilibrium constant data for the specific system. Vaporization equilibrium constants may be calculated either by thermodynamic methods or from experimental vapor-liquid equilibrium data. In the thermodynamic calculation. the equilibrium constant K may be shown to be" K = fP,/fl'..........(1) where fPi is the fugacity of the pure component i at the given temperature and at the vapor pressure of the pure component, and fp is the fugacity of pure i in the gaseous state at the temperature and total pressure of the system. At best the thermodynamic calculation results in a K applicable to ideal solutions. Equilibrium constants calculated from Equation (1) have been found to have only limited agreement with experimental values, even though the solutions for which they were calculated approached ideality."'" If the more volatile component is at a temperature above its critical, the accuracy of the equilibrium constant for the component is made more doubtful by the use of the vapor pressure term under such conditions. In order to make the thermodynamic calculation on a component above its critical temperature, one must resort to one of the empirical methods of extrapolation of the vapor pressure to conditions above its critical point.13 Application of the thermodynamic equilibrium constant then to the methane-water or the ethane-water systems would be risky since the systems are non-ideal, and the methane and ethane are above their critical in most petroleum operations. ETHANE-WATER SYSTEM In the temperature range of from 100° to 340°F and for pressures up to 10,000 psia, the vapor-liquid equilibrium data 'References given at end of paper. Manuscript received in the office of the Petroleum Branch March 16, 1951.

Jan 1, 1951

By B. J. Dotson, P. N. McCreery, R. L. Slobod, James W. Spurlock

A core sample porosity-check program is described. A number of laboratories participated in the investigation. which comprised measuring the porosities of ten selected natural and synthetic core samples. Each laboratory employed its own method (or methods) of measurement. These included Boyle's Law, water-saturation. and organic liquid-saturation methods. Brief descriptions of each method employed are given. In general, the measured values of porosity were in reasonably good agreement. The average deviation of porosity from the mean or average values for the group of samples was ±0.5 porosity per cent. The results of these measurements are compiled and presented in graphical form. INTRODUCTION The total hulk volume of a porous sample is derived from the sum of two volumes, the void or pore volume and the solid* or grain volume. The porosity fraction of the sample ia defined as the ratio of the void volume to the bulk volume. Multiplication of this ratio by 100 converts it to per cent porosity. Distinction is made here between total porosity and effective porosity. The former includes all void space, both interconnected and isolated, while the latter includes only those voids which are interconnected. This investigation deals only with the effective porosity.* Numerous cases had been noticed in which there appeared to be appreciable discrepancies in the results of porosity determinations on core samples. Differences of as much as 10 to 15 porosity per cent had been reported from different sources

Jan 1, 1951

By P. N. McCreery, R. L. Slobod, B. J. Dotson, James W. Spurlock

A core sample porosity-check program is described. A number of laboratories participated in the investigation. which comprised measuring the porosities of ten selected natural and synthetic core samples. Each laboratory employed its own method (or methods) of measurement. These included Boyle's Law, water-saturation. and organic liquid-saturation methods. Brief descriptions of each method employed are given. In general, the measured values of porosity were in reasonably good agreement. The average deviation of porosity from the mean or average values for the group of samples was ±0.5 porosity per cent. The results of these measurements are compiled and presented in graphical form. INTRODUCTION The total hulk volume of a porous sample is derived from the sum of two volumes, the void or pore volume and the solid* or grain volume. The porosity fraction of the sample ia defined as the ratio of the void volume to the bulk volume. Multiplication of this ratio by 100 converts it to per cent porosity. Distinction is made here between total porosity and effective porosity. The former includes all void space, both interconnected and isolated, while the latter includes only those voids which are interconnected. This investigation deals only with the effective porosity.* Numerous cases had been noticed in which there appeared to be appreciable discrepancies in the results of porosity determinations on core samples. Differences of as much as 10 to 15 porosity per cent had been reported from different sources

Jan 1, 1951

By John S. Bell, J. M. Shepherd

pressure difference of 280 psi measured initially on opposite sides of the major fault in the Hawkins Field led to pressure determinations in the Woodbine sand throughout the East Texas basin. Considering the large area, there is unusually good correlation between pressure losses and points of major withdrawals, these losses indicating that the basin pressure has been materially reduced by withdrawals, primarily from the East Texas Field and secondarily from the old fault-line fields of Limestone and Navarro counties, with the pressure loss varying inversely with the log of the distance from these two main areas of basin withdrawals to the measurement points. Apparently faults located throughout the basin serve as local blocks to continuous pressure gradients. INTRODUCTION The pressure anomalies found in the Hawkins Field, Wood County, Texas,' shortly after discovery have led to an area-wide investigation of the pressure distribution within the Woodbine sand of the East Texas basin. These pressures were obtained by drill-stem tests made for that sole purpose while drilling wildcat wells to deeper horizons. The Woodbine sand of Gulf Cretaceous Age is or has been productive of oil and gas in 42 different fields, with the 28 oil fields currently active having produced 118,000,000 bbl of oil during 1949. With one exception, producing energy for all Woodbine reservoirs has been from water drive provided predominantly by expansion of the tremendous volume of water contained in the Woodbine sand. This producing mechanism was recognized at an early date and was described mathematically by

Jan 1, 1951

By John S. Bell, J. M. Shepherd

pressure difference of 280 psi measured initially on opposite sides of the major fault in the Hawkins Field led to pressure determinations in the Woodbine sand throughout the East Texas basin. Considering the large area, there is unusually good correlation between pressure losses and points of major withdrawals, these losses indicating that the basin pressure has been materially reduced by withdrawals, primarily from the East Texas Field and secondarily from the old fault-line fields of Limestone and Navarro counties, with the pressure loss varying inversely with the log of the distance from these two main areas of basin withdrawals to the measurement points. Apparently faults located throughout the basin serve as local blocks to continuous pressure gradients. INTRODUCTION The pressure anomalies found in the Hawkins Field, Wood County, Texas,' shortly after discovery have led to an area-wide investigation of the pressure distribution within the Woodbine sand of the East Texas basin. These pressures were obtained by drill-stem tests made for that sole purpose while drilling wildcat wells to deeper horizons. The Woodbine sand of Gulf Cretaceous Age is or has been productive of oil and gas in 42 different fields, with the 28 oil fields currently active having produced 118,000,000 bbl of oil during 1949. With one exception, producing energy for all Woodbine reservoirs has been from water drive provided predominantly by expansion of the tremendous volume of water contained in the Woodbine sand. This producing mechanism was recognized at an early date and was described mathematically by

Jan 1, 1951

By J. N. Breston, R. V. Hughes

Conclusions drawn by previous research workers with reSPect to the relation between Pressure gradients and/or velocity and oil recovery obtained by laboratory water flood tests have been in disagreement probably due to variable procedures and unnatural conditions and materials. The Bradford Laboratory of the Pennsylvania Grade Crude Oil Association as part of its secondary recovery research program has conducted nineteen water floods on two long cores of widely differing characteristics in an attempt to clarify this relationship and make it an aid in predicting flooding pressures in the field. Unlike previous research procedures the present experiments were conducted with the aim of duplicating field conditions as closely as possible by using long unextracted consolidated cores, a live crude, and natural brines for both flooding and, connate water content. Also, the pressure gradients and flooding velocities were representative of field conditions where similar sands were being flooded. Eleven floods on one core and eight floods on the other core showed increased recoveries and lower residual oil saturation with increased flood pressure gradients and flood velocities. A marked decrease in recovery was obtained from both cores at very low flood velocities. This pressure versus recovery relationship is shown to hold up to the point of water breakthrough and also up to the 100 and 1 produced water to oil ratio point. INTRODUCTION The possibility of water flooding oil sands was suggested by Carl1 of the Pennsylvania Geological Survey in 1880. It is not known when the practice was tried intentionally for the first time, but its beneficial effects were noted in the annual production rate of the Bradford field as early as 1907. The practice was illegal in Pennsylvania until 1921. Early water floods in the Bradford field usually consisted of shooting or splitting the casing secretly to permit subsurface waters to enter the producing sands under hydrostatic head. As it was noted that the benefits of water flooding seemed to be proportional to the quantity of water dumped into the well many also began to utilize surface sources after the practice became legal. It was probably during the middle 20's before many producers realized that the pressurehead of the water upon the producing sand determined the rate and quantity of water that would enter the sand. Hence, rate and quantity of production appeared to be a direct function of input pressures. By 1927 a few producers had ventured the installation of pressure pumps in order to increase water-input rates and production through the combination of hydrostatic and hydraulic pressures. The adoption of pressure flooding and the "five-spot" drilling pattern in the Bradford field were essentially simultaneous. Water-input pressures in 1930 seldom exceeded 300 p.s.i. at the well head or 1100 p.s.i. at the sand face. Since that time, water-flood producers in the Bradford-Allegany fields have gone to higher and higher pressure until today 600 p.s.i. at the well heads is called a low pressure flood. Many high pressure floods now operate at 1300-1400 p.s.i. at the well head. The limiting and advisable pressure at the sand face has been pronounced as that pressure just under what is required to lift the overburden or to cause formation parting: According to this rule any water flood operation utilizing well-head pressures nearly equal in pounds per sq. in. to 1.1 times the average depth in feet to the top of the producing sand would be considered as a high-pressure flood. Despite the higher pressure trends in the Bradford-Allegany field operations and the results of early laboratory water flooding research, the desirability and benefits of high input pressures are still questioned by many operators, particularly in midwestern water flood operations. The present paper recounts a series of 19 laboratory water floods using two long, consolidated cores of widely differing characteristics saturated with live crude and flooded with oil field brines in an effort to simulate field conditions under • various pressure gradients and flooding velocities. For both cores, higher recoveries and lower residual oil saturations were obtained at higher pressure gradients and flood velocities. This relationship is shown to hold up to the water breakthrough point and also up to the 100 to 1 produced water to oil ratio point.

Jan 1, 1949

By R. V. Hughes, J. N. Breston

Conclusions drawn by previous research workers with reSPect to the relation between Pressure gradients and/or velocity and oil recovery obtained by laboratory water flood tests have been in disagreement probably due to variable procedures and unnatural conditions and materials. The Bradford Laboratory of the Pennsylvania Grade Crude Oil Association as part of its secondary recovery research program has conducted nineteen water floods on two long cores of widely differing characteristics in an attempt to clarify this relationship and make it an aid in predicting flooding pressures in the field. Unlike previous research procedures the present experiments were conducted with the aim of duplicating field conditions as closely as possible by using long unextracted consolidated cores, a live crude, and natural brines for both flooding and, connate water content. Also, the pressure gradients and flooding velocities were representative of field conditions where similar sands were being flooded. Eleven floods on one core and eight floods on the other core showed increased recoveries and lower residual oil saturation with increased flood pressure gradients and flood velocities. A marked decrease in recovery was obtained from both cores at very low flood velocities. This pressure versus recovery relationship is shown to hold up to the point of water breakthrough and also up to the 100 and 1 produced water to oil ratio point. INTRODUCTION The possibility of water flooding oil sands was suggested by Carl1 of the Pennsylvania Geological Survey in 1880. It is not known when the practice was tried intentionally for the first time, but its beneficial effects were noted in the annual production rate of the Bradford field as early as 1907. The practice was illegal in Pennsylvania until 1921. Early water floods in the Bradford field usually consisted of shooting or splitting the casing secretly to permit subsurface waters to enter the producing sands under hydrostatic head. As it was noted that the benefits of water flooding seemed to be proportional to the quantity of water dumped into the well many also began to utilize surface sources after the practice became legal. It was probably during the middle 20's before many producers realized that the pressurehead of the water upon the producing sand determined the rate and quantity of water that would enter the sand. Hence, rate and quantity of production appeared to be a direct function of input pressures. By 1927 a few producers had ventured the installation of pressure pumps in order to increase water-input rates and production through the combination of hydrostatic and hydraulic pressures. The adoption of pressure flooding and the "five-spot" drilling pattern in the Bradford field were essentially simultaneous. Water-input pressures in 1930 seldom exceeded 300 p.s.i. at the well head or 1100 p.s.i. at the sand face. Since that time, water-flood producers in the Bradford-Allegany fields have gone to higher and higher pressure until today 600 p.s.i. at the well heads is called a low pressure flood. Many high pressure floods now operate at 1300-1400 p.s.i. at the well head. The limiting and advisable pressure at the sand face has been pronounced as that pressure just under what is required to lift the overburden or to cause formation parting: According to this rule any water flood operation utilizing well-head pressures nearly equal in pounds per sq. in. to 1.1 times the average depth in feet to the top of the producing sand would be considered as a high-pressure flood. Despite the higher pressure trends in the Bradford-Allegany field operations and the results of early laboratory water flooding research, the desirability and benefits of high input pressures are still questioned by many operators, particularly in midwestern water flood operations. The present paper recounts a series of 19 laboratory water floods using two long, consolidated cores of widely differing characteristics saturated with live crude and flooded with oil field brines in an effort to simulate field conditions under • various pressure gradients and flooding velocities. For both cores, higher recoveries and lower residual oil saturations were obtained at higher pressure gradients and flood velocities. This relationship is shown to hold up to the water breakthrough point and also up to the 100 to 1 produced water to oil ratio point.

Jan 1, 1949

By A. C. England, William F. Haney, Paul B. Crawford, Bobby L. Landrum

The creation of unsymmetrical vertical or horizontal fractures in a producing well will result in a unique distortion of the normal shut-in pressures existing at the four surrounding wells. An electrical model study has been made to show how the shut-in pressures at the wells surrounding the fractured producing well may he used to estimate the size and orientation of vertical or horizontal fractures. The pressure differences at the four surrounding wells are recorded during production from the fractured well. The resulting pressure dato are matched from a table of several hundred possible fracture combinations. The table refers to the figure showing the effective size and orientation of the commercially created fracture. INTRODUCTION The creation of commercial fractures about oil and gas wells has led to considerable speculation as to the size and shape of the fractures. It is important that the size and shape be known in certain instances, especially when pressure maintenance programs are to be initiated. It was shown that if knowledge of a vertical fracture could be found that such information may be utilized in planning a waterflooding or gas cycling program and that in some cases the fractures might be utilized very effectively.' Other work showed that it may be desirable to create "pancake" fractures in certain reservoirs but that they should exist in a desirable range.' If the fractures are too large, they should be plugged prior to initiating a pressure maintenance program. If an irregular shaped "pancake" fracture is created, it is desirable to know the orientation of this fracture because similar but unreported studies have shown that "pancake" fractures may or may not substantially affect the sweep efficiencies and performance of the flooding or cycling program. Consequently, it may be desirable in some instances to estimate the effective size and orientation of the fracture. ANALOG An electrical model was used in making this study. The electrical model consisted of a circular reservoir approximately 8 in. in diameter, 1 in. thick and was filled with a dilute salt solution. A copper band formed the periphery of the reservoir. A vertical fracture was simulated by a copper strip soldered to the wire well located in the center of the reservoir. Vertical copper strips of various lengths and orientation were soldered to the wire well to represent vertical fractures in the reservoir. In studies reported here on vertical fractures it was arbitrarily assumed that two fractures originated at the well and extended out into the reservoir. An electrical potential was imposed between the wire well and the periphery of the tank. Plots of the iso-potentials are shown in Figs. 1 through 9. This model provides the steady-state isopotentials existing in a uniform, homogeneous circular reservoir having a vertically fractured well at its center. The permeability of the fracture is much greater than the permeability of the matrix proper. The effects of gravity are neglected. In preparing Tables 1 and 2, four symmetrically located unfractured wells were assumed to exist around

Jan 1, 1956

By C. S. Matthews, H. C. Lefkovits

The purposes of this study are (a) to determine the accuracy of a previously proposed method for calclrlating average reservoir pressure and (b) to find a method for estimating the shape of the drainage area of each well in a bounded reservoir. Both numerical and experimental methods are used to determine the pressure distribution and the location of drainage bounrlaries in idealized reservoirs at steady state. A number of photographs are included which show flowlines and drainage areas in reservoir models of various shapes. Results from these studies are then compared with those from the previously proposed method for calculating average reservoir pressure.' It is concluded that the previously proposed method is sufficiently accurate for most reservoir engineering purposes. In addition, some simple methods are given for estimation of .shapes of drainage boundaries. INTRODUCTION A method for the determination of the average Pressure in a bounded reservoir was previously developed by Matthews, Brons, and Hazebroek,1 and presented at the Petroleum Branch Fall Meeting in 1953.† In aP- plying this method, the reservoir was first divided into drainage volumes; second, the average pressure in each drainage volume was calculated; and third, these drainage volume pressures were averaged volumetrically to give the average pressure in the reservoir. It was shown that each well's individual drainage volume, at steady state, is proportional to the well's production rate; however. the question of how to estimate accurately the shape of these drainage volumes could not be answered. Furthermore, in calculating the average pressure for each drainage area, the actual drainage areas, which are in general quite asymmetric in shape, are replaced with one of the symmetric prototypes given in T.P. 3876. A question may then be raised as to how accurately the symmetrical figures depict the pressure behavior of the actual unsymmetrical drainage areas. The study reported on in the present paper was made in an attempt to shed light on the above questions. METHODS It was shown in T.P. 3876 that after a period of steady rate of withdrawal the rate of pressure decline becomes constant at every point in a bounded reservoir containing a single-phase fluid whose compressibility is small and constant and whose viscosity is con-

Jan 1, 1956

By E. V. Watts

The D-7 zone of the Ventura Avenue field is of special interest because the initial reservoir pressure at 92.00 ft nearly equaled the pressure exerted by the overburden. While the phenomenon has been observed elsewhere in the world, there is no record of a previous case in California. Such high pressures have been attributed to sealing of the reservoir, followed either by emergence of the beds or by compaction of the sediments in various ways. Oil in the D-7 zone is undersaturated. At pressures above the bubble point, oil is recovered by the slight expansibility of the reservoir framework and its liquid contents. More than 40 pct as much oil probably will be recovered by this mechanism as will be recovered by internal gas drive after pressures pass below the bubble point. Operations are handicapped by sand and pipe troubles. Introduction The Ventura Avenue field has been under development since 1915. It has long been considered a "high-pressure" field, but interest was heightened by the extreme conditions encountered in the recent development of the so-called D-7 zone. The original reservoir pressure in this pool is estimated to have been 8300 psi at a depth of 9000 ft below sea level, or 9200± ft below the surface. A fluid pressure approaching that exerted by the overlying sediments has been encountered in other parts of the world, but never before in California to the degree observed in the D-7 pool. With few exceptions, the original pressure in California fields is about equivalent to the static head of water below the water table in the outcrop. Structure The Ventura anticline is a prominent feature of the Ventura basin, being traceable on the surface about 17 miles.' The Ventura Avenue field is at the apex of the anticline. It is about one mile wide and five miles long, the major axis lying in an east-west direction. The productive limits cover an area of about 2300 acres. The entire anticline has been severely folded and faulted. The productive portions in particular are broken up by three major thrust faults having a general east-west strike. The resultant four fault blocks are termed the A, B, C, and D blocks, respectively. Certain electric-log intervals are assigned numbers. Fig I is a diagrammatic north-south section of the field near the crest, looking west, and shows three of the four fault blocks. To the west, the upper fault divides into two branches, which define the B block. Wells penetrating a fault may duplicate over 1000 ft of formation. However, the greater fault movement is the strike shift, which is believed to exceed 2500 ft both between the A and C blocks and between the C and D blocks. The location of water is irregular and unpredictable. A few intermediate waters exist, while some strata have more than 2000 ft of productive closure.

Jan 1, 1948

By E. V. Watts

The D-7 zone of the Ventura Avenue field is of special interest because the initial reservoir pressure at 92.00 ft nearly equaled the pressure exerted by the overburden. While the phenomenon has been observed elsewhere in the world, there is no record of a previous case in California. Such high pressures have been attributed to sealing of the reservoir, followed either by emergence of the beds or by compaction of the sediments in various ways. Oil in the D-7 zone is undersaturated. At pressures above the bubble point, oil is recovered by the slight expansibility of the reservoir framework and its liquid contents. More than 40 pct as much oil probably will be recovered by this mechanism as will be recovered by internal gas drive after pressures pass below the bubble point. Operations are handicapped by sand and pipe troubles. Introduction The Ventura Avenue field has been under development since 1915. It has long been considered a "high-pressure" field, but interest was heightened by the extreme conditions encountered in the recent development of the so-called D-7 zone. The original reservoir pressure in this pool is estimated to have been 8300 psi at a depth of 9000 ft below sea level, or 9200± ft below the surface. A fluid pressure approaching that exerted by the overlying sediments has been encountered in other parts of the world, but never before in California to the degree observed in the D-7 pool. With few exceptions, the original pressure in California fields is about equivalent to the static head of water below the water table in the outcrop. Structure The Ventura anticline is a prominent feature of the Ventura basin, being traceable on the surface about 17 miles.' The Ventura Avenue field is at the apex of the anticline. It is about one mile wide and five miles long, the major axis lying in an east-west direction. The productive limits cover an area of about 2300 acres. The entire anticline has been severely folded and faulted. The productive portions in particular are broken up by three major thrust faults having a general east-west strike. The resultant four fault blocks are termed the A, B, C, and D blocks, respectively. Certain electric-log intervals are assigned numbers. Fig I is a diagrammatic north-south section of the field near the crest, looking west, and shows three of the four fault blocks. To the west, the upper fault divides into two branches, which define the B block. Wells penetrating a fault may duplicate over 1000 ft of formation. However, the greater fault movement is the strike shift, which is believed to exceed 2500 ft both between the A and C blocks and between the C and D blocks. The location of water is irregular and unpredictable. A few intermediate waters exist, while some strata have more than 2000 ft of productive closure.

Jan 1, 1948

By R. A. Morse, W. O. Keller

The properties of limestone reservoir rocks such as the distribution and degree of continuity of the pore systems, and the relative volumes and permeabilities of the systems making up the complex cause large variations between performance of individual limestone reservoirs and their susceptibility to secondary recovery methods. The effects of these factors on the mechanism of fluid flow cannot be adequately evaluated with presently developed concepts, laboratory data, and geological information. The observance and interpretation of the performance of individual limestone reservoirs provides, at present, the most adequate approach for evaluating the integrated effects upon performance of the many. now immeasurable variations in the properties of limestone reservoirs. INTRODUCTION The development and application of techniques for increasing the efficiency of oil recovery from natural reservoirs is a problem of primary importance to the industry. During the past several years, a great deal of effort has been expended by the technical personnel of the industry toward the improvement of present known methods of oil recovery. and evaluating the factors which control the susceptibility of particular reservoir types to economic application of secondary recovery methods. Providing adequate and accurate laboratory data on the properties of the reservoir rock and its contained fluids. together with good production statistics, are available, methods have been evolved for estimating with reasonable accuracy the performance of an oil reservoir under either continued natural depletion or conditions imposed by introducing additional displacing fluid into the reservoir from an extraneous source through the injection of gas and/or water. The susceptibility of limestone reservoirs to secondary recovery by gas injection is very much dependent upon gas-oil relative permeability relationships for the reservoir in question. In a rock formation in which the porosity is of the intergranular type such as is found in sand stones and some non-fractured dolomites, a representative sample of the pore structure can be obtained in a small core plug. In this type of reservoir, it has been shown that relative permeability data obtained from laboratory experiments can be Properly applied to evaluate the flow relationships actually observed during the depletion of a reservoir. In addition, a good idea of the fraction of the reservoir which will be swept by the injected gas may be obtained from the spacing pattern used and the permeability profile of cored wells. From these data, it has been demonstrated that reliable estimates of performance and recoveries under gas injection operations can be made for reservoirs in which the Porosity is of the intergranular type. Limestone reservoirs on the other hand often present much more complex problems. One reason that the performance of limestone reservoirs is so variable is that there may be, in reality. two or more pore systems, the integrated performance of which will depend upon the physical properties of each system and their inter-relationship. For instance, in a limestone reservoir, the main pore structure, as far as void spaces for storage of hydrocarbons is concerned, may be represented by the intergranular openings of the rock. Usually in limes and dolomites, the intergranular pore openings are very small and the matrix permeabilities extremely low. Often, as in the case of Many dolomite and oolitic lime reservoirs, this is the only pore system, and performance is observed to be very similar to that of a sand stone of similar permeability. However, in the great majority of' the limestone reservoirs, there is present, in addition to the intergranular pore system, a complementary system of openings caused by fracturing or solution.',' The openings in the latter system are usually many times more permeable than the intergranular pore system due to their much larger size, and may contribute almost all the fluid carrying capacity of the formation, even though their volume may be a very small part of the total pore space in the reservoir. Obviously, the performance of such a complex under either primary or secondary control will deend upon the distribution and degree of continuity of both systems, the relative volumes and permeabilities of the

Jan 1, 1949