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By F. E. Crane, J. Downie

The general application of Darcy'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's concept implies a fundamental error in using Darcy's relationship for two-phase flow, and not merely that conditions may limit its use, Odeh's experimental support arouses considerable interest. However, Odeh'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'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 J. K. Elliott, P. H. Kelly

Many engineering functions such as surface metering work and laboratory compressibility check points involve the use of liquid densities of light hydrocarbon mixtures at various pressures and temperatures. However, at the present time, no simple reliable method exists for determining density variation, particularly if the composition of the liquid is unknown. Consequently, a study was undertaken to develop and present a simple and accurate method of predicting density variation of a light hydrocarbon liquid with pressure and temperature, knowing only the density of the liquid at some condition. The experimental liquid compressibility data from API Project 37 by Sage and Lacey' have been considered to be accurate within 0.5 per cent and cover a wide range of pressure (14.7 to 10,000 psia), temperature (100" to 400°F) and molecular weight (up to 150). From these data, a set of liquid density curves, which relate density to pressure, temperature and molecular weight, was developed. These curves make it possible to predict density variation with pressure and temperature. Compared to extensive laboratory compressibility data on a complex, light hydrocarbon liquid, the use of the liquid density curves resulted in an average error of less than 0.5 per cent. Based on the results of this analysis, it is concluded that the set of liquid density curves developed from the data of Sage and Lacey provides an accurate and simple method for predicting the density variation of light hydrocarbon liquids when the density at some condition is known. These curves should be very helpful in many engineering calculations, particularly in the surface metering of light hydrocarbon liquids. INTRODUCTION Many situations arise in field and engineering laboratory work, such as reservoir engineering studies, check of experimentally determined laboratory data and orifice flow-meter formulas, where liquid density factors at various pressure-temperature conditions are required. Also, the need for accurate light hydrocarbon liquid information has become more important with the advent of miscible-type displacements for secondary recovery purposes in oilfield operations. Several reliable methods are available1 - "or determining the density of liquid hydrocarbons if the composition of the liquid is known. However, there is a definite lack of methods for accurately determining the variation of density when the composition of the liquid is unknown. The purpose of this study is to review the various methods for determining hydrocarbon liquid densities and to develop a simple and reliable method of determining variation in density of light hydrocarbon liquids with pressure and temperature when the compositio~n of the liquid is unknown. METHODS FOR DETERMINING DENSITY OF LIQUIDS OF KNOWN COMPOSITION Sage, Lacey and Hicks' have proposed a method to predict the density of light liquid hydrocarbons by using partial molal volumes. Data are available on experimentally developed partial liquid volumes of hydrocarbons over a rather limited range of temperature, pressure and composition. The partial mold volume method has proved satisfactory for determining the density of some hydrocarbon liquids when the composition is known. Within the range covered in the Sage, Lacey and Hicks1 data, the results agree within about 3 per cent of the experimental values. Hanson mentions the limitation of this method to a composition range of approximately 10 per cent by weight of methane, which will not allow this correction to cover most low molecular weight-light hydrocarbon liquids. Standing and Katz2 studied data on light hydrocarbon-liquid systems containing methane and ethane at high temperature and pressure and have presented a method for determining liquid densities, assuming additive volumes for all components less volatile than ethane and using apparent densities for methane and ethane. The compressibility and thermal-expansion curves used by Standing are based on assumptions that compressibility of a hydrocarbon liquid at temperatures below 300°F is a function of the liquid density at 60°F and that thermal expansion of the liquid is affected little by pressure. The information required to use this technique with an example problem is furnished by Standing.' Hanson eports an average error of - 0.5 per cent using the method of apparent densities in calculating liquid densities of several volatile hydrocarbon mixtures. However, as implied, the apparent density method is not applicable for liquid density calculations when the composition of the liquid is unknown. Watson- as presented a method

By American Institute of Mining Engineers

By J. L. Lehman, J. D. Sudbury, J. E. Landers, W. D. Greathouse

A full scale field experiment on cathodic protection of casing answers questions concerning (1) the proper criteria for determining current requirments, (2) the amount of protection provided by different currents, and (3) the transfer of current at the base of the surface pipe. Three dry holes in the Trico pool in Rooks County, Kans., were selected for cathodic protection tests. The three holes were in an area where casing failures opposite the Dakota water sand often accur in less than a year. Examination of the electric togs showed the wells to be similar to other wells in the field where casing in four of seven producing wells has failed. The three holes were cleaned out and cased with 75 joints of new 51/2-in. 14-tb J-55. Each joint was visually inspected and marked before it as run. The casing was bull plugged and floated in the hole 50 that the inside might remain dry and free of excessive attack. Also, if a leak occurred, a pressure increase could be observed on gawge at the surface. Extensive testing was done, including potential profiles, log current-potentid curves and electrode measurements from both surface and downhole connections. Based on these data, a current of 12 amps was applied to one well and 4 amps to mother. The third well was left to corrode. During the two-year period when the casing was in the ground, [he applied current was checked weekly, and reference electrode measurements were made about every two months. Three sets of casing potential profi1e.c were run. When the three strings were pulled, each joint was examined for type of scale formed, presence of sulfate-reducing bacteria, extent of corrosion nttnck and pit depth. Since the pipe was new when run, quantitative determination of the protection provided by current was possible. This is the first concrete field evidence to help resolve the many arguments about the proper method for selecting adequate current for cathodic protection of oilwell (-using. INTRODUCTION A casing string is run when a well is drilled. This pipe is supposed to protect this valuable "hole in the ground" for the life of the well. Often the casing does not last the life of the well; it is with these casing failures that this work is concerned. The cost of repairing a casing failure varies from field to field—from as much as a $30,000 per leak average in California to $5,000 per leak in Kansas. Additional costs other than actual repairs are also important. These include formation damage, lost production, etc. Casing damage caused by internal corrosion is important in some areas. Treatment normally consists of flushing inhibitor down the annulus, but further research is being done on control measures. The test described in this paper is concerned only with external corrosion. The problem of casing failure from external attack has appeared in several areas including western Kansas, California, Montana, Wyoming, Texas, Arkansas and Mississippi. Cathodic protection is currently being used in an attempt to control external corrosion. From reports in the NACE there are thousands of wells currently under cathodic protection. The quantity of current being applied ranges from 27 amps on some deep California wells to a few tenths of an amp being supplied from magnesium anodes on wells in Texas and Kansas. Considerable field and laboratory effort1,9,5,6 was exented on the problem of cathodic prctection of casing, and it became fairly obvious that this method could be used to protect wells. Early workers showed that current applied to a well distributed itself over the length of the casing and was not concentrated on the upper few hundred feet. Basic cathodic protection theory had shown that corrosion attack could be stopped by applying sufficient current. The problem resolved itself, then, into one of trying to decide just how much current was necessary. Various criteria were utilized in installing the many existing cathodic protection installations. These methods included the following. 1. Applying sufficient current to remove the anodic slope as shown by the potential profile." 7. Applying enough current to maintain all areas of the casing at a pipe-to-soil potential of .85 v.' 3. Applying the current indicated by a log current-potential (or E log I) curve." 4. Supplying the current necessary to shift the pipe to-soil potential .3 v." 5. Applying 2 or 3 milliamps of current per sq ft of casing."

By P. Hazebroek, C. S. Mathews, E. E. Allen, H. C. Lefkovits

A rigorous study was made of the behavior of reservoirs composed of horizontal layers, unconnected except at the well and filled with a compressible fluid. The report is presented in two parts. Part I deals with the practical implications of the results obtained; Part 11 contains the mathematical derivation of the solution. The main portion of Part I is concerned with application of the results to reservoirs composed of two layers. Relative rates of depletion of the layers are studied, and it is shown that differential depletion between layers exists in the transient stage of the reservoir, which generally is of an order of magnitude longer than the transient stage in a single-layer reservoir. In the transient stage, the more permeable layer is depleted faster than the less permeable. However, the reservoir approaches a steady-state situation where both layers contribute equally to production. Theoretical build-up curves from such reservoirs are presented, and the influence of a skin effect and flow into casing and tubing are also evaluated. The build-up curves are predicted to have, first, the familiar logarithmic straight-line section and, subsequently, a rising and flattened section. The results found are compared with an extension of an approximate theory, and it is found that this simplified theory is applicable over most of the life of the reservoir. Extensions to reservoirs containing more than two layers are indicated, and examples of the performance and build-up curves for three-layered reservoirs are presented. The theoretical results on build-up curves were applied to field examples of such reservoirs, and satisfactory results were obtained. From the build-up curve, the pemeability-thickness product, the wellbore damage and the static pressure are obtained. However, it apparently is not possible to determine the properties of the individual layers from the combined build-up curve. A large number of reservoirs have been found where the producing formation is composed of two or more layers of differing physical characteristics, such as permeability and porosity, and where also the thicknesses of the layers differ. Since in general a differential depletion should exist between the layers of such reservoirs, it would be advantageous to know the amount of the differential depletion under a given production history. It also would be valuable to know the pressure behavior, because it could be undesirable to produce a reservoir in such a manner that the pressure in one of the layers would have fallen below the bubble point of the oil at a time when another layer might still be virtually undepleted. The determination of static pressures in shut-in wells with slow build-up is another feature of importance in layered reservoirs. If the behavior of the reservoir differs appreciably from the predicted behavior of a single-layer reservoir, the type of analysis for build-up curves suggested for single-layer reservoirs is not applicable. Several authors have treated the problem of finding the pressure and production characteristics of multilayer reservoirs. Horner treated the problem of n layers in an infinite field, the layers being connected only at the well. Tempelaar-Lietz2 has presented an approximate treatment of the characteristics of a bounded reservoir composed of two layers of different permeabilities and equal thicknesses. Homer gave no information on differential depletion between layers, and the treatment of Tempelaar-Lietz was not applicable for prediction of pressure build-up behavior. In addition, it was thought that a more rigorous treatment than the one by Tempelaar-Lietz would be valuable in determining the range of validity of this solution. The present study, therefore, was made of a bounded reservoir composed of two or more layers,

By H. H. Rachford, J. Douglas, D. W. Peaceman

A numerical solution of equations describing two-phase flow in porous media shows promise in providing a technique for predicting the displacermet from satlds of oil by water or gas. The description includes the influence of relative permeability, fluid viscosities and densities, graviry, and capillary pressure, and, tholrgh tested ortly for two-dimensional cases, should be eqlmlly applicable in three-dimensional geometry. Two memorical methods ore presented: the first method is quite general in its applicability; the second method can be used only with certain types of boundary conditions but requires less computing. Comparisons of computed results with data from Inhoratory models are presented. These data were taken on a water flood of a strarified model and on water floods of a five-spot model for favorable and unfavorable mobility ratios. On the stratified model, excellent agreement with recovery at breakthrough was obtained; agreement with recovery after breakthrough was poor. In the five-spot model, good agreement was obtainecl with recovery at and after breakthrough. The purpose of this paper is twofold: first, to present a reservoir engineering method requiring knowledge only of rock geometry and the normally measured rock and fluid properties for calculating the multi-dimensional flow of water displacing oil from porous, water-wet rock containing connate water; and, second, to investigate the validity of the method by comparing results of calculations with previously observed displacements in laboratory models. The availability of such a verified technique of reservoir analysis would afford major advantages. First, it would demonstrate that the fundamental macroscopic concepts of two-phase fluid mechanics, i.e., relative permeability and capillary pressure, yield an adequate description of the physical process. Also, since most reservoir rocks appear to be water-wet and contain connate water along with oil, it would provide a method of technical and economic value for calculating the course of oil displacement by water directly from measured reservoir and fluid properties. It is important to emphasize that the calculation is subject only to the limitations of detail and precision of reservoir information, but not to limitations introduced by simplifying assumptions. Further, it would providc almost the only means of examining the influence of factors such as the size and extent of reservoir inhomogeneities and uncertainties in the basic reservoir data. Knowledge of this influence is essential in stating quantitatively the detail required to define a reservoir and in establishing the relation between the uncertainty in the definition of reservoir properties and the reliability of predicted performance. Moreover, in the process of solving a particular problem much detailed information would become available about the displacement process. For example, at each point in the reservoir for all stages of the displace ment. the calculations would yield not only the water and oil saturations but also the direction and magnitude of fluid velocities and the local fluid mobilities. Such dctail is potentially of great value in giving insight into the mechanics of particular displacements. The development of such a method has long been the goal of research in the application of numerical an-alysis to petroleum reservoir enginecrinz. The most complete treatment of the displacement process published to date is that of Douglas. Blair, and Wagner,' which, however, was limited to flow in a single dimension. The method presented in the present work is hascd on the numerical solution of a finite difference analogue of the multi-dimensional differential system describing the displacement process. Although current work has considered only displacement of oil by water from water-wet sands, the differential system for other immiscible displacements, such as gas displacing oil with which it is in phase equilibrium, is quite similar. It should therefore be expected that the technique described will be applicable to displacement by gas as well. The description of the simultaneous flow of fluids through porous media in terms of relative perrncability and capillary pressure has been adequately discussed in the literature and standard textbooks. Sec, for exampje, Muskat. Chapter VII.'

By Frank Firmstone

By P. E. Baker

A paper by A. S. Odeh' expounds a capillary-flow theory which purportedly provides a mechanism whereby relative permeability depends on oil-water viscosity ratio and may be greater than unity for high viscosity ratios. Core-measurement results are presented to support the theoretical development. This paper presents arguments to indicate that (1) the theoretical treatment is basically incorrect, (2) data reported are insufficient to support the conclusions and (3) literature cited does not support the theory or the conclusions. PROPOSED MECHANISM The essence of Odeh's theory is that oil flows as a filament along the central portion of a straight, uniform capillary of radius r filling the tube to a radius ri. Surrounding the filament of oil is an annulus of water in which exists vortex motion but no net flow. The water is described as being in "microscopic but not macroscopic" motion. The oil filament is aided in its flow by moving upon the water vortexes as if on roller bearings. This process is presented as a steady-state flow condition. The first objection to the existence of vortexes in the presumed water layer is that the theory provides no mechanism whereby they can be established. This fact was mentioned by C. F. Weinaug in a discussion published with Odeh's paper. The capillary contains no irregularities or obstructions, and the water is not presumed to be in turbulent flow. Apparently, cylindrical symmetry is assumed; therefore, the supposed vortexes must be toroidal, the line of zero velocity being a circle concentric with and in a plane perpendicular to the axis of the capillary. This is a rather difficult picture to accept. The author referred to Yuster's statement' that he had observed the "spinning in place" of otherwise immobile water. Yuster's article does not describe the conditions under which this motion was observed or the means used to observe it. However, the article does make clear that the observed motion was not in a straight, uniform capillary but, rather, apparently oc-cured in some kind of dead-ended pore space. Obvious- ly, such a report cannot be considered as support for Odeh's concept of two-phase capillary flow.

By D. O. Wyble

Five water-driver fields, for which pressure predictions had been made within a few years after discovery, were re-studied when four to five years of additional pressure and production data became available. It was fortnd that forecasts of the pressure in water-dri~fe reservoirs may be subject to considerable unccrtainty. Predictions car be erroneous when there is insufficient presswe history to define the cllaracteristics of the aquifer, and when there are errors in the pressure, production or geologic data. INTRODUCTION The efficient operation of an oil or gas reservoir requires that the important characteristics of the reservoir be determined soon after its discovery. It is especially desirable to evaluate the pressure-production relationship quickly, for this relationship provides a basis for deducing the type of production mechanism that is operative, and for making pressure predictions. The pressure predictions, in turn, provide a basis for calculating efficient rates of production, determining whether water or gas should be injected, etc. The importance of pressure prediction is such that forecasts should be made as accurate as possible, and the limits of error well defined. Historically, pressure forecasts for some fields have proved very accurate, while for others the forecasts were so erroneous that they resulted in the adoption of wrong, or at best, unnecessary production practices. Pressure predictions made for water-drive fields are especially subject to error. Accurate forecasting for these fields requires that much be known not only about the reservoir proper but about the adjacent water-filled rock as well. The water-containing rock, or aquifer, may extend for many miles, and often there is only meager data regarding its thickness, permeability and porosity. Much of the information must be inferred from the previous pressure behavior of the reservoir. A brief pressure history may provide little information about the characteristics of the aquifer. Hence, pressure predictions made early in the life of water-drive fields can be incorrect. The work described in this paper was done to determine the degree of reliability which can be expected of pressure predictions made within a few years after water-drive fields are discovered. Five fields, for which the original pressure predictions had been based on less than seven years' history, were re-examined with the aid of four to five years of additional pressure data. Where the predictions were inaccurate, the reasons for failure were ascertained. The studies were accomplished by use of the electric reservoir analyzer.' The analyzer was first adjusted to repeat the original pressure-production match using the same values for the various parameters as were used in the original study. Then, the actual production rates experienced during the time elapsed since the initial study were set into the analyzer, and the pressure behavior indicated by the machine for this period was compared with that which actually OCcurred. Where the pressure profile traced out by the analyzer deviated from the observed field behavior, the analyzer was readjusted to obtain a better over-all match. The old and the new solutions were compared to determine the reasons for any differences. COMPARISON OF PREDICTED RESERVOIR PRESSURE BEHAVIOR WITH ACTUAL PERFORMANCE Field A The original pressure-production match is entirely adequate as evidenced by the pressure match of the field's history subsequent to Jan., 1952 (see Fig. 1)'.

By F. Brons, W. C. Miller

Pressure information for use in material-balance calculations is obtained, where possible, from pressure build-up surveys in shut-in wells. Using proper extrapolation methods, static pressures are obtained which, by averaging, give the field static pressure. Often, particularly in fields with a large number of wells, only spot pressure readings are available. A graphical method is presented here which enables the determination of the corrections which must be applied to the spot readings to give an estinzate of the static pressure. Although the static pressures thus obtained are not so reliable as those from build-up surveys, they are more nearly correct than the spot readings themselves for use in material-balance calculations. INTRODUCTION The average static pressure in a bounded reservoir is determined from a number of individual-well pressure measurements. Where pressure build-up curves are available, extrapolation methods such as described in Ref. 3 may be used to determine the static pressure in the drainage area of each individual well. The possibility of using pressure build-up curves presupposes that each well being surveyed is closed in during a certain period and that, during this time, a pressure recorder is left suspended in the hole. For surveys in fields with a large number of wells, this is usually not feasible for economic and other reasons. Either a large number of pressure recorders would have to be used simultaneously or, using a limited number of recorders, the time interval needed to complete a field-wide survey would be too long. The data obtained for this incomplete coverage are insufficient to permit reliable averaging of the few calculated static pressures over the entire reservoir. In many such cases another type of pressure information is available, i.e., spot pressure readings. During this type of pressure survey all wells are closed-in simultaneously and, after a reasonable shut-in time (e.g., three days), pressure readings are taken by running the recorder in and out of each successive well. These surveys, which are less expensive, are often taken at regular intervals, say once or twice a year. In fact, such surveys are required by the state regulatory bodies in many portions of the united States. These spot readings are normally lower than the static (fully built-up) pressure due to the relatively short shut-in time. No direct means of extrapolating such a reading to the static pressure is available because no pressure build-up record is obtainable. Consequently, these data are inferior to pressure build-up information as a basis for estimating the stabilized reservoir pressure in the drainage area of a specific well. For the common case where abundant spot readings but only a few pressure build-up surveys are available, our studies suggest that it may be possible to design a program which will combine the two types of information and provide an estimate of the average reservoir pressure that is more reliable than that obtainable solely from either set of data. in time) gives a point marked p. The actual static pressure at the time the well was shut-in is marked by p.. The illustration shows that, even if a build-up curve is available and can be extrapolated, a correction

By S. S. Marsden, S. H. Raza

An experimental study of the flow of line-textured. aqueous foams through Pyrex tubes is described. The foams range in quality F (ratio of gas volume to total volume) from 0.70 to 0.96 and behave like pseudoplastic fluids. At lower flow rates they exhibit laminar flow ad have apparent viscosities which increase with quality, and which cover a range of 15 cp to 255 poise for tubes of 0.25- to 1.50-mm radius rj. At higher flow rates a plug-like type of flow is developed, the extent of which increases with both T and ri. When the same foams flow through either open or packed Pyrex tubes, remarkably high streaming potentials ?E are often generated. These can easily reach 50v if nonionic foaming agents are used, but are at least an order of magnitude less for ionic foaming agents. A linear relationship between ?E and the pressure differential ?p is observed; this usually extrapolates to positive values of ?p at ?E of zero. The slope of the line increases with both F and ri. An equation was derived to describe the streaming potential of non- Newtonian fluids in circular tubes and was used to correlate experimental results. The calculated < potentials are of the right order of magnitude. INTRODUCTION Foams are both unusual and inniguing in their physical properties, and have been the subject of many scientific studies. However, present knowledge of foams is still fragmentary, specific and often contradictory. Apparent viscosity of foam is the physical property of greatest interest to both rheo1ogists and engineers. sibreel reported that the apparent viscosity decreased with increasing shear rate in a manner similar to some non-Newtonian fluids. Penny and Blackman2 reported that fire-fighting foams had both a limiting shear stress and a tensile yield stress. There is little doubt that some foams at least behave like non-Newtonian fluids, and have apparent viscosities considerably higher than those of either constituent phase. The high apparent viscosity of foam with its concomittant effect on mobility ratio and sweep efficiency no doubt prompted several attempts by research groups to use foam as a displacing agent in porous media. Based on recent experience, most of these groups probably succeeded in completely blocking fluid flow in the porous media and then abandoned their efforts. Two groups apparently found the successful combination of experimental parameters at about the same time.3,7 Others have recently added to our knowledge of foam flow in porous media and its use as a displacing agent.8-13 An experimental problem encountered by Fried3 was a transient blockage of foam flow in porous media when distilled water was used to prepare the foam-producing solution. Fried surmised that this was due to an electrokinetic effect and he eliminated it by using electrolytes in preparing foaming solutions. He also measured the streaming potential of a number of foams in capillary tubes which he found to be appreciably higher than those obtained when the constituent liquid flowed under comparable conditions. This paper presents results of a more comprehensive study of the streaming potential generated by aqueous foam flowing in both open and packed Pyrex tubes. It also adds to knowledge of the rheology of these foams as deduced from their flow behavior in open tubes. APPARATUS AND PROCEDURE A diagram of the apparatus used is shown in Fig. 1. Details of its construction, testing and use are described elsewhere.14 Careful selection of materials, extreme cleanliness and rather elaborate electrical insulation and shielding were necessary to obtain reproducible results (±5 percent). Both streaming potential and streaming current were measured with an electrometer. The design of the foam generator developed for this work is novel (Fig. 2). It will produce uniform fine-textured foams at pressures sufficiently

By M. W. Clegg

The application of the Laplace transformation to problems in the flow of compressible fluids in porous media has provided a large number of exact solutions. For plane radial flow, however, these solutions are either complex integrals or infinite series and are of little value to the field engineer. In the case of production at constant well pressure, the available approximate solutions me valid for large times only. In this paper it is shown that an approximate inversion formula for the Laplace transform, developed for the solution of viscoelastic problems, is applicable to radial flow problems and provides simple analytical solutions to constant terminal pressure problems. The method may be used to obtain approximate solutions to many problems, including media with radial permeability discontinuities, multi-layer formations and pressure buildup in wells after shut-in. The results are compared with the few available computer solutions as well as the large time solutions, and it is shown that this approximate method greatly extends the time interval over which a simple analytical solution is acceptable. INTRODUCTION The study of transient problems in the flow of fluids through porous media has benefited greatly from the application of transform methods. The use of the Laplace transformation for solving parabolic equations has been widely discussed in the field of heat conduction and diffusion as well as in the petroleum literature. Removal of the time variable with the Laplace transformation generally reduces the problem to a boundary value problem which may be solved by standard techniques. A much more formidable problem then faces the engineer, however, for frequently the transform does not possess a simple inverse. The result is that the general inversion integral must be used and this leads to either an infinite integral or an infinite series, both of which are difficult to handle from a computational standpoint. Asymptotic approximations for the inverse have been known for some time and these yield approximate inverse functions that are valid for very large or very small times — but frequently the times of interest lie somewhere between these two extremes. Therefore, some acceptable approximation valid over a larger interval of time is desirable. During the past few years a number of methods for achieving this have been developed and some of these are discussed briefly in this paper. The relative merits of the various methods are not evaluated here, but some general conclusions reached by other authors are given. One of these methods has been applied to problems associated with the radial flow of compressible liquids to producing wells. In the case of production at constant well pressure, the method leads to simple analytical solutions for a number of standard problems; e.g., homogeneous formation, permeability discontinuities, pressure buildup. These solutions greatly extend the range of validity of the asymptotic ones (valid for large times only) and should be of value in studying the behavior of wells producing under constant pressure conditions. METHOD FOR THE APPROXIMATE INVERSION OF LAPLACE TRANSFORMS Much of the work that has been done on the approximate inversion of Laplace transforms has originated in viscoelastic problems. Apart from the asymptotic approximations,1 one of the first approximate methods was due to Alfrey.2 If (s) is the Laplace transform of f(t) defined by

By P. Hazebroek, M. Prats, E. E. Allen

Well locations in water floods frequently do not coincide with the ideal well locations associated with the flood pattern which is used. A question of importance is. "How much oil is lost because of this?". This is the problem treated in this paper. It is assumed that each pattern in a five-spot flood has the proper number of production and injection wells but that the wells may be off-pattern. The distance by which a well is off-patern is given in terms of the pattern spacing, defined as the length of one side of a five-spot. The influence of off-pattern wells on the performance of a five-spot flood has been investigated mathematically for unit mobility ratio. All production and injection rates are assumed to remain equal. The loss in recovery resulting from pattern irregularitie: has been calculated at a cumulative water injection corresponding to a 98 per cent water-cut in a regular five-spot. Displacing a single production or injection well by about one-third the pattern distance reduces the total field recovery by 4.4/N per cent of the recovery obtainable with regular spacing, where N is the number of five-spots in the flood (assumed large). When off-pattern wells are separated by at least one regular five-spot and are displaced by less than one-third the pattern distance, the total loss in recovery in a large-scale flood is, at most, 1 per cent of the recovery obtainable from that field with a regular five-spot pattern. However, much higher losses may occur if the off-pattern wells are not separated by a regular five-spot, if the rates are imbalanced, or if the mobility of the injected water is higher than that of the crude. Although the loss in oil recovery due to pattern irregularity often may be low, the off-pattern case will always require injection of more water to reach the same final water-cut. The volume of water injected per unit volume of oil displaced has been calculated for each five-spot adjacent to a five-spot containing a single 08-pattern well. The cumulative water injection at the time of 98 per cent water-cut may be increased by as much as 37 per cent when a production well is displaced one-third the pattern distance toward an injection well. The existence of differences between actual subsurface locations and the idealized well patterns used in secondary recovery operations is well recognized. However, the methods commonly used for predicting waterflood behavior ignore such differences, even when subsurface locations are known. The reason for this is simple. The idealized well patterns are highly symmetrical and, as such, the production history of the pattern (and even of the field) can be determined from that of a few production wells—usually from only one. Consideration of the many irregular well spacings found in a specific field would entail a large amount of work, and then the results would be applicable only to that specific field. In an attempt to provide an answer to the more general problem, this paper considers a water flood having an idealized well pattern, except for one well which is not at its regular location. When several off-pattern wells are present, their contributions are assumed to be additive unless the off-pattern wells are close to each other. Only four positions of the off-center well (at x, y. of Fig. 1) are considered in this paper. These are shown

By E. F. Sumner, C. K. Eilerts

A partial differential equation was developed and programmed to compute the cumulation and flow of the liquid phase of a gas-condensate fluid. It was found that such cumulation near the wellbore may attain saturations permitting liquid flow within periods of the order of 1 day. The radius at which this saturation obtains advances toward the external reservoir boundary with continued recovery, although it may move only 2 to 5 percent of that distance during the productive life of the well. This relatively high saturation can cause a serious dimunition in delivery capacity. The pressure dilferential required for flow of gas through a formation with such saturation may be as much as three times greater than the corresponding differential in a formation where saturation is less than 2 percent. Because of the radial geometry, total reservoir pressure differential required for flow with a zone of relatively high liquid saturation about the well was indicated to be two to three times greater than without the saturation. INTRODUCTION A computing program developed by the authors 1 to integrate the partial differential equation for transient radial flow of gas-condensate fluids required a prevalued function, W(Po) = kD(p0)/M(p0)z0(Po).......(1) related to cumulation of condensate in pores of the reservoir as pressure declines. Methods were available for relating mobility to saturation, saturation to liquid-vapor volume ratio, liquid-vapor volume ratio to pressure and, hence, mobility to pressure to obtain W(pD). However, certain assumptions had to be made in advance of program execution concerning movement of the liquid phase and change in radial distribution of liquid saturation as recovery progressed. Because reservoir fluid mobility and related pressure gradients are markedly dependent on liquid saturation, it was desirable to eliminate the necessity for these assumptions and in this respect improve the reliability of a result obtained by integration. Experimental research was begun to determine the relationship of variables that control the reservoir flow of low liquid-vapor ratio fluids. With the porous medium partly saturated, permeability to a two-phase flowing fluid could not be measured because the viscosity was unknown. Viscosity could not be measured without knowing permeability of the liquid-containing medium; but mobility, the ratio of permeability to viscosity, was measurable. This property, and liquid-vapor volume ratio of the flowing phases, have values determined by nature of the fluid and porous medium and, in addition, were found to be pressure, velocity and saturation dependent. A program developed by Kniazeff and Naville 2 for computing multicom-ponent, two-phase flow used polynomials to represent saturation dependence of permeabilities for gas and for liquid phases, and an effluent viscosity constant under reservoir conditions. The authors developed a program based on a partial differential equation of similar mass balance origin but designed to represent distribution of an unlimited number of components between gas and liquid phases utilizing the experimental information available as to variable dependence. Attention was given to liquid-vapor volume ratio of the flowing phases, a property which is essential as a liquid saturation boundary condition. A program for computing implicitly saturation increase at uniform intervals along the drainage radius was combined with an existing program for calculating pressures, and the two were used alternately in an iterative solution for both saturations and pressures. The function W(pD) needed for calculating pressures was replaced by the ratio of mobility to compressibility factor. BASIC EQUATIONS The partial differential equation for calculating

By G. Rowan, M. W. Clegg

The basic equations for the flow of gases, compressible liquids and incompressible liquids are derived and the full implications of linearising then discussed. Approximate solutions of these equations are obtained by introducing the concept of a disturbed zone around the well, which expands outwards into the reservoir as fluid is produced. Many important and well-established results are deduced in terms of simple functions rather than the infinite series, or numerical solutions normally associated with these problems. The wide range of application of this approach to transient radial flow problems is illustrated with many examples including: gravity drainage of depletion-type reservoirs; multiple well systems; well interference. INTRODUCTION A large number of problems concerning the flow of fluids in oil reservoirs have been solved by both analytical and numerical methods but in almost all cases these solutions have some disadvantages — the analytical ones usually involve rather complex functions (infinite series or infinite integrals) which are difficult to handle, and the numerical ones tend to mask the physical principles underlying the problem. It would seem appropriate, therefore, to try to find approximate analytical solutions to these problems without introducing any further appreciable errors, so that the physical nature of the problem is retained and solutions of comparable accuracy are obtained. One class of problems will be considered in this paper, namely, transient radial flow problems, and it will be shown that approximate analytical solutions of the equations governing radial flow can be obtained, and that these solutions yield comparable results to those calculated numerically and those obtained from "exact" solutions. It will also be shown that the restrictions imposed upon the dependent variable (pressure) are just those which have to be assumed in deriving the usual diffusion-type equations. The method was originally suggested by Guseinov,1 who (a) postulated a disturbed zone in the reservoir, the radius of which increases with time, and (b) replaced the time derivatives in the basic differential equation by its mean value in the disturbed zone. In this paper it is proposed to review the basic theory leading to the equations governing the flow of homogeneous fluids in porous media and to consider the full implications of the approximation introduced in linearising them. The Guseinov-type approximation will then be applied to these equations and the solutions for the flow of compressible and incompressible fluids, and gases in bounded and infinite reservoirs obtained. As an example of the application of this type of approximation, solutions to such problems as production from stratified reservoirs, radial permeability discontinuities; multiple-well systems, and well interference will be given. These solutions agree with many other published results, and in some cases they may be extended to more complex problems without the computational difficulties experienced by other authors. THEORY In order to review the basic theory from a fairly general standpoint it is proposed to limit the idealising assumptions to the minimum necessary for analytical convenience. The assumptions to be made are the following: 1. That the flow is irrotational. 2. That the formation is of constant thickness. 3. Darcy&apos;s Law is valid. 4. The formation is saturated with a single homogeneous fluid.