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By G. Thodos, E. M. Phillips

A reduced density correlation for the gaseous and liquid regions of ethane has been developed from all the experimental PVT data available in the literature for this substance. Saturated vapor and liquid densities reported for methane, propane and n-butane were utilized to establish the rectilinear-diameter line for ethane. This line was then used with the saturated-vapor data for ethane to produce the saturated envelope for this substance. Most of the saturated liquid data reported for ethane were found to be inconsistent with the saturated-liquid curve resulting from this study. The correlation covers the regions 0.65 < TR <6.0 and 0 < PR < 15. For regions for which no experimental data have been reported, the isobars of the correlation were extended by the use of the theorem of corresponding states. This correlation is presented both on rectilinear and log-log coordinates. INTRODUCTION At the present time, there is considerable interest in the exact PVT behavior of pure hydrocarbons. Matschke and Thodos12 recently have developed a comprehensive compilation of experimental vapor and liquid density data for methane. Similar studies have been conducted for other pure substances.4, 7 In the present study the density data available in the literature for gaseous and liquid ethane have been critically reviewed and utilized to develop a reduced density correlation for this substance. SATURATED LIQUID AND VAPOR DENSITIES The rectilinear-diameter rule proposed by Cailletet and Mathias5 states that the sum of the saturated liquid and vapor densities of a pure substance is a linear function of temperature which passes through the critical point. This law, although empirical, has been well established by continued verification since its conception in 1886. This rule has been applied to the saturated density data of methane,6 propane 17 and n-butane8 to produce the straight lines presented in Fig. 1 which pass through the critical point TR = 1.00, Pr = 2.00. The rectilinear-diameter relationship for ethane was established from the lines for the other substances in Fig. 1 by plotting the quantity p~, + PR against zc for different reduced temperatures. A critical analysis of the saturated vapor and liquid densities reported for ethane by Kuenen,10 Maass and McIntosh,11 and Sage, Webster and Lacey18 revealed that the values of PR1 + pr resulting from these studies were inconsistent with the rectilinear-diameter line obtained from the reliable density data of the other substances, as shown in Fig. 1. In the analysis of these data, reduced quantities were calculated using the critical con-

By J. H. Moran, E. E. Finklea

The pressure build-up technique is a recognized method of determining permeability from conventional drillstem tests. In this paper an effort is made to extend such techniques to the interpretation of data obtained from the wireline formation tester. Such a study is necessary because of the differences, for this case, in the magnitude of the flow parameters (rate of flow, amount of recovered fluids) and in the flow geometry (flow through a perforation vs flow across the face of the wellbore, etc.) involved in the solution of the equations of flow for compressible fluids. The perforation is replaced by a spherical hole, and the effect of the borehole is neglected, so that the flow can be considered to be radial in a spherical co-ordinate system. Arguments are presented to justify this idealization. Assuming single-phase flow, general relations between pressure and flow rate are developed for a homogeneous medium. The study is then extended to permeable beds of finite thickness. It is shown that the early stages of pressure build-up tend towards spherical flow, while the later stages tend towards cylindrical flow. The thinner the bed, the more quickly flow approaches the cylindrical model. The prevalence of thin beds in practical work makes this analysis quite important. Cases involving permeability anisotropy are treated. INTRODUCTION From wireline formation tester operation, two types of data are obtained: (1) the nature and amount of recovered fluids, and (2) the pressure history recorded during the test. A number of papers have been written dealing with the interpretation of formation production on the basis of the recovered fluids.&apos;.&apos; In general, the methods described have been quite accurate for both high- and low-permeability formations. The present paper will deal with an analysis of the pressures observed. An analysis of the pressure build-up curves obtained in hard-rock country has already been attempted on the basis of the formula proposed by Hor-ner. Although this approach has met with success in many instances, some questions have been raised as to its validity. It is the aim of the present study to place the analysis of pressure build-up in the formation tester on a firmer basis, from which more detailed methods of interpretation can evolve. Because of the great differences between the operation of the wireline formation tester and the conventional drillstem test, modifications are necessary in the interpretation. The major difference relates to the flow geometry. Once the flow geometry has been established other features such as multiphase flow, skin effect, afterflow, etc., well described in the literature, can be introduced. It will be assumed that the mechanical operation of the formation tester is already known to the reader.6 t will suffice here merely to state that the tester provides the means for taking a relatively small sample of the fluid immediately adjacent to the borehole, and for recording the subsequent pressure response. In comparison with conventional drillstem tests, the time required for a satisfactory pressure build-up response is much shorter, because of the relatively small quantity of fluid withdrawn by the wireline tester. This feature is highly desirable in the case of low-permeability formations. For an analysis of the pressure response within the formation, three simple flow geometries are considered— linear, cylindrical and spherical. The spherical and cylindrical flow geometries are most pertinent to the formation tester; therefore, they will receive the major emphasis. Since the configuration of the borehole and the perforation made by the tester complicate the flow geometry, it is necessary to allow for them in the drawdown response. However, because of the volume of formations contributing to the pressure-response, the details of the perforation shape are unimportant in the build-up period. Since relatively small amounts of fluid are withdrawn from the formation, in contrast to a conventional drill-stem test, a study of the "depth of investigation" and the significance of drawdown as well as build-up data will be included. Because the "depth of investigation" will be shown to be rather large, the effect on the build-up curves of the finite thickness of the permeable bed is considered. It is this consideration that leads to the importance of cylindrical flow geometry. Also included is a discussion of permeability anisotropy and its effect on the interpretation of the tester results. The pressure curves recorded by the formation tester will follow two general patterns, depending upon whether the formation is of high or low permeability. Fig. I (a and b) schematically illustrates these two responses. In Fig. 1(a), the high pressure recorded during fill-up of the tool is essentially the pressure differential across the choke in the system. In Fig. l(b), the flow rate is

By R. E. Gilchrist, R. R. Harvey, M. R. Dean

A simple and rapid three-component analysis procedure has been developed for use in fluid-flow studies. The method is based on refractive index measurements, combined with refractive dispersion measured between the Ha and H wave lengths. The procedure requires. calibration curves for the three-fluid system. The only restriction on the fluids employed is that only one be an aromatzc or olefinic compound. Individual sample measurements require only a few minutes. Composition results within the limits of accuracy required for fluid-flow analog studies are obtained. INTRODUCTION The simultaneous analysis of three-component mixtures is a problem often encountered in fluid-flow analog systems. In petroleum production research, the problem is usually encountered in experiments on the displacement of fluid from a porous medium. In the case of immiscible displacement, simple volumetric measurements of the produced fluids are usually sufficient, the analog fluids often being the actual reservoir fluids themselves — oil, water and gas. However, modern secondary recovery of petroleum sometimes involves production under miscible conditions, in which the oil is displaced by liquefied petroleum gas which, in turn, is displaced by dry gas. Since this type of displacement is done under conditions of pressure and temperature that are not easily reproduced in the laboratory, studies are often performed with analog fluids at essentially atmospheric pressure. Since the number of samples taken during one of these experiments is usually quite large, the time required for analysis becomes an important factor. In the past, the difficulty of conventional analysis has been avoided by the addition of various tracers to one or more of the components, or by the use of a tracer fluid as one of the components. With these techniques, a relatively large amount of analytical time is still required. Moreover, in the case of added tracers, the tracer material may migrate in part to one of the other fluids, may be adsorbed on the solid surfaces of the model, or may introduce side effects not characteristic of the prototype fluid. The substitution of a tracer fluid for one of the components can severely limit the choice of analog fluids. Optical refractometry provides a rapid and economical method of analysis of two-fluid systems or of monitoring small changes in composition of an essentially one-component system. Refractometric methods are capable of high degrees of accuracy, require only very small samples and can easily be adapted to automatic methods. They are not generally applicable, however, where three or more fluids are present over wide ranges of concentration. The method of three-component analysis described here has three essential characteristics. 1. It is based on refractometric measurements and thus preserves all of these desirable properties. 2. It does not make any stringent demands on the choice of fluids that can be analyzed. 3. It is capable of accuracy sufficient for fluid-flow analog studies. THEORETICAL The difference in the refractive index of a substance at two different wave lengths of light is known as its dispersivity. When the difference is taken between the specific refractions at the two wave lengths, the quantity is referred to as the specific dispersivity. Specific refraction was defined empirically by Gladstone and Dale1 as r = n-1/d....[1] where n is the index of refraction and d is the density. The definition is given more correctly by the expression r =n2-1/n2+1 1/d..........(2) 1References given at end of paper. MICIFTV OF PETROLEUM ENGINEER JOURNAL.

By H. D. Outmans

In steady vertical flow, the interface of an immiscible liquid-liquid displacement is horizontal for any flow rate below the critical. In nonvertical flow, however, the shape of the interface in the steady state does depend on the flow rate, and the purpose of this paper is to calculate the unsteady interfaces during the transition of one steady state of flow to another. A knowledge of these transient interfaces is of considerable importance in reservoir engineering where the calculation of breakthrough recovery depends on the instant the interface reaches the producing wells and on the shape of the interface at that time. Although the emphasis is put on transient interlaces, which eventually approach stable equilibrium, it is shown that if the displacement exceeds a critical rate no equilibrium is possible. The interface is then unstable and viscous fingers are formed during the displacement. The critical rate and the shape of the transient and equilibrium interfaces are affected by the effective interfacial tension; but since this effective interfacial tension appears in the calculations only in combination with the inverse square of the thickness of the medium, its effect in the reservoir would appear to be negligible compared to its significance in model experiments. INTRODUCTION Stability criteria and the early growth of interfacial disturbances in a plane parallel to the boundaries of a dipping formation in which oil is displaced by an incompressible fluid were described in a previous paper.l This type of instability is significant in thin reservoirs. However, if the reservoir has appreciable thickness, then interfacial stability in vertical planes, normal to the upper and lower boundaries, also becomes important (the displacement is supposed to be parallel to these vertical planes). The difference between the two stability problems is that, in the first case, the intersections of the interface with planes parallel to the boundaries are normal to the direction of the displacement; in the second case, the intersections, this time with vertical planes, are not normal to the displacement. Instead, they are tilted at an angle which depends on the displacement rate. The tilt of steady interfaces was calculated by Dietz2 who also determined the critical rate of displacement for stability in the vertical plane by assuming that this rate would coincide with an interfacial tilt equal to the dip of the formation. The critical rate thus calculated is the same as has been found for thin reservoirs (see Eq. 1.1 of Ref. 1 and of the present paper). Dietz&apos;s calculation of the stable tilt was verified by laboratory experiments and the agreement was found to be fairly good.3 It is doubtful, however, that stable tilts actually exist in the reservoir because a change in production rate is not followed by an instantaneous adjustment of the interface to the new rate but, rather, by a transition period during which the interface changes from one equilibrium tilt to the other. The principal objective of this paper has been to describe these transient interfaces without putting any restrictions on the flow conditions or the shape of the interface, as had been done previously. The second objective was to compute the critical velocity, taking into account capillary effects, and the third was to evaluate, at least qualitatively, the shape of the front at rates above the critical, again without making the simplifying assumptions introduced by previous investigators.2,3 In the following sections two examples are given of the calculation of interfacial motion. The first describes this motion for an initially horizontal interface in a dipping layer, and the second for a vertical interface in a horizontal layer. The mathematical formulation of the problem is nonlinear in the boundary conditions, and this prohibits its solution in closed form. Instead, the solution is obtained in the form of higher-order approximations. 1 Before proceeding to a description of the mathematical model, however, we define two quantities

By T. D. Mueller

Many investigators have used the response of the "dimensionless aquifer" to a unit pressure drop or a unit fluid-withdrawal volume to calculate the performance of an aquifer in supplying water influx to an oil reservoir. In the past, these response functions have been calculated with the aid of the Laplace transform. With the advent of ultra highspeed digital computers, it becomes practical to solve for the response functions with finite-difference techniques. The computer method also permits extension of the dimensionless-aquifer concept to include the nonhomogeneous aquifer wherein the permeability and other properties vary as a function of the space co-ordinates. This paper gives results of calculating the response functions for a series of nonhomogeneous aquifers. Response functions are presented for both linear and radial aquifers whose thickness, permeability-viscosity ratio and porosity-compressibility vary. These functions are new and should prove useful to the petroleum engineer in analyzing the behavior of nonbomogeneous aquifers. Results are presented in the form of charts that can be easily used by the field engineer. INTRODUCTION Aquifers which surround many oil and gas reservoirs have the ability to supply water influx to such reservoirs as oil and gas are withdrawn. This water influx, called natural water drive, provides one of the most effective driving mechanisms for the production of oil and gas. In producing a reservoir, therefore, it behooves one to make the maximum use of natural water drive. To achieve the maximum use, the reservoir engineer must be able to predict the performance of an aquifer under a variety of production schemes that may be proposed for the reservoir. Unfortunately, the physical properties which dictate aquifer behavior often are known only within limits. Seldom do wells penetrate the porous strata of the aquifer. Even when they do, quantitative information regarding porosity, permeability and water compressibility is seldom available. It is known, however, that the water efflux from most aquifer systems is governed by a single, relatively simple, linear, partial differential equation. Also, the general physical location of the aquifer boundaries often are known. A technique originall proposed by Hurst1 and van Everdingen and Hurst2 has been found useful in analyzing reservoirs in this situation. The idea was later expanded by van Everdingen, Timmerman and McMahan3 to include the mathematical technique of least-squares fitting. This latter method will be referred to as the VTM method. The basic assumptions of the VTM method include the following. 1. The location of the physical boundaries of the aquifer are known. 2. The flow conditions at these physical bound-daries are also known. 3. The aquifer is homogeneous; e.g., thickness, permeability, water compressibility and porosity are constant throughout. In the VTM method, a material balance is made on the fluids entering and leaving the reservoir. In the balance equations, the water-influx term is represented as the product of the water influx from an arbitrarily-selected, dimensionless aquifer system times an unknown conversion number. This balance can be formed as many times as there are data points in the history of the reservoir. Each time, the conversion number can be evaluated. If the reservoir engineer has picked the correct dimensionless aquifer to represent the real aquifer, the conversion number remains constant for all balances that have been made over the history period. If such a situation occurs, the reservoir engineer can then predict the performance of the reservoir for any type of production scheme by using the function associated with that particular dimensionless system and the derived conversion number. These functions will be referred to as the response function of the aquifer. If the aquifer is nonhomogeneous (e.g., if the porosity, permeability, thickness, porosity, or

By D. R. Parrish, K. W. Beaver, H. W. Wood, R. W. Rausch

A pilot test of forward combustion in the Shannon pool, Salt Creek field, Wyo., is described. The Shannon sand, 950-ft deep, contains a heavy (25" API), viscous (76 cp) oil. Natural reservoir energy is limited. Primary production, intermittent since 1889, recovered only about 2 per cent of the oil in place. The field is operated by Pan American Petroleum Corp. for the Midwest Oil Corp., the owner. The original pilot was a 1.32-acre five-spot. The expanded pilot has eight producing wells surrounding a roughly triangular area of about five acres with the injection well near the center. A control or comparison well was also recompleted in another part of the field. Operation of the pilot has been little different front an ordinary gas drive. Little special equipment was found to be absolutely necessary. Except for some use of a temperature-resistant cement, all wells were conventionally completed. In spite of poor oxygen consumption, the over-all performance of the pilot has been good. Total oil recovery to June 1, 1961, was 73,971 bbl. The wells of the original pilot alone had produced about 24,000 bbl, equivalent to 50 per cent of the oil in place, when fire breakthrough at the first well occurred. These wells have now produced oil equivalent to more than 74 per cent of the oil in place in the original pilot area and production is continuing. It appears that ultimate recovery will approach theoretical maximums before the wells must be abandoned. Performance of the pilot has been encouraging, and expansion to a fieldwide combustion operation is being investigated. INTRODUCTION The results of both laboratory investigations and field tests of underground combustion have been reported previously.&apos; However, most of the field tests were primarily experimental. More information and experience are needed before forward-combustion operations can be engineered with confidence. The purpose of this paper is to present the results of a successful pilot test of forward combustion. These re- sults should increase confidence in forward combustion as a practical method for commercial oil recovery. HISTORY OF THE SHANNON POOL The Shannon pool is located on the north end of the Salt Creek field in Natrona County, Wyo. It is approximately 50-miles north of the city of Casper. The Shannon pool&apos;s3 discovery well was completed in 1889, making this one of the oldest oil fields in the Rocky Mountain region. Three more wells were drilled in 1890. First production was hauled in wooden barrels by horse and wagon to the railroad in Casper. In 1894 a small refinery, the first in Wyoming, was built in Casper to process the Shannon crude. In the following years the field changed hands several times. It appears that each new owner did some development drilling as several wells were completed in each of the years 1895, 1902, 1905 and 1912, with negligible development in the intervening years. Forty-eight wells were drilled in this period, but many were later abandoned. Discovery of the more prolific Salt Creek field proper ultimately forced suspension of operations at the Shannon pool. After 1915 there was only sporadic production, mostly to supply cheap boiler fuel to drilling rigs in the Salt Creek field. But even this was discontinued in 1931. Since then the pool had been dormant until the recent operations, which are the subject of this paper. The Shannon pool is now owned by the Midwest Oil Corp. Field operations are conducted for Midwest by Pan American Petroleum Corp. THE RESERVOIR Fig. 1 is a map showing subsurface contours of the Shannon pool. The reservoir is on a nose of the Salt Creek anticline dipping to the north at about 500 ft/mile. The trap is provided by a shallow fault on the updip side of the productive area. The downdip limits are bounded by water, but this water has not provided an effective source of reservoir energy. The Shannon sand outcrops at many places in the immediate vicinity, providing good surface indications of the Salt Creek anticline. At the Shannon pool the sand has been lowered by faulting and is overlain by about 900 ft of shale and other sands. The Shannon sand consists of two members. The upper, a water sand, is about 40-ft thick and is separated from the lower member by several feet of sandy shale. The oil pay occurs in the lower mem-

By H. J. Ramey

As fluids move through a wellbore, there is transfer of heat between fluids and the earth due to the diflerence between fluid and geothermal temperatures. This type of heat transmission is involved in drilling and in all producing operations. In certain cases, quantitative knowledge of wellbore heat transmission is very important. This paper presents an approximate solution to the wellbore heat-transmission problem involved in injection of hot or cold fluids. The solution permits estimation of the temperature of fluids, tubing and casing as a function of depth and time. The result is expressed in simple algebraic form suitable for slide-rule calculation. The solution assumes that heat transfer in the wellbore is steady-state, while heat transfer to the earth will be unsteady radial conduction. Allowance is made for heat resistances in the wellbore. The method used may be applied to derivation of other heat problems such as flow through multiple strings in a wellbore. Comparisons of computed and field results are presented to establish the usefulness of the solution. INTRODUCTION During the past few years, considerable interest has been generated in hot-fluid-injection oil-recovery methods. These methods depend upon application of heat to a reservoir by means of a heat-transfer medium heated at the surface. Clearly, heat losses between the surface and the injection interval could be extremely important to this process. Not quite so obvious is the fact that every injection and production operation is accompanied by transmission of heal between wellbore fluids and the earth. Previously, the interpretation of temperature logs&apos;,&apos; has been the main purpose of wellbore heat studies. The only papers dealing specifically with long-time injection operations are those of Moss and White3 and Lesem, et al.&apos; The purpose of the present study is to investigate wellbore heat transmission to provide engineering methods useful in both production and injection operations, and basic techniques useful in all wellbore heat-transmission problems. The approach is similar to that of Moss and White:&apos; DEVELOPMENT The transient heat-transmission problem under consideration is as follows. Let us consider the injection of a fluid down the tubing in a well which is cased to the top of the injection interval. Assuming fluid is injected at known rates and surface temperatures, determine the temperature of the injected fluid as a function of depth anti time. Consideration of the heat transferred from the injected fluid to the formation leads to the following equations. For liquid, Eqs. 1, 1A and 2 are developed in the Appendix. These equations were developed under the assumption that physical and thermal properties of the earth and wellbore fluids do not vary with temperature, that heat will transfer radially in the earth and that heat transmission in the wellbore is rapid compared to heat flow in the formation and. thus, can be represented by steady-state solutions. Special cases of this development have been presented by Nowakl and Moss and White.3 Both references are recommended for excellent background material. Nowak&apos; presents very useful information concerning the effect of a shut-in period on subsequent temperatures. Since one purpose of this paper is to present methods which may be used to derive approximate solutions for heat-transmission problems associated to those specifically considered here, a brief discussion of associated heat problems is also presented in the Appendix. Analysis of the derivation presented in the Appendix will indicate that many terms can be re-defined to modify the solution for application to other problems. Before Eqs. 1, 1A and 2 can be used, it is necessary to consider the significance of the over-all heat-transfer coefficient U and the time function f(t). Thorough discussions of the concept of the over-all heat-transfer coefficient may be found in many references on heat transmission. See McAdams5 or Jakob," for example. Briefly, the over-all coefficient U considers the net- resistance to heat flow offered by fluid inside the tubing, the tubing wall, fluids or solids in the annulus, and the casing wall. The effect of radiant heat transfer from the tubing to the casing and resistance to heat flow caused by scale or wax on the tubing or casing may also be included in the over-all coefficient. According to McAdams, on page 136 of Ref. 5>

By O. R. Wagner, R. O. Leach, H. W. Wood, C. F. Harpke

PAN AMERICAN PETROLEUM CORP.TULSA, OKLA. CASPER, WYO A field test has been made in which additional oil recovery was obtained from a previously-waterflooded "oil-wet" sandstone reservoir. This recovery improvement was accomplished by adjusting the reservoir wettability through chemical treatment of the flood water. The test was made in the Muddy sand of the West Harrisburg Unit, Neb. The chemical used, sodium hydroxide, was injected as a slug of dilute caustic solution through a water-injection well. The natural wettability of the reservoir and the chemical requirements for reversing wettability were determined in the laboratory from contact-angle studies using field water and oil samples. Laboratory flood tests with a synthetic system had shown that reversing the wettability of an oil-wet consolidated core would lead to improved oil recovery. The field performance indicates that the mechanism by which increased oil retovery is obtained in the field is the same as that observed in the lahoratory. Laboratory studies indicate that higher ultimate recoveries and decreascd water-injection requirements result when the adjusting agent is added early in the life of the flood. However, a previously waterflooded area was intentiorzally chosen for the field test so that unambiguous conclusions could be made about the effects of chemical injection on wettability and the extent of oil-recovery improvernent afforded by wettability reversal. Forces existing at the fluid-solid and fluid-fluid interfaces in a porous medium have an important effect on oil recovery during a water flood. Modifying these interfacial forces in the reservoir to improve oil recovery has been the object of much research. Several papers&apos; &apos; have discussed the use of surfactants to lower the water-oil interfacial tension. This paper describes work concerned with improving oil recovery by modifying the forces at the fluid-solid interfaces— that is, by changing the preferential wettability. An earlier paper: presented evidence to show that some reservoir systems could be changed from preferentially oil-wet to preferentially water-wet by the action of simple chemicals added to the water to increase waterflood oil recovery. The process was attractive for further study because it used only inexpensive chemicals and because it called for a gross "wettability reversal" rather than for a precise adjustment. The present paper is an extension of the earlier work. Laboratory flow tests were made using treated water and oil in a consolidated core to determine the amount of additional oil recovery and the producing performance which might be expected from reversing the wettability of an oil-wet reservoir during a flood. A contact-anglc study using water and oil from the Muddy "J" sand of the Harrisburg field, Banner County, Neb., indicated the reservoir to be preferentially oil-wet and susceptible to wettability reversal through chemical injection. Based on these studies, a field trial of wettability-reversal water flooding was initiated. in the Harrisburg field. The primary purpose of the trial was to determine if wettability-reversal flooding would improve oil recovery in an actual field situation. The field trial was also an important test of the laboratory tecnique used to determine the effect on oil recovery of certain wettability manipulation, as well as a test of the contract-angle method of determining reservoir wetra-bility. The paper is presented in two parts. The first part covers the laboratory experiments leading up to the field trial, and the second part covers the field trial. PART I—LABORATORY STUDY The laboratory experiments consisted of displacement tests using an idealized fluid system and of a contact-angle study with crude and water from the Muddy "J" sand of the West Harrisburg Unit, Banner County, Neb. The displacement tests were designed to determine the effects of a particular wettability manipulation, oil-wet to water-wet, on oil displacement in a water flood. The contact-angle measurements were made to determine the natural wettability of the reservoir and to determine if beneficial wetting changes could be brought about by a chemical addition to the flood water. PROCEDURE DISPLACEMENT TESTS The displacement tests were perfornled in a consolidated sandstone core using a refined oil and water. The wetting properties of this system could

By C. W. Carpenter, P. T. Bail, J. E. Bobek

This paper presents the results of model studies made to demonstrate the validity of applying the "basic" waterflooding scaling relationships of Rapoport1 to water-wet reservoirs composed of communicating strata of different permeability. Results demonstrate that these relationships can be validly applied, and also show the combined effect of variables on recovery. This demonstration was needed to confirm that the sizable effects of communicating strata on waterflood behavior, observed in model studies, were actually representative of field behavior. INTRODUCTION Rapoport1 Collins2 and others have presented scaling laws for modeling water-oil displacements. The validity of these laws has been experimentally demonstrated for homogeneous systems only. Recently, however, several investigators have presented the results of multilayer model studies made to determine the effects of viscous, capillary and gravitational forces on oil recovery in systems composed of communicating layers of different permeability. Dyes and Braun,3 using miscible displacements to simulate water flooding, showed that vertical communication adversely affects recovery at unfavorable viscosity ratios in the absence of capillarity. Ogandzhanyants and Egorova, 4 Gaucher and Lindley,5 and Richardson and Perkins6 modeled water-oil displacements in layered systems using immiscible fluids with capillary forces present. These investigators found more efficient behavior than in the miscible system of Dyes and Braun. However, since the scaling laws had not been verified for heterogeneous systems prior to or during these tests, it was necessary to assume that the results were representative of field behavior. This report presents the results of model studies made at Jersey Production Research Co. to find out if the waterflooding scaling relationships are valid when applied to water-oil displacements in heterogeneous reservoirs with vertical communication. Data obtained in the study show the combined effects of viscous, capillary and gravitational forces on oil-recovery behavior. The studies were performed in strongly water-wet systems where strong imbibition forces were present. For systems of different wettability, the effects of capillary imbibition would be somewhat different than those presented. APPROACH The scaling laws studied were those developed by Rapoport1 and designated by him as "basic" scaling laws. These relationships require that the model be scaled to the geometry of the prototype, and that the model and prototype be operated at the same viscosity ratio and have identical relative permeability curves, contact angles and boundary conditions. It is also necessary that the groups** be identical in the two systems, although any of the parameters making up the groups may be different. Finally, the capillary pressure of one system must be directly proportional to that of the second. Studies were conducted in two four-layer models, representing quadrants of five-spots, which were geometrically similar and which had the same glass-bead packing. The fluids used assured the same wettability in both models. Thus, the contact angles and relative permeabilities of comparative sand layers in the two models were identical and the capillary pressures were directly proportional. However, one model had a characteristic length three times that of the other. To make the scaling groups equal and to check the scaling laws, it was necessary to adjust the rate, water-viscosity level, interfacial tension and water-oil density difference to compensate for the difference in model sizes.

By M. H. Gaskell, D. C. Lindley

Small, steeply inclined reservoirs without natural water drives often are found associated with salt domes or other highly faulted structures. Frequently, only one well may be economically justified in these reservoirs, from which oil is produced by an expanding gas-cap drive or by a dissolved-gas drive. Although a large fraction of the oil upstructure from the well may be recovered during primary depletion, only a small fraction of the downdip oil can be produced because of gravity effects. This downdip oil has been defined as cellar oil991 in contradistinction to "attic oil" which is the oil above the structurally highest well in reservoirs where a natural water drive is present. In this study, two methods of producing cellar oil by water flooding a one-well reservoir were investigated by means of a laboratory model. This model was scaled to represent a prototype reservoir having an area of 30 acres, a permeability of 500 md, and a thickness and dip of 30 ft and 30°, respectively. One method considered, the simultaneous injection of water and production of oil from a single well, would require that the lower portion of the productive interval of a well be completed for water injection and the upper portion for oil production. The other method considered, intermittent injection, would involve alternate injection of water into and production of oil from a single well. Injection of water into the formation would repressure the reservoir, causing gas to go back into solution. Since some of the injected water would flow updip from the well, water injection usually would be followed by a waiting period during which the water could drain from above the wellbore. Production of oil by gravity drainage and gas-cap drive could be initiated when water drainage became sufficiently complete. The amount of water produced along with the oil would naturally depend on how soon after water injection ceased that production was started. This process could be repeated in cycles until oil could no longer be produced economically. Of these two methods, the intermittent injection technique would be simpler to put into operation since it does not require a dual completion. Also, it is probably more generally applicable than the simultaneous injection-production method. It is to be expected that in some reservoirs the rock and fluid properties would be such that practical oil-production rates could not be achieved by the simultaneous technique. However, in reservoirs where the simultaneous method will result in practical rates of oil production, it does have the advantage of permitting immediate, continuous oil production; whereas in the intermittent method, oil production is interrupted by periods of water injection and drainage. It was the objective of this study to determine whether these two methods of cellar oil production are practical for the representative prototype investigated and to evaluate their relative merits. DESIGN OF LABORATORY MODEL SCALING REQUIREMENTS The prototype reservoir and fluids were selected to have the dimensions and physical properties shown in Table 1. The laboratory model was then designed in accordance with well known scaling criteria, as discussed by Croes, et al,2 except for one modification. According to Croes, et al, one requirement of scaling a laboratory model to a reservoir prototype is that both the relative permeabilities and dimensionless capillary pressure be the same functions of water saturation for the model and the prototype. Since unconsolidated sand packs are used in the laboratory model to represent the consolidated porous media of the prototype, it is virtually impossible to satisfy this requirement. Much of the difficulty stems from the fact that unconsolidated sands usually exhibit lower residual oil and connate-water saturations than do reservoir rocks. To satisfy the scaling requirement as nearly as possible, Perkins and Collins&apos; have suggested that the relative permeabilities be re-defined as

By F. E. Crane, J. Downie

The general application of Darcy&apos;s law to natural rocks has already been challenged in the literature.1 The evidence shows that the permeability as calculated from the Darcy equation can be a function of the pressure drop and the salt concentration of the water phase. Most explanations for aberrant behavior involve clays and their properties and have been qualitatively satisfactory.Recently, however, Odeh2 revived the theoretical views of Yuster.3 Since Yuster&apos;s concept implies a fundamental error in using Darcy&apos;s relationship for two-phase flow, and not merely that conditions may limit its use, Odeh&apos;s experimental support arouses considerable interest. However, Odeh&apos;s work as presented is thought to to be inadequate. He has omitted important information about his materials and procedures; therefore, acceptance of his conclusions should be withheld. Since a clay effect is possible, Odeh should have been allowed space to present a more detailed account of the rocks which he used and the precautions which he took to avoid confounding the effects of clay and fluid circulation. In addition, it follows from Odeh&apos;s discussion that the oil relative permeability should increase as the viscosity ratio increases. Odeh presents data corroborating this deduction. It also follows that the oil relative permeability should decrease as the viscosity ratio of oil to water decreases. However, our results show that a high relative permeability, when once attained by using a viscous oil, may be maintained when that oil is replaced by an oil of much lower viscosity. EXPERIMENTAL PROCEDURE The results are shown in Fig. 1 and were obtained as follows. Sandstone cores. 3-in. long X l-in, in diameter and which contained clays, were saturated with

By W. E. Brigham, P. W. Reed, J. N. Dew

By J. D. Alexander, W. L. Martin, J. N. Dew

This paper presents data obtained using a flood-pot technique to determine the fuel available and the corresponding theoretical air requirements for in situ combustion of crude oils. Since the technique is relatively quick and easy, it is a practical and convenient tool for evaluating reservoirs as fireflood prospects. It is also a research tool which facilitates systematic study of the variables affecting fuel availability and corresponding air requirements. The understanding of these variables is of prime importance to those concerned with the technical and economic development of in situ combustion as an oil-recovery process. The experimental results show conclusively that the fuel available for in situ combustion is not a constant but, rather, varies with crude-oil characteristics, porous-medium type, oil saturation, air flux and time-temperature relationships. Thus, the fuel availability for specified field applications should be determined using actual reservoir crude and core material and the process conditions expected during in situ combustion in the reservoir. INTRODUCTION In situ combustion is a thermal process for recovering crude oil from reservoirs. The thermal energy released during the combustion of a small amount of the oil in place aids in the displacement of the remaining oil. Numerous articles have been published describing the in situ combustion process giving detailed results of laboratory and field experiments.10 In order to engineer an in situ combustion project, a number of important factors must be considered and determined. These factors include: (1) the amount of fuel consumed per unit of reservoir volume swept by the combustion zone, (2) the composition of the fuel consumed, (3) the amount of air required to consume this fuel, (4) the portion of the reservoir swept by the combustion zone, (5) the appropriate air-injection rates and pressures, (6) the amount of oil that will be recovered, (7) the rate of oil production and (8) the operating costs. Nelson and McNiell1 recently have described a procedure which utilizes laboratory combustion-tube data as a basis for the calculation of some of these design factors. Various authors have attempted to describe the in situ combustion process mathematically, and considerable progress has been made. Analytical solutions to the problem of heat transfer from a moving combustion front have been obtained for linear and radial systems."-&apos; All of the published results involve the assumptions that: (1) fuel concentration is constant throughout the reservoir, or that fuel concentration is inversely proportional to the velocity of the front for a given rate of oxygen consumption; and (2) the fuel reacts instantaneously with injected oxygen, while liberating a constant amount of heat per unit weight of fuel at all temperatures. It seems both desirable and reasonable to test the validity of these assumptions experimentally. This paper presents laboratory data which were obtained by means of a "fire flood-pot" method for determining fuel availability and composition, and the corresponding theoretical air requirements for in situ combustion of crude oils under variable conditions. The mechanics of the method are similar to a conventional tube-run experiment.&apos; The important differences involve the size of the reservoir model used and the method for providing the experimental environment. The new method subjects conventionally-sized core samples or unconsolidated sands to a programmed environmental sequence similar to that experienced by a similar volume of rock during the approach and passage of a combustion front in a long tube or in an oil reservoir undergoing in situ combustion. Restored-state samples can also be used. The small samples and relatively simple techniques involved allow an experiment to be set up, run and calculated in about three 8-hour days. This is a considerable improvement over long-combustion-tube techniques which can require several days to run and several more work days to set up and calculate. All the runs presented were run at 40-psig injection pressure. Pressure was not considered as a variable for these experiments, since we previously had found that it had only a small effect on fuel availability up to 600 psig.APPARATUS AND MATERIALS APPARATUS The fire flood-pot apparatus consists of a consolidated

By J. Downie, H. A. Kendall, G. H. F. Gardner

Some cases of the motion of two miscible fluids in uniform linear models are discussed. There is no bulk flow through the models, and the convection currents are caused solely by density gradients. Horizontal, vertical and inclined positions of the models are treated separately. Analytical formulas for the motion of a narrow transition zone between the fluids are obtained and compared with measurements, and the limitations are discussed. Observations of the ultimate stabilizing effect of diffusion on the motion me compared with the theory. It is shown that fluid motion in an inclined model with a constant rate of bulk flow can be directly deduced from the cases discussed, provided the viscosity ratio is small. INTRODUCTION In some reservoirs, convection currents caused by variations in the fluid densities may be significant. For practical purposes it may be desirable either to minimize the effect, particularly in miscible displacement, or to maximize the effect as in some schemes for the production of heavy crude oils by combustion. Experiments by Craig, et al,l have shown the effectiveness of gravity in reducing the efficiency of a miscible displacement when the mixed zone between the displacing and displaced fluids is narrow compared with the height of the system. The presence of a board transition zone from one fluid to the other has been shown by Perkins, et al,2 to nullify considerably the influence of a difference in density. Indeed, the theoretical discussion given by Perrine3 has shown that when the transition zone exceeds a certain critical length the efficiency approaches 100 per cent. Many additional results 495 have been published on miscible and immiscible displacements which show the importance of density difference and also mobility ratio. The aim of the present paper is to discuss some cases of gravity segregation of miscible fluids in linear models such as are often used in the laboratory to evaluate recovery processes, and to supply additional experimental evidence in support of the conclusions. An attempt is made to calculate simply the magnitude of the fluid motion caused by density pdients and mobility ratios, and to quantify the modifications in the fluid motion produced by the combined effect of molecular and convective dispersion. However, it should be pointed out that the uniform permeability of the models and the use of only a single pair of fluids (whereas several pairs of fluids may be employed in a recovery scheme) severely restricts direct conclusions about natural reservoirs. For conciseness, the motion generated by density gradients is emphasized for the case of no bulk flow through the models. This is not a drastic limitation because, as shown in Appendix A, a fluid motion with a constant bulk flow through any linear model is equivalent to a fluid motion with no bulk flow in the same model inclined at a different angle to the horizontal, provided only that the density is a linear function of the viscosity of the fluid mixture. HORIZONTAL MODEL In this case the model is assumed to have a rectangular cross-section with a horizontal breadth b, vertical height and a great length L. Throughout.the paper it will be assumed that x-axis points along the length, the y-axis along the width and the z-axis along the height. Thus, in the present case the x, y plane is horizontal. Initially, the transition zone between the fluids is assumed to be thin and parallel to the y, z plane. An example of this situation in a practical problem arises in a scheme for using air for cushion gas in the storage of fuel gas in aquifers. 6 With the passage of time the denser fluid sinks and spreads along the bottom of the model while the lighter fluid rises. The interface extends from the top plane of the model to the bottom. Experiments have shown that for practical purposes this interface may be treated as a plane surface at all times. The surface is significantly curved, however, for viscosity ratios greater than about 10. Other complications arise with large viscosity ratios because of the nonlinear dependence of the viscosity on the composition of the mixture, so that the simple results given here are restricted to fairly low viscosity ratios.

By J. H. Henderson, R. J. Wygal, J. Naar

Experimental work is reported which shows that consolidated rocks and unconsolidated porous media exhibit different imbibition flow behavior. At a given saturation the imbibition nonwetting permeabilities for a rock are smaller than the drainage permeabilities. The contrary happens for unconsolidated aggregates — imbibition nonwetting permeabilities are larger than drainage ones. A similar difference is observed for the wetting phase. Imbibition permeabilities are larger than drainage ones for a consolidated rock but smaller than drainage permeabilities for an unconsolidated medium. The results of these differences are examined for two cases. 1. Flooding Efficiency — Craig&apos;s1 scheme for the computation of production history of a five-spot water flood is shown to agree extremely well with experimental results obtained when using a system packed with glass spheres if imbibition relative permeability curves are used. 2. Alcohol-Slug Displacement — Published theory 2 on oil displacement by alcohol slugs has been questioned despite the apparent agreement between predicted and observed results. The present work suggests that, if imbibition relative permeability curves characteristic of the unconsolidated media used in the early experiments had been available to make the predictions, the inadequacy of the theory would have been immediately evident. The experimental work shows that poorly consolidated formations tend to behave like unconsolidated media. Finally, it is shown that the difference in imbibition behavior is directly related to pore-size distribution and cementation. PART 1 — THE FLOW BEHAVIOR OF UNCONSOLIDATED AGGREGATES Experiments on scaled models of field reservoirs are useful for studying new displacement processes which are incompletely understood. Even when a mathematical description is possible, the solution might be difficult and complex. An answer obtained from a scaled model is extremely valuable in such cases. A great amount of work$-5 therefore, has been devoted to the derivation of scaling laws. Similarity groups have been defined which assume (1) that the relative Permeability curves of the prototype and the model are the same whether the displacement is an imbibition or a drainage process and (2) that there is a linear relationship between the capillary pressure of the model and the prototype. For practical reasons (simplicity in the preparation of models, duration of the experiments, etc.), the porous media of laboratory models are usually unconsolidated packs of sand or glass particles. Hence, unless the capillary and flow characteristics of unconsolidated and consolidated systems are identical, the model data are applicable only to unconsolidated formations. The usefulness of scaled-model studies may then be seriouslyrestricted since most oil-bearing sands are consolidated. Perkins and Collins6 suggested the use of model and prototype curves normalized with respect to both relative permeability and saturation to improve compliance with scaling criteria. Even this technique does not give a satisfactory model-prototype match. This paper reports an observation of two-phase flow in unconsolidated sands which shows that, for most displacements, "scaling" in the strict sense of the word is not even qualitatively feasible with a sand model. It provides, however, a firm foundation for testing a theory by matching it with observed performance of laboratory-size models. EXPERIMENTAL AS a part of a basic study of packed aggregates, the relative permeability of glass-spheres and sand-grain packs was measured with capillary control. The fluids were oil and air&apos; The spheres were packed in plastic cylinders 1-in. in diameter;

By V. V. Valleroy, A. J. Cornelius, B. T. Willman, G. W. Runberg, L. W. Powers

This paper reports the results of an investigation into the use of steam as a recovery agent. High oil recoveries by steam, as much as 100 per cent greater than by water flood, were demonstrated in laboratory linear cores. The principal mechanisms responsible for the additional oil have been identified as (1) thermal expansion of the oil, (2) viscosity reduction and (3) steam distillation. Although the first two also enhance recovery by hot water flood, they are effective with steam injection at lower volumes of produced fluids. Steam-zone residual oil saturation is independent of initial saturation. Recovery by steam is greater for lighter oils because they contain a greater fraction of steam-distillable components. Equations for the steam-zone advance in a radial homogeneous system are presented; these show the effect of reservoir parameters. The displacement in the hot liquid region moving ahead of the steam front can be estimated by a calculative procedure which is suggested. The method which takes account of the temperature gradient is applicable also to a regullar hot water flood. INTRODUCTION Considerable industry interest in the application of heat to petroleum reservoirs as a means of increasing oil recovery has been evident in the past few years. Three thermal methods which have attracted interest are (1) the injection of saturated steam, (2) the injection of hot water and (3) the injection of air into a formation to support combustion within the reservoir. Much has been published in recent years on underground burning, and there have been several papers on hot water injection. Although there are several early reports1,2 on steam injection, no recent experimental studies have been published on this recovery method. In our early thermal methods research, a marked improvement was found in oil recovery by steam injection compared with recovery by water injection in the same system. An investigation subsequently was undertaken to obtain quantitative information from which to evaluate steam injection as an oil recovery method. In addition, it was desired to investigate the recovery mechanism of hot water as compared with that of "cold" water and steam injection. An understanding of the mechanisms by which these processes operate would generally define favorable field conditions for their successful application. This paper reports the results of the laboratory study and suggests calculative approaches to estimate the field behavior of the steam-injection process. EXPERIMENTAL METHOD EQUIPMENT A schematic diagram of the equipment used for the displacement tests is shown in Fig. 1. Essentially, it consisted of a core with suitable means for recording temperatures, a feed system for injecting steam or cold or hot water, and a receiving train for condensing, cooling and measuring produced fluids. For the steam experiments, air-free saturated steam was piped from the boiler to the core face in insulated lines that were provided with steam traps and bleeds to remove any condensate formed in the lines due to heat losses. A 12-in. section of the line immediately ahead of

By J. J. Taber, I. S. K. Kamath, R. L. Reed

Alcohol floods of consolidated sandstone cores have shown the process to be strongly dependent on the phase behavior of the particular alcobol-oil-water system used. This means that in many cases the mechanism does not conform to the idea of a piston-like displacement. Instead, it is found that by changing the alcohol it is possible to change the relative velocities of the oil and water and, in fact, the entire mechanism of the process. The effects of rate, viscosity, initial saturation, distance travelled and hysteresis of relative permeability on the alcohol flooding mechanism are discussed. INTRODUCTION Reasons for interest in the use of alcohol to miscibly displace oil and water from a porous medium appear in the existing literature.l-7 The mechanism of the displacement has been considered and the apparent implications formulated into a theory which presumably would enable one to predict the essential features of the process.6 Unfortunately, most of the reported experiments have been performed with unconsolidated or artificially consolidated sands. With these systems some of the noteworthy facets of the process are obscured and resulting data appear uncertain. It is the purpose of this paper to show how the use of consolidated sandstones has led to revision of the mechanism and, hence, the theory of alcohol flooding. The practical result is increased pessimism toward the possibilities of commercial application of the simplest form of the alcohol-slug process. However, elucidation of the mechanism has made it possible to define the essential characteristics of a system of slugs which will behave in a nearly piston-like fashion and, thus, yield the best possible result. EQUILIBRIUM PHASE BEHAVIOR Fig. 1 is a diagram of the ternary system isopropyl alcohol (IPA)-Soltrol-calcium chloride brine. Brine was used to prevent plugging of the core and calcium chloride was used because sodium-chloride brine exhibits a solid phase with Soltrol and IPA. If alcohol is added in increments to the immiscible mixture of water and oil represented by Point A, the path followed by the successively equilibrated samples will be on the Line ABC and pass from the immiscible region to the miscible region by crossing the binodal curve at B. Consider the intersection D of this path with the tie Line EF. The quantity of oleic phase is proportional to the Segment ED and the quantity of the aqueous phase is proportional to DF. Compositions of the two phases are specified by Points E and F. It is clear that in the case shown the oleic phase is diminishing and entirely disappears when miscibility is achieved. Such will

By P. T. Bail, J. E. Bobek

In reservoirs containing soft shales interbedded with oil-producing sands, it is possible to have water movement from the shales into the sands during reservoir depletion. This paper presents the results of scaled flow-model tests performed to investigate the efficiency of oil displacement by this vertical influx of water into oil-producing sands. In these model tests, the effects of rate of influx and rock wettability were considered. Oil recoveries by shale-wafer influx and by water flooding were cornpared after 0.4 hydrocarbon volume of water entered the producing sand. This comparison was made for water-wet and oil-wet systems. In water-wet sand, shale-water influx produces slightly less oil than conventional water flooding; in oil-wet sand, shale-water influx produces about one-half as much oil as conventional water flooding. In another type of comparison, it was found that shale-water influx followed by water flooding recovers less oil than water flooding alone. This is true for both water-wet and oil-wet sands. A comparison of tests run at different rates of shale-water influx shows that oil recovery is insensitive to rate in water-wet sand; in oil-wet sand, oil recovery decreases with decreasing rate of influx. INTRODUCTION Localized subsidence of the earth&apos;s surface has accompanied the depletion of some oil reservoirs, particularly in California,1, 2 along the Texas Gulf Coast,3 4 and in the Bolivar Coastal fields of Venezuela. Subsidence occurs when fluid withdrawals reduce the pressure in the reservoir. The reasons for subsidence accompanying a reduction in reservoir pressure are not known with certainty.10° However, there is considerable evidence that compaction of soft shale beds adjacent to producing oil sands can be a major cause of this subsi-dence.3, 6, 10-12 When the shales compact, a limited amount of water moves from the shales into the producing sands. A schematic illustration of this oil-producing mechanism is shown in Fig. 1. As the pressure in the sand declines due to oil production, a predominantly vertical pressure gradient develops at the sand-shale boundary. This causes water to move from the shale into the sand as indicated by the solid arrows. This paper reports the results of scaled flow-model tests to investigate the efficiency of oil displacement by the vertical influx of shale water into producing sands. The model tests were not performed with the aim of duplicating the recovery behavior of any specific reservoir. The primary purpose of the tests was to obtain a better understanding of oil displacement by shale-water influx. A knowledge of the oil- and water-production characteristics of even a simplified reservoir system should be of value to engineers estimating the performance of reservoirs where shale-water influx is occurring in conjunction with other production mechanisms. The following limitations and assumptions apply to the model work. 1. The sand of the prototype reservoir is homogeneous and horizontal. 2. The shale-water influx is uniformly distributed along the top and bottom of the sand member being studied. 3. No effects of edge-water drive or dissolved-gas drive that might accompany shale-water influx are considered. PROTOTYPE RESERVOIRS Scaled-model tests were performed to study oil displacement from three prototype reservoir sections. The reservoir sections modeled consist of single sand layers out of a sequence of -sand and -shale layers, as illustrated in Fig. 1. Each prototype represents a homogeneous, high-permeability, unconsolidated sand layer. In the field, the prototype is oriented in such a manner that one end is at the radius of drainage of a producing well and the other end is pointed toward the producing well (Fig. 2). The sand and fluid properties and the dimensions of the three prototypes are given in Table 1. The capillary pressure relationships for the three prototypes are presented in Figs. 3, 4 and 5. The oil-water per-

By M. D. Arnold, P. B. Crawford, P. C. Hall

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

By A. L. Barnes

A number of reservoirs have been partially invaded by bottom water. Water flooding such reservoirs can be especially inefficient if the oil has a high viscosity because injected water will under-run the oil and emerge at producing wells without having displaced much oil. A possible means of improving water sweep efficiency would be to precede the water flood with a slug of water purposely thickened with a chemical additive. This possibility has been studied with a scaled laboratory flow model. The investigation was carried out on a model representing a 20-acre five-spot with one set of reservoir condition~. Displacements were performed with water, with viscous-water slugs of 10 and 25 per cent of the pore volume followed by water, and with all viscous water. Displacement tests were made at several rates of injection. For all cases, compared at the same producing water-oil ratio, an increase in rate resulted in an increase in volumetric sweep. The larger the quantity of viscous slug injected, the greater the crossflow of oil ahead of the displacing front and, thus, the lower the WOR during that period of a displacement. This investigation indicates that the injection of aqueous viscous slugs in this type of system would give some additional benefit over conventional flooding by (I) reducing the life of the flood, (2) reducing lifting costs and (3) increasing ultimate recovery. The benefits of a viscous-slug displacement would warrant its use if the viscous water could be created for a few cents per barrel. INTRODUCTION The most appropriate method for water flooding oil reservoirs which have been partially invaded by bottom water has been a problem of considerable interest. Such reservoirs, having good vertical permeability and unfavorable mobility ratios, are difficult to produce efficiently under normal waterflood procedures. Even though the injection wells have been plugged back above the oil-water contact and the water zone has been squeezed off, injection water will enter the formation and not only displace oil, but also much of it will displace the bottom water, thus creating a high producing water-oil ratio at the start of a flood (see Fig. 1). Since the rate of injection and the viscosity of the displacing fluid are the more easily controlled physical parameters of the reservoir, it is quite natural to study their effects on the volumetric sweep of the oil zone and on the producing water-oil ratio. Increasing the viscosity of the displacing fluid has two disadvantages—it reduces the maximum rate of injection into the reservoir, and it costs more than water. It was thought that the injection of a viscous-fluid slug, followed by water, would minimize these two disadvantages, increase the volumetric sweep of the oil zone and reduce the producing water-oil ratio. Water with an additive to increase viscosity would probably be the most effective. The primary purpose of this investigation was to determine the feasibility of injecting viscous-water slugs followed by water to improve or hasten oil recovery while reducing the producing water-oil ratios. The effect of injection rate upon recovery was also investigated. A laboratory model, scaled to a 20-acre five-spot prototype with one set of reservoir conditions, was constructed. Laboratory studies of displacements with (1) water, (2) viscous-water slugs of 10 and 25 per cent of the pore volume followed by water and (3) all viscous water were performed at several rates of injection. THEORY OF SAND MODEL SCALING There are two conventional means of determining scaling criteria. These are dimensional analysis and inspec-tional analysis. Determining scaling criteria by dimensional