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By L. C. Reese

The ultimate resistance against a rigid cylinder which is moved laterally in a cohesionless soil is a function of the geometry of the cylinder and the properties of the soil. An approximate method is developed for computing this resistance and is tested against results of laboratory experiments. Satisfactory agreement between the method and experiment was obtained. Not only was the ultimate resistance against the cylinder measured, but measurements were made of the shape of the rupture surfaces. These measurements should allow the development of a more rigorous computation procedure. INTRODUCTION A critical aspect in the design of offshore drilling platforms is assuring the stability of the platform during a hurricane. The large horizontal loads from waves and wind make a severe loading condition. Piles are generally employed as the foundation since they can be effective in resisting both horizontal and vertical loads. Spuds are sometimes used with a mat foundation, where the spuds are designed principally to resist horizontal loads and the mat designed principally to resist vertical loads. The research reported in this paper is related to one aspect of the problem of laterally loaded piles or spuds in sand. The complete solution to the problem of the laterally loaded pile in sand would require the prediction of soil resistance against the pile as a function of pile deflection; only the ultimate resistance against short piles is considered in this paper. A considerable amount of additional research will be necessary in order to obtain a complete solution to the problem of the laterally loaded pile in sand; however, the work reported here should be useful as a guide in the performance of some of the additional research. ULTIMATE LATERAL RESISTANCE AGAINST A LONG FALL IN SAND To aid in the understanding of the theory which is developed for a cylinder, the theory for earth pressure against a wall is reviewed. In Fig. l(a), a long wall of height H is shown embedded in soil. Soil resistance will develop as the wall is deflected, and the soil resistance will increase with deflection until some limiting value is reached. In this discussion, and those following, it is assumed that all points on the wall deflect equal amounts. A possible shape of the real curve which relates soil resistance to deflection is shown by the dashed line in Fig. l(b); however, as a means of simplifying the discussion, an idealized curve (shown by the unbroken lines) is drawn. If such a wall as this were furnishing the horizontal support for an offshore structure, the dashed curve in Fig. 1 would be the information needed in performing a foundation analysis, with the idealized curve possibly being an acceptable substitute. For the idealized curve, the soil resistance is linear with deflection for the early portion of the curve such that

By W. B. Wise, H. D. Attra, W. M. Black

The purpose of this paper is to illustrate a comparatively new approach for solving a problem that has plagued oil producers for many years—how to make the most money with available field production capacity. In a very basic operation such as a top-allowable one-well field, a computer and staff of engineers are not required to determine that the best operation is to produce that well at its maximum for as long a time as it will produce. However, as the problem becomes more complex and the number of wells and number of reservoirs increase, it probably will be a wise choice to devote some engineering thought and calculation time to determine the best way to operate that field on both an ultimate and day-to-day basis. Continued developments in the field broadly referred to as "operations research" have led to a number of useful engineering analyses for optimizing field operational problems. One of these techniques, termed linear programing, is parlicularly interesting because of its potential applications to the study of complex oilfield operating problems. Linear programing is concerned with the problem of planning a complex set of interde~endenl activities in the best possible (optimal) fashion. A field application of linear programing is being used to maximize daily income from a multi-reservoir producing operation. The initial results of this study indicate that the linear programing technique (I) can be applied effectively to field problems, (2) can be used to detect unsuspected avenues for improving operations and (3) can effect a significantly improved means of controlling field operations through the use of the highspeed computer. INTRODUCTION The usual approach for studying complex field operational problems has been to look in detail at several basic plans suggested by judgement and experience and, then, to choose the best plan from those investigated. This approach is entirely satisfactory provided: (1) that judgment and experience alone will reliably pick the best or near the best program as one of the plans to be investigated; and (2), and most important, that the factors which control field production will not change. This paper deals with the large group of field operations which are at least one-step removed from a satisfactory solution using the conventional method of analysis. Problems such as pipeline- and gathering-system design, transportation studies, large field development projects and multi-reservoir producing operations fall in this latter category. To find the best program for handling these problems when the best program is not obvious, a complete optimization study is required, and high-speed computers are required to continually update the program once it is selected. Operations of this type have an extremely large number of possible solutions. However, only one will result in maximum economic return and, more important, this one program must be re-evaluated and adjusted constantly to accomodate such changing field factors as the number of producing days, the price of crude, the discovery of new reserves, declining reservoir pressure with subsequent decline in production and a host of other factors which characterize specific operations. One of the most widely used, direct methods of optimization is a numerical procedure termed "linear programing", which is designed to investigate systematically each of the possible solutions involved in a given problem, determining rapidly and uniquely the optimum answer. As implied by the name, linear programing requires that all field variables be either defined or expressed in a series of interdependent linear equalities or inequalities. These relationships are solved simultaneously, using a form of matrix solutions to determine the optimum values for each producing variable that will maximize net profits. The solution techniques used in a recent field case study is termed the "simplex method" and is discussed in full detail in Ref. 1.

By J. J. Taber

The turbulent flow drag coefficients, or friction factors, have been experimentally determined for the cut-tings normally encountered in drilling operations. The gas law and average drag coefficients for characteristically flat particles (limestones and Shales) and for angular to sub-rounded particles (sandstones) were used to extend Newton's equation to a more useful form. The resulting equations are expressions for the slip velocity of a particle as a function of the particle size and shape, the bottom-hole injection Pressure, and the Bottom-hole temperature. The velocities necessary to lift actual rock cuttings as observed in the laboratory were compared with velocities predicted from the derived equations. Results indicate that there is no single correct circulating velocity and that the commonly used 3,000 ft/min linear velocity may he sufficient to lift only very mall particles. The advantage, in terms of horsepower requirements, of cycling high pressure air to obtain lower compression ratios was shown. INTRODUCTION A promising departure from standard rotary hydraulic drilling is air or gas drilling. In many instances the rate of penetration and bit life increases resulting from this method have been very substantial. Further the application of air drilling in areas of lost circulation or water sensitive pay zones has been highly successful. Purpose For the drilling contractor, the practical question remains, "How much air pressure and volume should I have?' lt is necessary to have a reasonable knowledge of the air velocities and pressures required in air drilling operations for the proper design and most advantageous use of surface equipment and for adequate removal of cuttings from the borehole. Eased on experience, most operators agree that at least 3,000 ft/min linear velocity is necessary for satisfactory hole cleaning.' It was the purpose of this investigation to evaluate the drag coefficients, or friction factors, for the cuttings normally encountered in drilling operations, i.e., sandstones, limestones and shales, and to utilize the values obtained to develop an expression for the minimum velocities and pressures (hence the volumes) necessary to lift these cuttings. THEORY Several investigators have done extensive work on the ability of drilling mud to lift bit cuttings. They conclude that the ability of a drilling mud to lift cuttings is dependent on the density difference between the rock being drilled and the drilling mud, the cutting size and shape, the mud flow constants, and the flow state (laminar, transitional or turbulent) of the mud. However, drilling muds are not true fluids but have a variation of viscosity with velocity in laminar flow and a constant apparent viscosity in turbulent flow. A survey of the literature revealed that no experimental work had been done to determine the velocities necessary to lift actual rock cuttings using a compressible fluid such as air or gas. In 1953, Nicolson6 stated that in air drilling fluid mechanics the particles could be assumed spherical in shape and that ; constant drag coefficient of 0.5 could be used due to the highly turbulent flow of the circulating air. By equating the turbulent resistance on the particle to the gravitational force on the particle, he obtained the expression, ^ = 2.67^y ,.......(1) where V, is slip velocity of spherical particle, ft/sec; D is particle diameter, in.; p, is particle density, 1b/ft8; and p, is fluid density, lb/ft3. However, as stated earlier, most operators seem to agree that adequate hole cleaning can be obtained by circulating a sufficient volume of air to give a linear velocity of 3,000 ft/rnin in the annular space. Basic Equation The velocity with which a solid particle freely falls through a fluid will increase until the accelerating force, gravity, is equal to the resisting forces, buoyancy due to the fluid displaced by the particle and friction due to the relative motion of the particle through the fluid. When the accelerating and resisting forces become equal,

By H. R. Crawford, P. B. Crawford, A. F. Tragesser

A method has been developed to calculate wellbore temperatures during mud circulation and the actual cementing operation to aid in the design of cement slurries. The method agrees within 10F with previously measured values. The calculation technique provides temperatures, as functions of time, at varying depths in both the casing and annulus. The technique also provides this information if a relatively cool cement slurry is pumped into the well immediately following circulation of hot mud. Circulating bottom hole temperatures of brine and a bentonite mud were measured. INTRODUCTION As wells are drilled deeper, greater demands are being made on all phases of the industry, and new technology has been developed to provide satisfactory well completions. However, little or no work has been conducted on accurately determining bottom-hole, static and circulating temperatures.. In designing a cement slurry, such factors as density, fluid loss control, viscosity, deterioration from ternperature, compressive strength and pumping time must be considered. Individual well conditions often make it necessary to include still other factors. Pumping time is a primary consideration and, as wells are drilled deeper, encountering higher bottom-hole temperatures, this property becomes even more important. Cement slurries must be designed with sufficient pumping time to provide safe placement in the well; however, the slurry cannot be overly retarded as this will prevent the development of satisfactory compressive strength. The pumping time of a specific cement is currently obtained by subjecting the cement to simulated conditions of temperature and pressure. A reasonably accurate bottom-hole pressure may be obtained by considering hydrostatic heads of fluids, friction pressure and wellhead pressures. However, accurately determining bottom-hole temperatures is much more difficult. Bottom-hole static temperatures are estimated by considering several sources of information, including logging temperatures, published temperature gradient maps and field experience. This information is usually questionable due to disagreement of data from the various sources. Temperature gradient maps were constructed based on temperatures recorded many years ago while running bottom-hole pressure tests. These thermal gradients then represent an average of well conditions and cannot always apply to a specific well. Also, logging temperatures may be affected by the time since fluid was last circulated, rate of penetration, circulating rate and many other factors. Therefore, even though logging temperatures are available, the question still exists as to the correction factor that should be applied to obtain an accurate static temperature. After obtaining static bottom-hole temperature, it is then necessary to relate this to circulating temperatures actually encountered by the cement slurry. This is accomplished by selecting a test schedule from the API RP-10B corresponding to the estimated well conditions.' The API-recommended practice for testing oilwell cement provides testing schedules for various well depths and conditions. These schedules are intended to simulate down-hole conditions during cementing. They provide a rate at which both temperature and pressure are increased until the estimated circulating conditions are reached. These testing schedules represent circulating temperatures for an average well and, although there is flexibility in choosing the test schedule that most accurately simulates the temperature of an individual well, it still is not possible to consider all the well conditions that will affect the bottom-hole temperature. Many factors affect cement temperatures; for example, the length of time a well has remained static prior to running casing and cementing, the circulation time, the temperature of fluids used in cementing, fluid density and flow properties of fluids. The pumping time for a typical retarded cement could vary from 2 to 4 hours with a 10F change in testing temperature. Variations in pumping time are the most critical in highly retarded cements used in deep, hot wells; yet, predicting bottom-hole circulating temperatures is more difficult in these wells. This work was conducted to develop a means of calculating circulating temperatures as a function of well depth, casing and hole size, pumping rate and time, fluid and reservoir physical properties and thermal status of the well. PREVIOUS WORK In 1941 Farris reported on a study to develop information leading to a more practical laboratory evaluation of oilfield cementing mixtures and performance.' It was then recognized that the pressure factor was being neglected,

By A. B. Kinzel

Since the exposition of the behavior of certain iron alloys by Sykesl involving the existence of an austenite loop and the discovery of such a loop in the chrome-iron system by Bain,2 there has been much conjecture both on his part and on the part of metallurgists in general as to the exact shape and location of this loop. In previous work commercial steel has been used and the microscope has been employed to locate the critical points so that the position of the loop has been quite approximate. Numerous attempts have been made to measure the critical points of the carbon-free alloys but all of these for one reason or another have failed. A satisfactory method for studying these phenomena is presented here. MateRial The first difficulty in this study was to obtain pure chromium-iron alloys. This has been overcome by melting in a vacuum electrolytic iron and chromium analyzing 99.84 Cr, Fe and C. A pure magnesite crucible was used and the melt allowed to solidify in the crucible. A typical analysis is chromium, 10.10 per cent., carbon, 0.006 per cent., silicon and manganese nil. To overcome the problem presented by segregation, ingots were made into wire 0.04 in. in diameter. This was accomplished by hand-forging the ingots into rods, using an oxyhydrogen flame for heating, in order to avoid carbon. Subsequently the rods were swaged to wire, the heating being carried out in hydrogen. Thus local segregation was eliminated although differences in analysis between portions 50 ft. apart were noted. An electric-resistance method was first tried to determine the critical points, but due to the physical defects in the wire this failed. Bain had previously shown the presence or absence of critical points in a qualitative way by observing the sag in a catenary. The author has devised the following method which gives an accurate determination of the critical points from expansion-temperature curves of suspended wire, a special telescopic dilatometer being used for the purpose.

By D. B. Robinson, C. A. Macrygeorgos, G. W. Govier

Experimental data have been obtained on the volurrletric behavior of ternary mixtures of methane, hydrogen sulfide and carbon dioxide at temperalures of 40°, 100" and 160°F up to pressures of 3,000 psia. The results indicate that the compressibility factors for this system do not agree with compressibility factors for sweet natural gases at the same pseudo-reduced conditions. The deviation increases as the temperature and methane content decrease. Discrepancies of up to 35 per cent were observed. A careful analysis has been made of the existing pUrblished data on compressibility factors for binary systems containing light hydrocnrbons and hydrogen sulfide or carbon dioxide. It has been found that the deviation of actual from predicted compressibility factors for methane-acid gas mixtures is a function of the methane content and the pseudo-critical properties,.v of the mixture. The ratio between actual compressibility factors for methane-acid gas mixtures and compressibility factors for sweet natrlral gases at the same pseudo-reduced conditions has been currelated over a range of pP,, from 0 to at least 7 arid a range of pT, from about 1.15 to at 1east 2 0 with an error not exceeding 3 per cent and over most of the range within I per cent. The validity of the correlation for mixtures containing appreciable hearvier hydrocorbons has not been fully established, but it is shown to be preferable than the use of a corretation based only on hydrocarbons. INTRODUCTION Although a relatively accurate method for predicting compressibility factors of pure materials is provided by charts based on reduced properties and the assumption that the compressibility factor is a unique function of T P and z the determination of the correct values of compressibility factors for gas mixtures is somewhat difficult. Two general methods of dealing with gaseous mixtures have been proposed. The first assumes a direct or modified additivity of certain properties of the mixture in terms of the properties of the individual components. Examples of this method are based on the familiar laws of Dalton and Amagat. The second method averages the constants of an equation of state applicable to the pure components. Both of these methods are of limited value in engineering calculations because the first usually provides reliable answers only over narrow ranges of pressure and temperature and the second is cumbersome to handle. In petroleum engineering practice accurate estimations of the volumetric behavior of natural gases arc frequently required. To fulfill this need, several generalized compressibility charts have been developed.' ' Of these, the one prepared by Standing, el al is widely used at present. In the construction of charts of this type a third method for dealing with mixtures has been followed. It is based on correlation of pseudo-critical properties as outlined by Kay and calculated from the critical properties of the individual components in a mixture. Although these charts provide relatively accurate information on the compressibility of dry or wet sweet natural gases, they are less reliable when used for gases containing high concentrations of hydrogen sulfide or carbon dioxide or both. Thus, an experimental program, although time consuming, is the best means now available for the determination of the volumetric behavior of sour or acid gas mixtures. An increased interest in the behavior of these gas mixtures, particularly in connection with some of the fields in Western Canada where the acid gas concentration of the reservoirs may be as high as 55 per cent and where hydrogen sulfide alone may be as high as 36 per cent, provided the incentive for this study. It was the purpose of the investigation to determine the volumetric behavior of selected mixtures of methane, hydrogen sulfide and carbon dioxide over a range of temperature from 40" to 160°F and at pressures up to 3,000 psi. EXPERIMENTAL METHOD The apparatus used in this investigation was basically the same as that described by Lorenzo.'" The amount of each pure component used in preparing the gas mixtures was measured over mercury in a glass-windowed pressure vessel. The pure components were then transferred individually in the desired amounts to a second glass-windowed pressure vessel where the volumetric behavior of the mixture was determined. Volume was varied by mercury injection or withdrawal. The capacity of the cell was about 125 cc. Temperatures in the cells were measured with copper-constantan thermocouples and a Leeds Northrup semi-

By R. E. Holmes, T. W. Leland

The solution to the unsteady-state mass- and heat-transfer equations describing the adsorption of a dilute component from a gas stream flowing through a packed bed is readily applicable to the design of hydrocarbon recovery units. The solution to these equations depends on the assumption of a linear equilibrium equation to relate concentrations on the surface to concentrations in the gas. This assumption is shown to be justifiable for components which are very dilute in the gas stream. This approach permits the prediction of the effects of bed shape and size, cycle time, and gas mass velocity on the recovery of each component. It also allows the time and gas flow rate needed for regeneration to be determined. The equations involve a constant for each component and another constant characterized by the type of adsorbent. These constants must be evaluated from operating data. Values of these constants determined for silica gel are presented. This paper points out the type of experitrrental data needed for a thorough design of hydrocarbon adsorption units. INTRODUCTION The growing importance of adsorption processes to recover hydrocarbons from natural-gas streams has created an urgent need for better methods to design and predict the performance of these processes. Since the original use of solid adsorbents in natural-gas processing was for dehydration, most of the current design methods for hydrocarbon recovery re extensions of those developed earlier for dehydration. These methods are based on an adsorptivity or bed loading factor defined as the amount of a particular component adsorbed per unit weight or per unit volume of the packed bed. The recovery of a given component is then expressed as an empirical function of its adsorptivity on a given adsorbent. In spite of the simplicity and initial utility of these methods, they are not completely satisfactory in that they do not predict the effect of the dimensions of the bed in relation to flow rate and cycle time, and do not predict the distribution of various components along the length of the bed. It is possible, however, to make a considerable improvement in the design of these processes by applying the basic equations of mass and heat transfer applicable to gases containing small concentrations of adsorbing components flowing through granular beds. These equations have been developed and solved by Anzelius,' Furnas,% nd Hougen and Marshall." where G = mass velocity of the inert constituents (assumed to be methane), lb/hr-sq ft, y = weight of an adsorbing component in the gas per unit weight of inert, lb of a given constituent per lb of methane, x = bed length, ft, p, = packed bed density, lb/cu ft, P, = gas density, Ib/cu ft, f = void fraction in the bed, t = time, hours, and w = weight of a given component adsorbed per unit weight of adsorbate free solid, Ib/lb pure adsorbent. The term on the left side of Eq. 1 represents the flow rate per unit bed volume of a component entering less the flow rate per unit bed volume of that component leaving the differential bed length. The terms on the right side represent, respectively, the accumulation rates per unit bed volume on the solid and in the gas phase within the differential bed section. The last term is negligible for this application since pgfv is quite small in comparison with p, and G. The partial differential is determined by the mass-transfer rate between gas and solid in the differential section.

By J. L. Fitch, B. G. Hurd

The presence of gypsum in samples subjected to standard core analysis introduces serious errors in the measurement of water saturation and porosity. The magnitude of these errors, depending upon the type of analysis procedure used, has been evaluated experimentally and theoretically. Water-saturated pore volumes determined by vacuum distillation or retort procedures may be too high by as much as 48 per cent of the volume of gypsum present. The maximum error in this value determined by Dean-Stark extraction with toluene is 36 per cent of the gypsum volume. If pore space is measured by a Boyle's law type porosimeter the maximum erorr due to gypsum is 38 per cent of the original gypsum volume present. The conscientious core analyst may eliminate the errors caused by gypsum by either of two methods. He may apply suitable corrections for the water of crystallization removed from gypsum, or take special precautions to prevent dehydration of gypsum during core cleaning and alzalysis procedures. These alternatives are discussed and methods for obtaining reliable core analysis data are proposed. Gypsum (CaSO4 . 2H2O) occurs as a common mineral in many of the world's sedimentary basins. In addition to its presence as primary bedded evaporitic deposits, it is often found as secondary replacement zones and pore-fillings in host rocks. That it may cause false indications in porosity, both on neutron logs and in standard core analysis, has been generally recognized. False porosity interpretations from neutron logs result because the chemically bound water in gypsum attenuates neutrons as effectively as free water. Errors in core analysis result when gypsum is dehydrated prior to or during the analysis. Vacuum retort procedures used by many laboratories to determine fluid saturation and porosity effect a complete removal of water of crystallization from gypsum. The crystal water, distilled and collected with free water from the sample, is counted as water-sat11rated pore space. Dehydration of gypsum results in a decrease in volume occupied by calcium sulfate and a corresponding increase in pore volume. Thus, if gypsum is dehydrated by sample cleaning and drying procedures, subsequent porosity measurements with gas expansion or compression instruments will be high. The qualitative effect of gypsum on porosity determinations by retort procedures was discussed in a recent article by Bynum and Koepl3. They concluded that since false porosity was interpreted as being water saturated, determinations of oil content were not affected. Others in the industry, however, have pointed out that porosity values are often used with values of water saturation determined independently, e.g., from electric resistivity logs in making reserve estimates. Values of water saturation calculated from the formation resistivity using the Archie equation, S4= are actually low if values of are high due to gypsum. In this case, false porosity values due to gypsum could cause serious errors in calculations of oil-in-place. This investigation was made to determine quantitatively the effect of gypsum on porosity values determined by different core analysis procedures. EXPERIMENTAL PROCEDURES Dehydration of Gypsum The extent and rate of removal of water of crystallization from gypsum under conditions encountered in core analysis procedures were studied. Taken for the experiments were three types of relatively pure, naturally occurring gypsum, viz. selenite, satin spar and massive gypsum. Although all samples probably contained trace chemical impurities, each type lost the theoretical amount of water upon complete dehydration. An automatic recording thermobalance, similar to one described by Mauer2, was used to obtain dehydration rate data for samples heated in dry air. Water

By G. W. Tracy, R. D. Carter

A method based on an approach by Hurst' is developed for calculating water influx behavior. Using this method, superposition calculations may be eliminated. The principal diflerence between this method and that of Hurst is that, over finite intervals of time, constant oil-productton rates are assumed by Hurst whereas constant water influx rates are assumed in the presently described method. By adopting the assumption of constant water influx rate for finite time periods, a method is developed for calculating water influx behavior which lends itself to convenient combination with the material balance equation in the Schilthuis form. Above the bubble point, an equation is given for the explicit step-wise calculation of pressure history for a prescribed oil-production history. Use of this method of calculating water influx behavior should result in a considerable saving of time as compared to superposition calculations when the calculations must be made without using a digital computer. The connection is shown between the method described herein and the method developed by van Ever-dingen and Hursr2 (which requires superposition cal-culations). Also, results obtained using the two methods are compared.

By I. Fatt

A recently developed system for measuring electrical resistivity of liquids without use of electrodes offers some interesting possibilities in electric logging technology. The equipment as supplied by the manufacturer is satisfactory for continuous mud logging on a drilling rig or for measuring mud or filtrate resistivity in the laboratory. A simple modification of the commercially available instrument makes it suitable for measuring resistivity of core samples in the laboratory. The continuous measurement of mud resistivity on a drilling rig is a convenient means for detecting mixing of formation water with the drilling mud. Such information is useful to the geologist, the mud engineer and the logging engineer. However, continuous mud resistivity logging by conventional electrode-type resistivity cells is beset with difficulties. The mud, sand and rock chips abrade the electrodes, thereby changing the cell constant and eventually destroying the cell. Also, additives and crude oil in the mud may poison the electrodes by coating them with a nonconductive material. An electrode-type resistivity cell. therefore, may give erroneous readings under certain conditions. Electric logging companies circumvent the electrode poisoning problem by using a four-electrode resistivity cell for measurement of mud resistivity. In this cell, change in electrode area does not change the cell constant. However, the four-electrode cell is difficult to adapt for continuous reading and does not solve completely the problem of electrode abrasion by the sand and cuttings in the mud. The measurement of electric logging parameters on core samples in the laboratory encounters some of the same problems discussed in connection with mud logging. Ideally, the electrical resistivity of a core sample should be measured by placing platinum black electrodes in direct contact with the plane ends of a cylindrical or rectangular sample. Platinum black electrodes however, are much too fragile and easily abraded to be brought in contact with a rock sample. Also, oil or other constituents in the fluid contained in the sample will poison platinum black. In practice, gold-plated brass electrodes, in an AC bridge circuit operating at about 1,000 cps, are used for routine core analysis. For more precise work in research studies, a four-electrode scheme is used.',' Preparation of the samples for the four-electrode method is much too involved for routine core analysis. An apparatus for measuring resistivity of liquids without use of electrodes was described by Guthrie and Boys3 in 1879. They suspended a beaker, containing the electrolyte, by a torsion wire and rotated a set of permanent bar magnets around the vessel. The eddy currents induced in the electrolyte reacted against the rotating magnetic field to develop a torque, which was measured as a deflection of the torsion wire. In 1879 this method could not be made precise or convenient because of the lack of strong permanent magnets. The writer described a very greatly improved apparatus similar to that of Guthrie and Boys, but it was not suitable for continuous measurements or core samples.' Many electrodeless resistivity devices using radio frequency current are described in the literature.5, 6 These generally are suitable only for noting the end-point in a chemical titration. They do not measure resistivity, instead measuring a complex quantity which includes the dielectric constant and the magnetic permeability. The first description of the apparatus to be discussed in this paper was given by Relis.7 Improvements and modifications are described by Fielden,s Gupta and Hills,> and Eichholz and Bettens.10 DESCRIPTION OF APPARATUS The apparatus used in this study is based on the principle that the solution under measurement can form a loop coupling two transformer coils, as shown in Fig. 1. For a fixed AC voltage applied across Coil A, the voltage appearing across Coil B is a function of the resistance of the liquid-filled loop. The details of the voltage generating and measuring circuits are given in Refs. 7, 8, 9 and 10. A block diagram of the equipment is given in Fig. 7. Special features worth mentioning are the operating frequency of 18,000 cps and the automatic temperature compensation which results in the given resistivity readings being automatically correlated to 25°C. The liquid loop supplied by the manufacturer, shown in Figs. 1 and 2, was modified for use in core analysis (Fig. 3). The core sample under test is substituted for a section of the original loop. As shown in Fig. 3, the unit accepts only plastic-mounted cylindrical core specimens. A Hassler-type sleeve easily can be designed for the unit if unmounted cores are to be measured. EXPERIMENTAL PROCEDURE MUD LOGGING A simulated mud line was set up in the laboratory.

By F. M. Perkins, R. H. Jamison

Publications concerning scaling laws for laboratory flow models of oil reservoirs indicate that the relative permeability and capillary pressure relations must be the same functions of saturation in the model and its prototype. In this paper, the relative permeabilities and saturations are redefined in a way which permits one to have diflerent relative permeability and capillary pressure relations in the model and prototype. The development of the new scaling criteria is demonstrated by deriving scaling laws for one simple flow problem. INTRODUCTION The successful application of information gathered through bench-scale model studies to the prediction of multi-phase fluid flow behavior in petroleum reservoirs requires careful consideration of the scaling criteria. The requirements which must be met for a small-scale model to duplicate the behavior of a much larger reservoir prototype have been discussed by Leverett, et al,' Rapoport,2 and Geertsma, et al.3 According to these authors, the relative permeabilities to water, oil and gas and the dimensionless capillary pressures must be the must have the same values in the model and prototype. Furthermore, they point out that the viscosity ratios must have the same values in the model and prototype. In addition to these requirements, other scaling criteria are given which, when considered, usually dictate a much higher permeability in the model than exists in the reservoir. Since the more permeable model sands may have connate-water and residual oil saturations quite different from those in the prototype, the scaling requirements pertaining to the dependence of relative permeabilities and dimension l ess capillary pressures on saturation usually are not met. Also, if the model fluids are selected to give equal viscosity ratios in the model and prototype, one may find greatly different mobility ratios* in the two cases and, therefore, may expect grossly different flow patterns. For this reason, Craig, et al,' correlated the results of their model studies with mo- bility ratio rather than with viscosity ratio. As yet, however, no satisfactory method has been advanced which permits use of anything other than the scaling requirements outlined in the previously mentioned papers. The purpose of this paper is to present a method of developing a set of scaling criteria which permits different relationships between saturation and relative permeability or capillary pressure in the model and prototype. Rather than attempt to report scaling criteria for a variety of practical situations, this paper demonstrates by use of one simple example how the modified scaling criteria are derived.

By J. S. Levine, M. Prats

A homogeneous and uniform cylindrical reservoir containing oil and gas is fractured vertically on completion and is produced at a constant bottom-hole pressure. The fracture has an infinite flow capacity, is of limited lateral extent and is bounded above and below by the impermeable strata defining the vertical extent of the reservoir. Results show that such a fractured reservoir can be represented by a reservoir of circular symmetry having very nearly the same production history. The well radius of this circular reservoir is about 1/4 the fracture length and is essentially the same as that obtained previously for a single fluid of constant compressibility. At the same value of cumulative oil production, gas-oil ratios of fractured reservoirs producing at constant terzinal pressure are larger than those of reservoirs having no fractures. This leads to more inefficient use of the reservoir energy in fractured wells and results in lower reservoir pressures for the same cumulative oil production. The reduction in operating life due to fracturing a reservoir is not as great as that for a slightly compressible fluid. This diflerence can be accounted for by the lower reservoir pressure in the fractured reservoir and its adverse effect on the average mobility and compressibility of the oil. As anticipated, the reduction in operating life increases czs the reservoir permeability decreases. The type of results presented in this report can be used to determine the economic attractiveness of fracture treatments per se, to setect the initial spacing to be used in developing a field, and to compare the relative merits of fracturing available wells and infill drilling. INTRODUCTION The effect of vertical fractures on a reservoir producing either an incompressible or a compressible liquid has already been discussed in the 1iterature.l,2 Those results indicate that the production history of such a reservoir is essentially the same as that of a circular reservoir having an effective well radius of approximately one-fourth the fracture length. The present work reports on the effect of a vertical fracture on a reservoir producing two compressible fluids —oil and gas—by solution gas drive. Because of the empirical nature of the PVT and relative permeability data used to obtain the performance of such reservoirs, results can only be obtained numerically and with the aid of high-speed computers. Since reservoirs lose their radial symmetry when fractured vertically, pressure and saturation can no longer be given only in terms of distance from the well. Two coordinates (such as x and y) must now be used to describe the pressure and saturation within the reservoir, and, since we are dealing with compressible fluids, time is also a variable. Thus the solution of a vertically fractured reservoir requires finding two unknowns (pressure and saturation) in two space variables (say x and y) and in time (t). Since no means are readily and generally available for solving such problems at the present time, we have used the results of previous work1,2 to approximate the effect of a vertical fracture on a reservoir producing both oil and gas by depletion. The purpose of the present wmk, then, is to investigate the possibility of using available numerical techniques (limited at the moment to one space variable) to study the two-space-variable flow behavior resulting from a vertical fracture. Results obtained in the course of this investigation are also reported and discussed. Input and output data of the numerical methods used are given in practical units: BOPD, feet, psi, cp, and md. Results are discussed fist in terms of specific reservoir and crude properties and geometries. Later, dimensionless parameters are introduced in order to extend results to different values of some of the reservoir and fracture properties. IDEALIZATION AND DESCRIPTION OF THE FRACTURED SYSTEM It is assumed that a horizontal oil-producing layer of constant thickness and of uniform porosity and permeability is bounded above and below by impermeable strata. The reservoir has an impermeable, circular, cylindrical outer boundary of radius r,. The fracture system is represented by a single, plane, vertical fracture of limited radial extent, bounded by the impermeable matrix above and below' the producing layer (reservoir). It is assumed that there is no pressure drop in the fracture due to fluid flow. 1 indicates the general three-dimensional geometry of the fractured reservoir. Gravity effects and the effects of differential depletion resulting from variations in hydrostatic head (pressure) will be neglected. Thus, the flow behavior in the fractured reservoir is described by the

By J. B. Agan, R. J. Fernandes

This paper utilizes the layered-system approach, modified to include areal sweep efficiency, to determine the miscible-slug size required and to predict the perfort7zance of a miscible-slug process in a highly stratified reservoir having a permeability variation of 0.76. The slug size in each layer was determined from theoretical calculations and laboratory data which showed that, to maintain miscibility in the reservoir, the slug size had to be 8.2 per cent of the floodable hydrocarbon pore volume. Economic considerations, however, such as the value of the miscible product injected, the cost of injection and the cost of reprocessing the miscible product, limited the amount of miscible product which could be injected into the lower-permeability layers. This resulted in subjecting only 60 per cent of the reservoir to a slug size sufficient to maintain miscibility. Utilizing the relationship of producing gas-oil ratio and areal sweep efficiency as a function of pore volume injected (as obtained from data published by Dyes, Caudle and Erickson2), the theoretical performance was determined. This prediction is compared with actual performance to date. Actual performance reflects an increasing percentage of tniscible product in the produced fluid to a particular level, which remains static for a short period and then increases again to a higher level. This performance suggests that the reservoir has performed as a layered system. It is concluded that the layered-system approach can be used to predict performance in a highly stratified reservoir and that economic consideration is a limiting factor in determining the amount of the reservoir which can be miscibly swept. INTRODUCTION The Paloma zone in the Paloma oil field, Kern County, Calif., is comprised of several sand members separated by siltstone, shale and/or cherty sections. Rapid facies changes within the zone indicate that the sediments were deposited in a "near shore" environment. As a result, the Paloma sands have a high permeability variation, and the Paloma zone is comprised of several sand reservoirs. Since one of the sand reservoirs containing crude oil was not receiving the benefits of gas injection, consideration was given to recompleting certain wells to isolate the sand in order to perform a miscible-phase injection project and, thereby, to increase its ultimate oil recovery. Before proceeding with the project, a review of the literature was made to determine the miscible-slug size that would be required to maintain miscibility throughout the displacement process. Although the review showed that considerable information was available for homogeneous systems, insufficient information was available to determine slug-size requirements and to predict performances for a highly stratified reservoir. This paper has been prepared to describe the method used to determine the miscible-slug-size requirement and to predict the performance of the miscible-phase injection project initiated in the Paloma oil field. Although the Paloma project has only been in operation since Aug., 1958, sufficient production history has been obtained so that a comparison can be made with the predicted performance. DESCRIPTION OF RESERVOIR The reservoir in which the miscible-phase project was initiated in the Paloma field is shown on Figs. 1 and 2. Reservoir properties are as follows: average sand thickness, 43 ft; porosity, 19.1 per cent; water saturation, 47.2 per cent: oil viscosity, 0.328 cp; reservoir temperature, 250°F; reservoir pressure, 3,500 psi: gas saturation, 21.2 per cent at time of miscible product injection; and total net hydrocarbon pore volume, 19,993,000 reservoir bbl. LIMITATIONS The method described herein utilizes a layer-system approach, where injection into and production from each layer is assumed to be proportional to the layer's fractional capacity. The effects of increased fluid mobility on injection and production rates, in layers which have had breakthrough, are not reflected in this method. There has been considerable controversy over the slug size necessary to maintain miscibility throughout the displacement process. In this method, the slug-size

By J. M. Gaines, C. H. Herty

IRon oxide (FeO) plays an extremely important part in the manufacture of steel. In the open-hearth furnace and the Bessemer converter it is the chemically predominant compound and controls to a large extent both the operation of the furnaces and the composition and quality of their products. Almost all of the refining action is carried out through the medium of FeO, which oxidizes carbon, manganese, silicon and phosphorus. At the end of any open-hearth or Bessemer heat the steel contains dissolved iron oxide, which must be wholly or partly eliminated. The type of deoxidation product depends on the amount of dissolved iron oxide and on the deoxidizer used. After the heat has been deoxidized and while it is being teemed, iron oxide diffuses from the ladle slag into the metal, causing losses of deoxidizer and increase in iron oxide content of the steel. It is generally believed that non-metallic inclusions are responsible for a great many failures of steel in service and for decreased yield of steel during rolling. The basis of most non-metallic inclusions is dissolved iron oxide. This investigation was undertaken in order to determine the amount of iron oxide that will dissolve in iron under various conditions. Steel-making slags are complex and it has been thought best to determine solubility under simple slags as a first step. The study is being continued under slags whose compositions approach those of operating slags Previous Investigations The solubility of oxygen in iron has been determined by a number of investigators (see Table 1) but their effort's have been directed toward the

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

A system of partial differential equations describing miscible displacement of fluids in porous media is derived The system takes into account the influence of gravity, the spatial distribution of permeability, diffusion, and fluid viscosities and densities. A numerical procedure for approximating solutions to the differential systems has been tested for a horizontal two-dimensional geometry. In end-to-end displacements of oil with less-viscous solvents, the numerical solutions exhibited fingering qualitatively similar to that observed in laboratory models. Small random spatial variations in permeability about the mean value are sufficient to initiate fingering. Quantitative comparisons of computed results with laboratory data show good agreement. INTRODUCTION Miscible flooding of oil by solvent is receiving increasing consideration for field use.1-4 Unfortunately, such floods potentially present severe problems in loss of recovery through the by-passing of oil by expensive solvent. Consequently, their economic evaluation requires sound techniques for predicting recovery. The purposes of this work are to present a finite-difference method for calculating the multidimensional displacement of oil by solvent and to investigate the validity of the method by comparing results of calculations with data from displacements in laboratory models.5 The formulation of the method to simulate the model experiments treats a case of limited scope in the description of solvent flooding in the reservoir. The model experiments were carried out with fluids that were assumed to form an incompressible, ideal, two-component system with constant diffusivity. Establishing the validity of the method even in its present form provides a major step toward the goal of quantitatively evaluating individual solvent flooding projects. First, it demonstrates the fea- sibility of calculating the course of displacements which are dominated by an inherent macroscopic instability, i.e., viscous fingering. In addition, the method provides almost the only practical means of examining the effect of the size and extent of reservoir inhomogeneities on the development and propagation of the fingers, taking into account the important influences of diffusion and gravitational segregation. It might be inferred that such studies cannot yield results of practical value because in displacements dominated by macroscopic instability the pattern of finger development and the resulting performance should depend critically on small variations in the geometric distribution of reservoir inhomogeneities. The present method offers the capability inherent in computational techniques of predicting performance reproducibly with any arbitrary distribution of reservoir properties and, as such, provides a means of evaluating the sensitivity of behavior to uncertainties in reservoir definition and, thus, assessing the reliability of prediction of performance. THE PHYSICAL PROBLEM DATA USED FOR QUANTITATIVE TESTS OF CALCULATIONS In this work, a calculation for treating the miscible-displacement process is tested by comparing calculated results with experimental data. The experiments chosen for comparison have been described in detail,5 and the quantitative features are summarized in a later section. Briefly, oil was flooded by solvent of equal density from a thin rectangular channel in Lucite packed with uniform Ottawa sand. Under these conditions, two-dimensional geometry is considered adequate to represent the process. Inasmuch as the present work is concerned with testing of the method by comparison with specific two-dimensional data, the system of equations presented in the succeeding section will be oriented to defining the physical system specifically. THE DIFFERENTIAL EQUATIONS Suppose x, y to be a Cartesian co-ordinate system and define h(x, y) to be the height of a point above a horizontal reference plane. It will be assumed

By E. F. Johnson, F. H. Brinkman, H. J. Welge, A. L. Hicks

A method is presented for predicting the character of gas or water displacement in a radial system, which can be either horizontal or inclined. The latter case would comprise cone-shaped or dome-shaped symmetry. The method conriders the one dimension of radial distance, taken parallel to the bedding planes. Approximate allowance can be made for segregation of the two fluids perpendicular to the bedding planes. A complete saturation history can be obtained in about a day's time with the use of a desk calculator. Results of an example calculation agree well with the performance of simulated gas drive in a large model representing a section of a cone. This pie-shaped, sand-packed model was 8-ft long and 4-in. thick. The method of solution is useful in handling other partial differential equations of first order and first degree. INTRODUCTION A new analytical method has been developed for predicting the performance of gas or water drive in a reservoir having radial or cone-shaped symmetry (see Fig. 1). In addition, this new development offers a general method of handling partial differential equations of first order and first degree. This work extends those methods developed previously'- "or predicting the displacement of oil by gas or water in linear systems. The method of calculating oil recovery in a radial system involves two major parts. The first part is a calculation of the distribution of saturations at various times of depletion. The second part is the calculation of oil recovery and producing gas-oil or water-oil ratios through volumetric balance on the saturation distributions obtained in the first part. This second part differs only slightly in principle from similar calculations made with linear systems, for instance. The basic assumptions used in the calculations are as follows. 1. One-dimensional radial flow. An approach is explained later for approximating a second vertical dimension. (With- drawals of oil, and of the driving fluid after breakthrough, are assumed uniform around the periphery of the dome.) 2. Constant-volume fluid flow. Thus, in a gas drive there is no change in gas solubility, or in oil or gas volume due to viscous and gravity pressure drops. 3. Capillary forces are negligible. 4. Constant rate of injection. A program has been written for carrying out the calculations needed on a digital computer. However, a prediction can also be arrived at using a desk calculator; this latter method of work requires about a day's time for each prediction made. CALCULATION OF SATURATION DISTRIBUTION For definiteness, we describe the development of our method for the case of gas drive from the crest of the structure. The reader will note, however, that the method is just as applicable to an advancing radial water drive. The equation describing gas flow over an infinitesimal

By H. N. Hall

Various factors must be considered in an engineering evaluation of gravity-drainage reservoirs. Among these are: (1) the effect of producing rate on total oil recovery; (2) the effect upon well productivity and ultimate recovery of the pressure level maintained during the producing life of the reservoir; (3) the economic advantage of full or partial pressure maintenance; and (4) estimate of the rate of gas production and injection and the possible purchase of gas under conditions of full pressure maintenance to ascertain compressor facilities needed. All of these factors can be evaluated only when a reliable method is employed for determining reservoir performance in gravity-drainage reservoirs. The purpose of this paper is to present a general method for calculating the performance of a gravity-drainage reservoir. This method is applicable for conditions of complete pressure maintenance, partial pressure maintenance and normal pressure depletion. Provisions are made to take into account variations throughout the reservoir of reservoir configuration, changes in permeability and fluid composition. Based on the method presented in this paper, an IBM 650 computer program has been developed. The past performance of an actual gravity-drainage reservoir producing under conditions of declining pressure and no gas injection was duplicated using this program. INTRODUCTION In tilted reservoirs the production of oil is influenced by drainage of oil from upstructure to downstructure locations. When this downstructure drainage of oil is sufficient to cause effective segregation of the gas and oil in a reservoir, the reservoir is usually classified as a segregation drive or gravity-drainage reservoir. (Discussion will be restricted to gravity-drainage reservoirs which have no encroachment of edge water.) The important feature in gravity-drainage reservoirs is the density difference between reservoir oil and gas. These phases tend to segregate in the reservoir with the result that in the gas cap the oil saturation is maintained at a higher level by drainage of oil from the gas-cap area. Oil can be produced from the oil zone at a low gas-oil ratio and reservoir energy is thereby conserved. The standard material balance in not adequate for predicting gravity-dramage reservoir performance because it does not take into account the difference in saturation above and below the gas-oil contact. Several authors'.' have presented methods for calculating the performance of gravity-drainage reservoirs in which reservoir pressure is maintained constant by gas injection into the gas cap. Using some simplifying assumptions, these methods can be employed with a desk calculator to give acceptable results. The problem of predicting the performance of gravity-drainage reservoirs under the conditions of declining reservoir pressure is many time more complex than that of constant pressure. fierefore, attempis to develop a method suitable for desk calculation have required excessively simplified assumptions. In the past several years, highspeed digital computers have become more widely available for reservoir engineering problems. These corn puters are well suited to problems such as the prediction of the performance of gravity-drainage reservoirs with pressure decline. Many of the simplifying assumptions necessary for hand computation can be eliminated so that a realistic approach to the gravity-drainage process can be made. CONCEPTUAL PICTURE OF OIL MOVEMENT IN GRAVITY-DRAINAGE RESERVOIRS Before attempting to develop an analytical treatment for conditions occuring in a gravity-drainage reservoir, a concept should be formed concerning the movement of fluids in the reservoir as oil is produced. A review of the literature'.' shows that it is customary to classify gravity-drainage operations into two categories—(1) with complete pressure maintenance, and (2) with declining pressure. The same line of reasoning will be followed in presenting the concept of the movement of fluids in the reservoir because it is easier to visualize the movement of fluids under conditions of complete pressure maintenance. After discussing complete pressure maintenance, an analogy will be made between that and the case of declining pressure. It should be kept in mind throughout that the final aim for the problem of solving gravity-drainage performance with digital computers will be to develop a general program for any kind of gravity-drainage reservoir. COMPLETE PRESSURE MAINTENANCE One feature which is generally common in gravity-drainage reservoirs is a gas cap located at the top of the structure. This is shown in Fig. 1(a). Fig. l(b) shows oil saturations that might occur through the reservoir. In the gas cap, oil saturation is lower than

By J. E. Warren, J. H. Hartsock

Because of the extensive utilization of hydraulic fracturing for the stimulation of low-productivity wells, the two related problems of fracture design and evaluation have become economically significant and, as a consequence, helve motivated this investigation. The producing characteristics of horizontally fractured wells were studied to determine the fracture configuration that should be employed as the basis for the design of the treatment and to develop a method that can be used to establish the degree to which the design objectives have been achieved. The equations which describe the steady-state flow of a single-phase fluid into, and through. a finite-capacity fracture were solved numerically for an idealized reservoir-fracture model. The numerical results were used to obtain an apparent skin effect for each combination of the parameters considered. Based on the computed results, subject to the limitcitions implied by the assumptions that were made, the following general conclusions were drawn. 1. For a radius of drainage at least four times us large as the radius of the fracture, an apparent skin effect that is independent of the radius of drainage can be calculated. 2. The productivity of the hydraulically fractured system, relative to that of the unfructured well, can be determined from the apparent skin effect and can be used to establish design objectives. 3. In the evaluation of a fracture job, it is not Possible to determine both the radius of the fracture and its flow capacity uniquely from the apparent skin effect; an independent determination of one of the quantities is necessary. lNTRODUCTION Although hydraulic fracturing has been employed as a method for stimulating the productivity of literally hundreds of thousands of wells during the past 10 years, it is only in the last few years that improvements in fracture design1-6 and fracturing technique' have combined to increase the probability of obtaining a successful treatment to such an extent that the mechanics of the method may be considered to be standardized. From an economic point of view, however, two related questions must be satisfactorily answered before hydraulic fracturing can be used in the most profitable manner. The two questions are the following. I. For a particular well in a given formation, what are the optimum design specifications for the fracture treatment? 2. Have the design objectives been achieved by the fracture treatment? The significance of these questions has been recoguized, and some attempts to obtain answers have been made. Howard, et al,8 endeavored to determine the optimum treatment, based on maximizing profits, for any given formation; unfortunately, this work was based on a crude method for approximating the productivity of a well. Carter and Tracy9 utilized the same approximation to study the effect of fracturing on the behavior of a well producing by virtue of a solution-gas drive. Electrolytic models were used by van Poollen10 to investigate the variation in productivity due to fracturing; however, only a limited number of results were presented. Later, from the same model results, van Poollen, et al,11 attempted to justify an approximate expression for determining the productivity of a fractured well. It is quite apparent that there is a definite lack of the practical information necessary for specifying the optimum fracture configuration to be considered for design purposes. The only detailed attempt to develop a procedure for evaluating the result of a given fracture treatment appears to be that of van Dam and Horner.12 These authors described a technique for analyzing pressure build-down data, obtained immediately after fracturing, to determine the final fracture volume, the final fracture porosity, the fracture area, the fracture thickness and the in situ fluid loss of the fracturing fluid. While this approach should be useful whenever acceptable pressure measurements are available, it does not yield a value for the flow capacity of the fracture. Since the problems of fracture design and evaluation are inversely related, it should be sufficient to study the effect of the fracture configuration on the performance of a well. The primary objective of this investigation is to evolve a technique for computing the desired solutions. The secondary objective is to analyze these computed results in order to prescribe a method for evaluating fracture treatments. Because this study is exploratory in nature, its scope

By M. D. Arnold, H. J. Gonzalez, P. B. Crawford

A method is presented for estimating the effective directional permeability ratio and the direction of maximum and minimum permeabilities in anisotropic oil reservoirs. The method is based on the principle that production from a well in an anisotropic reservoir results in elliptical isopo-tentials about the well, rather than circular. Bottom-hole pressure data from three observation wells surrounding a producing well are required to apply the method. The method involves fitting field pressure data to a set of general charts of isopotentials and making a few simple calculations until a solution is found. The method is based on a steady-state equation for homogeneorrs fluid pow. In addition to the method, a brief discussion of the theory underlying it is presented. INTRODUCTION The existence of a different permeability in one direction than another in oil reservoirs has been mentioned in several papers. Hutchinson' reported laboratory tests on 10 limestone cores and pointed out that one-half of them showed significant, preferential, directional permeability ratios, the average being about 16:1. Johnson and Hughesz reported a permeability trend in the Bradford field in the northeast-southwest direction with flow being 25 to 30 per cent greater in that direction. Barfield, Jordan and Moore -eported an effective permeability ratio of 144:1 in the Spraberry. Crawford and Landrum4 showed that sweep efficiencies could often vary by a factor of two to four, and sometimes considerably more, due to variations in flooding direction and patterns in anisotropic media. These findings indicate that the poss'bility of anisotropy may be worthy of consideration in the development of an oil field. In considering this, it should first be determined if anisotropy exists. If it does, the direction of the maximum and minimum permeabilities and the ratio of their magnitudes are quantities which can be of value in planning the most efficient well-spacing patterns. Past methods of determining these quantities have included analysis of oriented cores and analysis of flooding performance of pilot injection patterns. In recent work, Elkins and Skov5 resented an analysis of the pressure behavior in the Spraberry which accounted for anisotropic permeability. This work was based on the transient pres- sure distribution in a porous and permeable medium, with the solution expressed as an exponential integral function involving rock and fluid properties. The purpose of this study is to provide a method, based on steady-state equations, of estimating the direction and relative magnitude of permeabilities in an oil reservoir from field pressure data and well locations only. The method presented is based on work by Muskat6 which shows that Laplace's equation represents the steady-state pressure distribution for homogeneous fluid flow in homogeneous, anisotropic media if the co-ordinates of the system are shrunk or expanded by replacing x with it is desirable that data be obtained early in the history of a field because knowledge of an anisotropic condition would allow new wells to be spaced in such a manner that reservoir development and subsequent secondary recovery programs could be planned more efficiently. THEORETICAL CONSIDERATIONS A brief discussion of the theoretical basis on which the graphical solution was developed is presented in this section. Muskat's two-dimensional6 olution for the pressure distribution in an homogeneous, anisotropic medium with an homogeneous fluid flowing can be algebraically manipulated to show that the isobaric lines are perfect ellipses. The ratio of the major axis to the minor axis, a/b, is related to the permeability ratio, k,/k,, as follows. alb = dk,/k,--...........(1) It can also be shown that the pressure varies linearly with the logarithm of the radial distance from the producing well. However, the gradient along any ray is a function of the orientation of that ray, and a ..xiable is present when anisotropy exists which cancels out for a radial (isotropic) system. For a system such as that described, a dimensionless pressure-drop ratio was developed which is completely independent of the actual magnitude of the pressures. This was done by arranging Muskat's solution in such a way that aIl variables cancelled out except k,/k, and well positions. However, this solution depends on having a co-ordinate system with axes coinciding with the major and minor axes of the elliptical isobars. Thus, it was necessary to introduce a co-ordinate system rotation factor. The two unknown variables are then k,/k. and 0, and the two measured dimensionless pressure-drop ratios are related to the unknown variables as follows.

By L. A. Wilson, N. H. Harrison, R. R. Clay, R. L. Reed. D. W. Reed

Experiments have been performed in a linear near-adiabatic system for the purpose of extending data on reverse and forward combustion from atmospheric pressure to 1,000 psig. Results obtained from reverse combustion appear to conform qualitatively with the existing description of the process when reaction kinetics are suitably modified to account for the increase in pressure, i.e., increasing tbe pressure decreases the peak temperature and increases the combustion zone velocity. Forward combustion appears to be a fuel dominated process wherein peak temperature and combustion zone velocity are not very sensitive to changes in pressure. The moderate effects of pressure that do exist at low flux virtually disappear at high flux providing all oxygen is consumed. With this provision. increasing the pressure decreases the frontal velocity and increases the peak temperature. Results me shown graphicaIIy which demonstrate the effects of presswe on peak temperature, rate of advance, oil recovery, air/oil ratio, carbon oxides produced and temperature distributions. INTRODUCTION Numerous field tests of oil recovery using the technique of underground combustion are now in progress. Operating pressures used are always substantially in excess of atmospheric pressure. Nevertheless, the literature contains no laboratory data pertaining to the effects of pressure except for those of Martin, Alexander and Dew.1 Unfortunately, these data appear to reflect heat losses which may have obscured some of the effects of increased pressure. The underground combustion processes are exceedingly complex, and general concepts relating to them have necessarily been described in relatively simple terms. Particularly with regard to forward combustion, the interaction between multiphase fluid flow, heat transport and various rate mechanisms is so involved that to date a rigorous treatment is not available. In this paper a linear near-adiabatic system is described which was found capable of operating at pressures up to 1,000 psig and temperatures of at least 1,100 F. Using this equipment, experiments on both forward and reverse combustion were accomplished at elevated pressures and the data presented as a function of air flux or temperature. It will be assumed that the reader is familiar with the papers of Wilson, Wygal, Reed, Gergins and Henderson on forward combustion and that of Reed, Reed and Tracht3 on reverse combustion, so that it is not necessary to repeat the details of the two processes. EQUIPMENT AND PROCEDURE It was decided to study the effects of pressure over the interval 0-1,000 psig using a near-adiabatic system. Since satisfactory operation of such a system requires very thin tubing walls, it proved necessary to insert the entire combustion tube and heater assembly into a high pressure jacket in such a way that the internal tube pressure could be counterbalanced by pressurizing the annulus. This meant that the numerous heater and thermocouple wires had to pass through gas-tight seals that required considerable effort to maintain effective. An unexpected difficulty arose in connection with the nature of the annulus pressuring gas. It turned out that the composition of this gas critically affected the functioning of the adiabatic control system. Operation of the equipment at elevated pressures was not particularly difficult. The problems that did arise were a direct consequence of the large numbers of connections and seals involved. EQUIPMENT The equipment consisted of the combustion tube which fitted within the pressure jacket. This jacket was in turn mounted on a wheeled carriage which facilitated movement and provided for rotation of the