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By J. P. Heller, H. B. Bradley, A. S. Odeh

A potentiometric model technique is presented for determining the areal sweep efficiency of a five-spot well pattern, at and beyond breakthrough. A sharp interface between displaced and displacing fluids is assumed. Although the prototype svstem is referred to as a waterflood operation, obvious changes in the notation and computations will adapt the results to other displacement processes. The results of the study include the following. 1. Areal sweep efficiencies for a five-spot well pattern, at and beyond breakthrough, for mobility ratios (displacing to displaced fluid) of 4:1, 2:1, 1:1 and 1:4. 2. Extension of potentiometric analysis to the investigation of the areal sweep efficiency beyond breakthrough in a five-spot pattern by the application of conformal mapping and conductive-solid models. 3. The use of layers of conductive fabric in representing mobility ratio changes in potentiometric models. 4. The development of a probe mechanism for probing conductive solids. The results obtained by conductive-cloth models agree with earlier areal sweep efficiencies at breakthrough obtained by Aronofsky and Ramey 1 on the potentiometric analyzer using electrolytic-tank models. Results beyond breakthrough differ from those obtained by the X-Ray Shadowgraph technique. Data from this study show that, for mobility ratios greater than one, water cut rises rapidly as fluid is produced after breakthrough. However, for mobility ratios smaller than one, a large increase in area swept resulted with only a small increase in water cut. INTRODUCTION In calculating reservoir performance of waterflood-ing operations and other fluid-injection programs, it is necesssary to estimate the areal sweep efficiency * before and after injected-fluid breakthrough into production wells. Influence of mobility ratio on oil-production history, before and after breakthrough for a five-spot well pattern, has been studied by X-Ray Shadowgraph techniques 2-5 and by gelatin models.6 In none of these investigations was the transition zone controlled experimentally. Steady-state anaiog techniques assume that a vertical and discrete interface exists between the displacing and displaced phase. Thus, when using a potentiometric analysis, it is assumed that no transition zone exists. To determine the areal sweep efficiency beyond breakthrough for a five-spot well pattern using the potentiometric analyzer, four principal problems had to be resolved. These were the following. 1. The laborious method of representing changes in mobility ratio in electrolytic tanks by means of contoured wooden blocks. 2. Vapcrization of the electrolyte solution during the study causing concentration changes and, thereby, variable conductivity. 3. The scale-limitation problem 7 that is accentuated by abrupt eiectrolyte depth changes. 4. A wellbore geometry problem. EXPERIhlENTAL EQUIPMENT AND PROCEDURES CONDUCTIVE-SOLID MODEL The theory, equipment and procedural techniques of the electrolytic-tank potentiometric model have been treaced excellently by Lee8 and by Muskat.9 By the use of a conductive solid to represent the fluid conductivity of the porous media, the need for contouring wooden blocks to represent mobility ratio was eliminated. It was found that a carbon-black coated fabric, Uskon D-16,** could be employed as a fairly uniform conductive media. This material, when stacked in appropriate layers and pressed together, can be used to represent changes in mo-

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

The problem of unsteady-state gas flow through porous media has been solved numerically only for the case of linear or radially symmetric reservoirs. A recently introduced numerical method for solving the unsteady-state heat flow equation in two dimensions is applied to the calculation of the depletion of a square region containing a perfect gas. Solutions are presented in graphical form for various values of dimensionless parameters. The solutions are compared with published .solutions for radial reservoirs. I NTR ODUCTION The problem of unsteady-state flow of gas through porous media gives rise to a second-order non-linear partial differential equation for which no analytical solution has been found. Numerical approximations to solutions of the gas flow problem have been obtained by the stepwise solution of an associated difference equation1,2. However, the methods so far developed have required that the reservoir be either linear or radially symmetric. This restriction in shape has been necessary so that only two independent variables be considered, namely, one distance variable and time. In order to deal with reservoirs having more realistic shapes, it is necessary to develop numerical procedures for the solution of the gas flow problem involving two distance variables. A numerical procedure, denoted as the alternating-direction implicit method, for the solution of the heat-flow problem in two dimensions has recently been introduced" By the use of this procedure, approximate solutions have been obtained for heat-flow problems in a square8, and in regions having various non-rectangular boundariesa. Because of the similarity between the equation for heat conduction in solids and the equation for gas flow in porous media, it is reasonable to expect that the alternating-direction implicit method should also be useful for solving the gas flow problem in various two-dimensional regions. Solutions have been calculated for the simplest two-dimensional region, a square reservoir with a single well in the center. While reservoirs of such simple geometry seldom, if ever, exist, the solution of this problem is of some practical importance because it is also the solution of another problem, that of determining the depletion history about an individual well in an infinite uniform reservoir containing wells spaced throughout on a square lattice and producing equally from each well. Finally, it is of interest to compare solutions for a square reservoir with those for a circular reservoir and to determine the effect of the shape of the boundary for that particular case. METHOD OF CALCULATION Basic Differential Equation By combining the equation of continuity, the perfect gas law,

Jan 1, 1956

By O. G. Kiel, G. W. Swift

The concept of "a continuous succession of steady-states", which has been applied successfully by Aromfsky and Jenkins to obtain a solution for the nonlinear partial differential equation describing the transient Darcy flow of gas through porous media, is demonstrated to be equally valid for transient non-Darcy flow. A mathematical model, which numerically solves the partial differential equation, is used to check the validity of the succession of steady-states solution. Comparison of sand-face pressure histories compelted by the two methods shows excellent agreement. The utility of the succession of steady-states solution in predicting performance of gas wells rests in the fact that no special computation equipment is required. The development of the succession of steady-states solution leads also to a practical method for determining and analyzing field test data. A method for taking gas-well test data under constant-rate conditions is presented. Experimental data obtained in the field by employing the constant-rate method are presented and analyzed in accordance with the succession of steady-states solution. Analysis of data in this fashion is demonstrated to give direct "in situ" information for reservoir permeability, porosity and turbulence or non-Darcy coefficient. INTRODUCTION The economics of gas production are dependent upon the transient behavior of flow within the reservoir. For production from a finite reservoir, the transient flow behavior can be subdivided into two parts. At first, the transient caused by the movement of the pressure "wave" into the reservoir is of importance. Later in the production history, the pressure-wave movement ceases and the second transient stage of material depletion becomes controlling. For reservoirs of relatively high permeability, it can be shown that the pressure wave moves into the reservoir and stabilizes quite rapidly. In the case of relatively impermeable reservoirs, quite the opposite is true. Although it is theoretically possible to compute the production capability of a well from the properties of the reservoir as determined by static tests and core analyses, more reliable information is obtained by conducting flow tests on the well and thereby obtaining some measure of "in situ" formation properties. For gas wells, there are two basic types of tests in existence: the flow-after-flow method,' and the isochronal method.' Both of these techniques are tailored to obtain data that can be analyzed in accordance with the empirical performance equation: In addition, the isochronal method makes provision for the sluggish nature of pressure-wave movement in "tight" formations by requiring pressure build-up between flows and by stipulating that data obtained on successive flows be analyzed at equal elapsed flow times. It can be demonstrated that either test is valid for reservoirs of high permeability. Further, since it has been pointed out that the pressure wave stabilizes rapidly for reservoirs of this type, tests of relatively short duration will give stabilized information on the performance of a well. Further decline of sand-face pressure and/or production rate may be determined by employing material-balance techniques. Cullender' points out that for relatively impermeable reservoirs the flow-after-flow method gives invalid results. (See Appendix C.) If the isochronal method of testing is used, there are two alternatives: (1) the tests must be conducted for a sufficient length of time to obtain stabilized information (which may require months to accomplish); or (2) some method for extrapolating the results of short-term isochronal tests must be employed. The first alternative is impracticable because of manpower, conservation and economic considerations. Recourse to the second alternative requires some assurance regarding the reliability of the extrapolation technique. Poettmann and SchilsonJ present an empirical method for predicting stabilized performance. The present investigation was originally initiated to determine the reliability of this technique. To do this, a mathematical model was developed to simulate the Darcy and non-Darcy flow of gas through porous media. The model consisted of a finite-difference approximation of the nonlinear partial differential equation which was solved on an IBM 7090 computer. Long-term production histories were simulated by the model and compared against predictions obtained from the Poettmann-Schilson method. As the work progressed, it became apparent that a straightforward predictive equation could be developed by utilizing the concept of a succession of steady-states. As a result, the emphasis of the work was redirected to exploit the advantages of the new method.

By B. E. Eakin, A. L. Lee

Atmospheric pressure viscosity values For light hydrocarbons were calculated by a simple mixing rule based on the Sutherland constants for pure components. This method was further extended so that the atmospheric pressure viscosity of a mixture may be calculated based on the molecular weight information only. INTRODUCTION A proven method for estimating the gas-phase viscosity of a mixture is the one by Herning and zipperer.l This mixing rule has the following form: One method for calculating the pure component viscosity i is the Sutherland equation,2 which has the following form: The Sutherland constants B and S are determined from experimental data. A set of Sutherland constants for light hydrocarbons based on the data of several investigators3-5 is presented in Table 1. APPLICATION The Herning-Zipperer equation and the Sutherland equation were used to obtain an equation for calculating the gas-phase viscosity of light hydrocarbons. This equation has the form, Eq. 3 was used successfully in the study of methane-n-butane mixtures.6 Further analysis indicated that the Sutherland constants are a function of molecular weight.7 The gas-phase viscosity may be calculated based on molecular weight information only. The following equation was developed: The atmospheric pressure viscosity of ethane, propane, n-butaneand four methane-propane mixtures calculated on the basis of Eq. 6 are compared with the data of other investigators in Tables 2, 3, 4 and 5, respectively. A plot of atmospheric pressure viscosity vs molecular weight based on Eq. 6 is presented in Fig. 1.

Jan 1, 1965

By R. A. Greenkorn, R. C. Smith

Hele-Shaw cells are used to model creeping flow through porous media (where Darcy&apos;s law is valid). The effects of inertia on flow about obstructions in a Hele-Shaw cell can be calculated by a perturbation method if one can determine a solution to Laplace&apos;s equation. Results of a computer solution for flow about circular, square and elliptical obstructions are presented. These results show that or a modified Reynolds number of less than I, the inertia terms are small; and for values of less than 3, the average streamline predicts the ideal flow. Therefore, the analogy might be used for studying flow in porous media up to a modified Reynolds number of at least 3. INTRODUCTION The nature of fluid flow in porous media is of interest in the fields of soil mechanics, ground water flow, petroleum production, filtration and flow in packed beds. Because it is very difficult to study the phenomenological behavior of flow in porous media, homologs and analogs are used to study flow characteristics. A Hele-Shaw model, made of two closely spaced plates - usually glass — is often used as an analogy to two-dimensional flow in porous media. Hele-Shaw2 showed experimentally that the streamline configuration for creeping flow around an obstacle located between two closely spaced parallel plates is the same as for two-dimensional, ideal flow about the same obstacle. Stokes7 verified these observations mathematically. The usual equation of motion for flow in porous media is Darcy&apos;s law. The form of the mathematical statement of Darcy&apos;s law is identical, within a multiplicative constant, to the expression for the average velocity over the plate gap in the plane of a Hele-Shaw model. These models may be used to describe flow in both homogeneous and heterogeneous porous media. In the mathematical proof of the Hele-Shaw analogy it is assumed that the convective terms in the Navier-Stokes equations are negligible and that the equations of motion degenerate to Laplace&apos;s equation, with pressure the dependent variable. Whenever a Hele-Shaw model is used as an analogy to flow in porous media, .the validity of this assumption is in question. Riegels5 showed that if convection is not neglected, the velocity distribution around a cylindrical obstruction in the flow field depends on a Reynolds number, the plate spacing, and a dimension characteristic of the obstacle. Riegels&apos; solution, a perturbation solution, uses the boundary condition that the flow rate into the obstacle averaged over the plate gap at any point on the obstacle is zero. The method requires that a solution to Poisson&apos;s equation for the perturbation pressure be found. Riegels evaluated this solution for the case of the cylindrical obstruction. His method may be simplified by eliminating the need for solving Poisson&apos;s equation for the perturbation pressure. Instead, an analytic expression for the perturbation pressure gradient is obtained (valid for arbitrary shapes) and used to eliminate pressure from the equations for the perturbation velocities. The results show, for symmetrical shapes, that if NRe < 1, the convective acceleration terms are small, and that the average velocities represent ideal flow up to at least NRe = 3, where: L is a characteristic dimension of the obstacle perpendicular to flow, b is the plate spacing, u is viscosity, v, is velocity of approach and p is density. THEORY* Incompressible fluid flow through a Hele-Shaw model and a porous medium are analogous because the equations for the average velocity components in two-dimensional flow are identical if:

Jan 1, 1970

By V. J. Berry, J. D. Pendergrass

Well pressure transient tests provide a means for directly obtaining information about formation pressure and reservoir flow capacity. Such tests have also been proposed for determining presence and location of faults or other reservoir closures and for measuring oil in place. For mathematical convenience, most theoretical studies have considered the reservoirs to be homogeneous. Definitive information is not yet available to show whether the actual presence of nonuniformities will make pressure transient behavior different from that of a uniform reservoir. The conclusions reached from actual transient tests are questionable, therefore, insofar as they rely on the original assumption of homogeneity. One type of nonuniformity commonly assumed to exist is that of stratification. In most reservoirs the strata are thought to be in vertical communication. Equations for the transient flow of a single-phase, compressible fluid in a one-well, bounded, circular reservoir have been solved for several situations involving crossflow between multiple strata of various thicknesses and permeabilities. The results show that except for the very early flow period, which usually is too short to be analyzed, the transient performance observed at the well is substantially identical with that of a homogeneous reservoir having the same dimensions and having the same steady-state flow capacity. Thus, stratification does not adversely affect interpretation of well transient tests. This conclusion holds for all commonly encountered combinations of reservoir thickness and external radius. Deviations are observed for unusually thick reservoirs whose outer radii are relatively small. The results of these studies also show that the presence and the amount of stratification cannot be simply diagnosed from reservoir pressure transient data when there is crossflow between strata. INTRODUCTION The last decade has brought wide acceptance of the transient well pressure test for determining reservoir parameters. Following the original work of Hurst and van Everdingen,1 the mathematical theory was thoroughly explored. Numerous authors have suggested how to determine static reservoir pressure, permeability-thickness product, original oil in place and reservoir limits for different reservoir geometry. The same mathematical techniques have been used to predict the transient performance of a reservoir over a long period of time. Most of the theoretical work has been for homogeneous, isotropic systems. Some results have also been presented for a homogeneous, anisotropic reservoir.2 Petroleum reservoirs are not homogeneous. The deposition process seems to favor creation of a stratified formation. This concept is sufficiently well accepted so that the most natural extension of the transient flow theory beyond the homogeneous case is to a stratified formation. Results for a stratified reservoir with no vertical communication between layers can be obtained from the results for a homogeneous reservoir. Lefkovitz, et a1,3 have given a thorough treatment of the two-layer case. Two recent papers4,5 have treated the case of a two-layered reservoir with vertical communication or crossflow, between layers. Russell and Prats4 find that, after a relatively short time, the two-layered reservoir with crossflow exhibits a simple exponential pressure decline. From this time forward, the behavior is not distinguishable from the behavior of a homogeneous reservoir having the same steady-state flow capacity. The results of Katz and Tek 5 are equivalent. Russell and Prats4 also speculate that a multi-layered reservoir with crossflow will behave as a homogeneous system after long enough production time "... providing the contrast in kh between layers is not too great". They also suggest that, at intermediate times, "... the relative positions of the layers with respect to each other will have a great influence on the production behavior and on the time at which the previously mentioned large-time approximation might be valid". Katz and Tek5 remark upon the mathematical difficulty of treating a reservoir having many layers or strata. If relative position of the layers is also

By E. L. Dougherty

A phenomenological theory for a one-dimensional unstable miscible displacement similar in type to the Buckley-Leverett model but including the effects of mixing is proposed An equation giving the fractional flow of pure solvent through an oil phase containing dissolved solvent is derived including the effects of gravity and nonbomogeneities. Numer ical integration of the resulting pair of nonlinear hyperbolic partial differential equations gives volumes of dissolved and undissolved solvent as functions of space and time. Parameters in the model which characterize mixing due to dispersion were determined from experimental data; the parmeters correlated with viscosity ratio. The results indicate that the rate of dispersive mixing is proportional to volumetric flow rate Incorporated into our equations were Koval&apos;s heterogeneity factor H. which characterizes mixing due to channeling. This allowed satisfactory predictions of displacement behavior observed in horizontal floods in nonhomo-geneous cores; but in most cases the values of H which we used were considerably larger than those used by Koval. INTRODUCTION It has been shownl,2,3 that for favorable viscosity ratios, the diffusion equation with convection satisfactorily describes the behavior of a miscible displacement in a porous media. Numerous attempts to develop a satisfactory mathematical description for the case of unfavorable viscosity ratio have been reported, but they have met with only partial success. These attempts, which are reviewed by oval! have taken two approaches: (1) development of a flow model akin to the Buckley-Leverett approach for immiscible displacement neglecting the effects of mixing5,6 and (2) simultaneous application of Darcy&apos;s Law for flow and the diffusion equation with a convection term for mass transfer.7,8,9 We set out to construct a mathematical model of Type 1 including, though, the effects of mixing. Based upon a set of hypotheses, we derived a pair of nonlinear hyperbolic partial differential equations which describe in a one-dimensional system the combined effects of flow and mixing. To work with these equations it was necessary to develop a fractional flow formula. The combined system was integrated numerically using the method of characteristics. In our equations the mixing process is characterized by four parameters. Three of these, labeled ß, P1 and P2, account for dispersive type mixing. The fourth is the heterogeneity factor H, proposed by Koval to account for channeling due to nonhomogeneities in the porous media. Values of the parameters which would cause agreement between theory and experiment were determined by trial-and-error for miscible floods conducted in horizontal cores of both homogeneous and heterogeneous materials. Calculations were also performed for vertical floods in homogeneous cores. The purpose of this paper is (1) to present the details of the mathematical analysis, (2) to present the results of the calculations, (3) to consider what light the results shed on the mixing process in an unstable miscible displacement, and (4) to provide a firmer foundation for the correlation technique developed by Koval for predicting the behavior of unstable miscible floods. STATEMENT OF PROBLEM The problem is to construct a mathematical model which describes in one dimension the observed behavior in an unstable miscible displacement. The approach is phenomenological in that the equations are based on assumptions which violate certain physical precepts known to apply to the displacement phenomenon. However, the assumptions do allow us to account mathematically for the more essential phenomena. The work is of value if we can quantitatively predict experimental results which heretofore could not be predicted, even though the synthetic nature of the model belies complete explanation of the observations. We assume that the system is comprised of two contiguous flowing phases. One phase, which we call free solvent, has the properties of pure solvent. We call the fraction of the pore volume occupied by this phase the solvent saturation, designated s. The oil phase consists of oil containing dissolved

By Thomas M. Drown

AT the meeting of the Institute in New York,, in February, 1880,* I described a process of determining sulphur in metallic sulphides, with especial reference to the determination of pyrites in coal. The process, as then described, is as follows : A solution of sodium hydrate, of 1.25 specific gravity, is saturated with bromine. If an excess of bromine is used it must be neutralized by the addition of a :little more sodium hydrate. The pulverized mineral or coal is moistened with 25 c.c. of this solution and heated, then hydrochloric acid is added cautiously to just acid reaction. This operation is repeated with another 25 c.c. of the alkaline solution, and again rendered acid. The mixture should be kept hot. The contents of the beaker or dish are then * Transactions, American Institute of Mining Engineers, vol. viii, p. 569.

Jan 1, 1881

By C. D. Stahl, S. M. Farouq Ali, W. E. Culham

One- and two-dimensional mathematical models have been developed that simulate transient, two-phase flow of hydrocarbon mixtures in porous media in a manner that accounts for interphase mass transfer. Numerical simulations of one-dimensional depletion-drive experiments using a two-component hydrucarbon fluid were used to establish the validity of the mathematical models. In addition, the experimental and numerical data were used to demonstrate that production rate had a relatively insignificant effect on the recovery of individual hydrocarbon components from the experimental system, and that attainment of equilibrium between phases is possible for a wide range of liquid and vapor velocities in reservoirs containing light hydrocarbon fluids. Results of some two-dimensional numerical simulations are also presented. INTRODUCTION This study was undertaken to develop a mathematical model that would simulate transient, two-phase flow of hydrocarbon mixtures in porous media under conditions that result in interphase mass transfer and to test the validity of the assumptions used to set up the model. In addition, the study was designed to determine if production rate influences the recovery of individual hydrocarbon components from reservoirs producing by depletion drive. Two-phase flow in porous media, with interchange of components between the two phases, is important in many petroleum recovery processes. Studiesl-5 conducted within the last 3 years have outlined methods of solving multiphase flow problems incorporating mass transfer. Some of these studies have also indicated the importance of accounting for mass transfer under various producing conditions. An earlier work6 first demonstrated the importance of combining relative permeability data with equilibrium ratios in compositional balance methods. The mathematical model presented in this paper is formulated so that a phase behavior package, as described in previous papers,5,17 is not required as an integral part of the routine employed to solve for the primary dependent variables. The finite difference formulation is designed so that all the primary variables can be solved for simultaneously. This is accomplished by utilizing one basic set of equations. These innovations, which are in contrast to other models2,3,5 but are similar in some respects to the approach used by Taylor,l render the total problem computationally simpler than any of the previously referenced formulations. The mathematical model was developed by combining Darcy&apos;s law with a continuity equation for each hydrocarbon component. The principal assumptions invoked in the formulation were (1) that capillary forces and diffusional effects are negligible, and (2) that thermodynamic equilibrium exists in the reservoir at all times. No assumption as to the type of vaporization process was made in formulating this model. Experimental data were required to complete this study. These were generated by conducting several depletion drive experiments. The experimental apparatus consisted of a sandstone core enclosed in a pressurized casing. The apparatus was designed in such a manner that the core could be charged with a liquid hydrocarbon mixture and depleted at different production rates. The experimental tests were designed to determine the effect of production rate on component recovery. In addition, direct comparison of experimental and mathematically predicted

Jan 1, 1970

By J. S. Aronofsky

The first step in a quantitative analysis ot the mechanism of oil displacement by water in a fractured reservoir is usually conceded to be the solution of the differential equation describing the saturation distribution of two immiscible fluids flowing in a porous medium, where the capillary pressure is taken into account. In such a system the production mechanism may consist of displacement of oil both by the flow of water due to natural or artificially imposed pressure gradients and by imbibition, which implies a flow of water not due to external pressure gradients. Owing to the presence of the two oil displacement mechanisms, the mathematical model given by the differential equation intended to describe the system may not properly represent the behavior of the physical system. In fact, in the reservoir the rate of water advance may be very slow, and in the case of a fractured reservoir with a great number of large fractures, the pressure difference determining the flow of water through the matrix may be much less than 1 lb/&apos;psi over lengths of a few feet. In such a case, imbi-bition (the exchange between oil in the matrix and water in the fractures resulting from capillary forces) may become, with time. a significant element of the production mechanism. It occurred Lo the authors, however, that without going into a physical analysis of the process of production, it might be possible by means of simple abstract reasoning to throw some light on the variation of recovery with time under conditions occurring in a highly fractured oil reservoir with rising water table. The object of this paper is to present both the reasoning and its application to a reservoir of the highly fractured type. Specifically, the analysis given here was undertaken to try to explain the increase of recovery (as defined later) with time as observed in this reservoir, without having to assume unlikely variations in the reservoir parameters with depth. This attempt has been successful as will become clear upon comparison of the computed recoveries with the actual field data. ABSTRACT MODEL Let us consider a small volume. of porous matrix saturated with oil at time, t = 0. Let the process of oil displacement by water start at time, t = t,,. At some time, t, the process will have terminated. Then a volume of oil equal to or smaller than the original oil contained in the matrix will have been produced. The first basic assumption that describes the model and guides the forthcoming reasoning is that the oil production from the small volume. dv, is a continuous monotonic function of time and that it converges to a finite limit. Such an assumption is not inconsistent with the results of laboratory waterflood tests as well as with results of imbibition tests where this is, in fact, observed. The second basic assumption is that none of the properties which determine the rate of convergence change sufficiently during the process to affect this rate or the limit. Let it be assumed that the form of the function of time relative to production from the matrix volume. dv, is given by where V,(t) is the volume of oil produced up to that time t. R is the limit toward which the recovery converges, A is a constant giving the rate of convergence, and V,(t) is the volume of oil originally in place in the volume, dv. It should be noted that recovery at time I will be understood here to he It follows that r. tends to R as t tends to infinity. CONSTRUCTION OF RESERVOIR FROM ABSTRACT MODEL Let the reservoir consist of a series of identical blocks of porous matrix stacked vertically and separated by fractures. Let each of these blocks satisfy the conditions of our abstract model. These conditions are: (1) that recovery is a continuous mono-tonic function of time converging to finite limit, and (2) none of the properties that determine the rate of convergence change sufficiently to affect the rate or the limit. Let water be rising in fractures so that oil production from any part of the block starts when the water comes in conLact with it. TOTAL RECOVERY FROM THE RESERVOIR COMPARED TO RECOVERY FROM A SINGLE MODEL ELEMENT As stipulated in Eq. 1, in the case of the abstract model,

By B. A. Eaton

The subject of many discussions and technical papers in the last 20 years has been the prediction of the well-bore pressure gradients that are required to induce or extend fractures in subsurface formations. The subject merits this attention because of the frequently recurring problems that arise from an inability to predict fracture pressure gradients. Encountered in several common types of operations in the oil industry are problems associated with the prediction of formation fracture pressure gradients. When wells are being drilled in both new and old fields, lost circulation is often a very troublesome and expensive problem. Complete loss of circulation has been disastrous in some cases. Many times, such disasters could have been avoided if techniques for calculating fracture pressure gradient had been employed in the well plans, and if casing strings had been set, and mud weight plans had been followed accordingly. In areas of abnormally pressured formations, the prediction of fracture gradients during the well-planning stage is extremely important. In fact, it is as important as the prediction of formation pressure gradients, which has received a great deal of attention in recent years. There are several published methods used to determine fracture pressure gradients. However, none of these methods appears to be general enough to be used with much reliability in all areas. In 1957, Hub-bert and Willis published a classical paper that included the development of an equation used to predict the fracture extension pressure gradient in areas of incipient normal fau1ting.l Overburden stress gradient, formation pore pressure gradient and Poisson&apos;s ratio of rocks were the independent variables that were shown to control fracture pressure gradient, the dependent variable. In 1967, Matthews and Kelly published another fracture pressure gradient equation that is different from that of Hubbert and Willis in that a variable "matrix stress coefficient" concept was utilized.3 Later the same year, Costley wrote about a similar idea.5 Goldsmith and Wilson used a least-squares curve-fitting technique and field data from the Gulf Coast area to correlate fracture pressure gradient with formation pore pressure gradient and formation depth.&apos; They noted that the fracture pressure gradient increased with increasing depth while the pore pressure gradient remained constant. In each of these cases, the problem for which a solution was sought was to determine the bottom-hole pressure gradient required to initiate or extend a fracture. Results of the previous work show that fracture pressure gradient is a function primarily of overburden stress gradient, pore pressure gradient, and the ratio of horizontal to vertical stress. There is argument for a fourth variable in that in many cases breakdown fracture pressure gradient is greater than the fracture extension pressure gradient. However, if the fracturing fluid is able to penetrate the formation through the pores or existing cracks, there is very little

Jan 1, 1970

By C. R. McEwen

The displacement equations of Buckley and Lever-ett&apos; have been successfully applied to the prediction of oil recovery in frontal drives for a number of years. Commonly, the capillary pressure term is omitted from Leverett&apos;s fractional flow formula. The resulting satura-tion-vs-distance curves become multi-valued, however. Buckley and Leverett, recognizing that the neglect of capillarity was most likely the cause, proposed that this part of the solution he ignored. An ingenious method of propagating a discontinuity in place of the multi-valued portlon of the curve was devised by Cardwell using "non-capillary displacement theory". However, it would seem that a completc description of the displacement pracess would require the inclusion of capillary forces. Three publications on displacement theory have appeared in which capillary pressure was included. Ter-williger. et al&apos;, calculated saturation profiles which matched those which they observed when gas displaced water vertically downward. Based on their study, Jones-Parra and Calhoun5 roposed a method of computing saturation distributions sufficiently removed in time from the initial conditions so that all saturations in the flood front region were assumed to move with the same velocity. This latter assumption corresponds to the tangent construction on the flowing fraction-vs-satura-tion curve proposed by Welge." A numerical solution to the problem of water displacing oil from a water-wet porous medium was recently presented by Blair, ef at&apos;. The initial conditions included a uniform saturation slightly above interstitial water saturation. that is, the permeability to water ahead of the front was not zero. This appeared to result in a region of slowly rising water saturation ahead of the front, at least for the particular set of relative permeability and capillary pressure data used to illustrate the computation. The authors also postulated an "end-effect" at the outflow face of the system, whereby no water could pass out of the system until the water saturation had built up to a high value. The saturation profiles computed under these assumptions show water accumulating at the downstream end of the system while the flood front proper is still traveling toward the outlet. The purpose of this paper is to present the results of a numerical solution to the one-dimensional water-flooding equation in which no outlet end-effect is considered and where there is no flow of water ahead of the flood front. It should be noted that the contemporary paper of Fayers and Sheldon8 deals with the problem under discussion. For a thorough treatment including both capillarity and gravity the reader is referred to their paper.

By W. B. Gogarty, H. R. Bailey

Methods are presented for determining molecular diffusion coefficients by using data from, capillary flow experiments. These methods are based on a numerical solution (presented in a previous paper) of the partial differential equation describing the combined mechanisms of flow and diffusion. Results from this numerical solution are given and compared with the approximate analytical solution of G. I. Taylor. The numerical solution is valid over a much larger time range. These methods are applied to experimental results for the fluid pairs water-potassium permanganate solution and amyl acetate-orthoxylene. Both of these fluid pairs have approximately equal densities and viscosities. Graphical and numerical techniques are presented for deter mining diffusion coefficients from the flow data. Values obtained by these techniques are compared with values obtained by other methods. INTRODUCTION The molecular diffusion coefficient is known to be a variable in determining the amount of mixing in a miscible displacement process. The effect of molecular diffusion on dispersion in longitudinal flow through porous media -has been examined by different investigators. These investigators concluded that at low velocities of flow, the amount of dispersion is approximate1y proportional to the molecular diffusion coefficient. The influence of diffusion on fingering, channeling, and overriding has been mentioned by other investigators.4 Recent studies5,6 have been made on the effects of molecular diffusion in connection with the problem of gravity segregation. Many different methods have been developed for the experimental determination of molecular diffusion coefficients? These methods differ mainly according to boundary conditions selected and analytical procedures used. Nevertheless, all of these methods have the condition in common that the bulk fluids in which diffusion is occurring are stationary with respect to each other. In connection with a series of papers on mixing in capillary flow,8-10 Taylor suggested the use of a flow method for determining molecular diffusion coefficients. Additional studies 11-13 have been conducted on miscible displacements in capillary tubes, but the data from these studies were not used for the specific purpose of determining diffusion coefficients. The flow method proposed by Taylor results in a single value of the diffusion coefficient for the fluid pair used in the displacement experiments. This single value represents the true value for the fluid pair when the diffusion coefficient is independent of concentration. If the diffusion coefficient is a function of concentration, the single value obtained by the flow method gives an average value for the coefficient of the fluid pair. These average values are based on diffusion taking place over the entire range of concentration, i.e., from 0 per cent of one fluid to 100 per cent of that same fluid. In field applications of the miscible displacement process, gradients occur over the same range of concentration as are found in the displacements in capillary tubes. Molecular diffusion coefficients obtained from the capillary flow method should, therefore, be especially relevant to field operations. This investigation was undertaken to evaluate the feasibility of obtaining molecular diffusion coefficients from capillary -flow experiments. In making this evaluation, diffusion coefficients were first determined for two systems from data obtained in capillary flow experiments. These values of the diffusion coefficient were then compared to values obtained by other methods. MIXING IN CAPILLARY FLOW—THEORETICAL The theoretical basis for determining molecular diffusion coefficients from capillary flow experiments is the partial differential equation relating the mechanisms of flow and diffusion. For the case of laminar flow and with a fluid pair having equal densities and viscosities, the equation is given by

By G. Thodos, R. B. Grieves

A method has been developed For predicting the critical temperatures and critical pressures of binary mixtures of carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen with the normal paraffin hydrocarbons. For carbon-dioxide and hydrogen-sulfide systems, relations are presented that take into account the peculiar behavior of mixtures with closely boiling components, such as carbon dioxide-ethane and hydrogen sulfide-propane mixtures which exhibit minimum critical temperature points. For hydrogen, nitrogen and carbon-monoxide systems, the extreme critical behavior caused by wide differences in pure component properties is established In addition, those fixed gas-paraffin systems which resemble paraffin-paraffin systems are also accounted for. For a mixture of known composition, the pure component critical temperatures, critical pressures and normal boiling points are all that are required to determine its critical point. Graphical relations are presented relating Tc and PC , of the mixture to the pure component properties. From the treatment of 12 carbon-dioxide and hydrogen-sulfide systems reported in the literature (74 mixtures), the expected error lor the critical temperature is approximately 1.5 per cent, and for the critical pressure, approximately 2 per cent. From the treatment of six hydrogen, nitrogen and carbon-monoxide systems reported in the literature (30 mixtures), the expected error for both the critical temperature and critical pressure is approximately 2.5 per cent. The relationships, which have been developed with only normal paraffins as the hydrocarbon components, may be extended to those isoparaffins and olefins which fall within the allowable volatility ranges. INTRODUCTION Many of the fixed gases — carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen — occur in natural mixtures with hydrocarbons. Carbon dioxide and hydrogen sulfide are frequent components of the fluids produced from underground petroleum reservoirs. Nitrogen, carbon dioxide and hydrogen sulfide are present in varying quantities in most natural gases and gas-condensate well effluents. Hydrogen mixtures are of considerable interest in many phases of refining processes of petroleum. The determination of the critical temperatures and critical pressures of such mixtures is of value in vapor-liquid equilibrium studies, for the prediction of the characteristics of underground reservoirs, and for reduced-state correlations of PVT, transport and thermodynamic properties. The accurate estimation of the critical point for binary mixtures is an important initial step toward a complete analysis for the establishment of the critical temperatures and pressures of multi-component mixtures. Methods for predicting the critical temperatures and critical pressures of binary hydrocarbon systems have already been presented in the literature.8 It is possible to apply these existing methods to fixed gas-paraffin mixtures, but due to their unusual critical behavior, values calculated deviate considerably from experimental values. For systems containing trace quantities of the fixed gases, these methods are acceptable; however, for systems containing more than 5 mol per cent of the fixed gases, these utterly fail to produce reasonable critical values. Consequently, in this study a method has been developed for handling such binary mixtures over the entire composition range. CARBON-DIOXIDE AND HYDROGEN-SULFIDE SYSTEMS The critical behavior and the vapor pressure behavior of mixtures of carbon dioxide and hydrogen sulfide with paraffinic hydrocarbons may be quite similar or quite dissimilar to that of paraffin-paraffin mixtures, depending on the volatilities of the components involved. The critical temperature and normal boiling point of carbon dioxide are very close to the corresponding values for ethane, while its critical pressure is considerably higher than that of ethane. The normal boiling point of

By A. M. Sarem

For the performance prediction of multiphase oil recovery processes such as steam stimulation, there is an acute need for three-phase relative permeability data. No fast and simple experimental technique, such as the unsteady state method proposed by Welge for two-phase flow, is available for the three-phase flow. In this paper, an unsteady - state method is presented for obtaining three-phase relative permeability data; this method is as fast and easy as Welge&apos;s method for two - phase flow. Analytical expressions are derived by extension of the Buckley-Leverett theory to three-phase flow to express the saturation at the outflow face for all three phases in terms of the known parameters. It is assumed that the fractional flow and relative permeability of each phase are a function of the saturation of that phase. Other simplifying assumptions made include the neglect of capillary and gravity effects. The effect of saturation history upon relative permeability is acknowledged and attainment of similar saturation history in laboratory and field is recommended. The required experimental work and computations are simple to perform. The test core is presaturated with oil and water, then subjected to gas drive. During the test, required data are the rates of oil, water, and gas production, together with pressure drop and temperature. The ordinary gas-oil unsteady-state relative permeability apparatus can be readily modified to measure the required data. The proposed technique was applied to samples of a Berea and a reservoir core. The effect of saturation history upon relative permeability was studied on one Berea core. It was found that increase in initial water saturation has a similar effect upon three-pbase relative permeability as it does in two-phase flow. INTRODUCTION In the light of increasing demand for three-phase relative permeability data for predicting the performance of thermal and other multiphase-flow recovery processes, a simple and accurate method of experimental determination of such data is extremely desirable. Leverett and Lewis 1 described the simultaneous flow method of obtaining three-phase relative permeability data. However, Caudle et al.2 reported that this method is very time consuming and cumbersome. Corey3 proposed calculating the three-phase relative permeability from measured krg data. Corey&apos;s theory is based on simplified capillary pressure curves,4 assuming a straight line relationship between I/Pc2 and saturation. Also, Corey&apos;s method assumes a preferentially water-wet system. The simplest and quickest method of obtaining three-phase relative permeability data is the unsteady-state method where, for instance, oil and water are displaced by gas. However, in such a test the correlation of average saturation with relative permeability does not give a valid relationship because the rates of oil, water and gas flow in the sample change continuously from the upstream to downstream end. This difficulty in calculating valid relationships was solved by Welge for two-phase flow by deriving an expression for determining the outflow face saturation from Buckley and Leverett frontal advance equations.5,6 In this paper, relations are established to determine the outflow face saturation and relative permeability to all phases in a three-phase flow displacement experiment. PROPOSED METHOD The fundamentals established by Buckley and Leverett5 for two-phase flow were extended to three - phase flow and used as a basis for the derivation of saturation equations. This approach is comparable to Welge&apos;s6 use of Buckley and Leverett theory in arriving at expressions to determine the outflow face saturation of the displacing fluid in a two-phase flow system.

Jan 1, 1967

By C. Chu

A theoretical investigation has been made of the forward combustion process using a one-dimensional linear mathematical model, taking into consideration the effect of the vaporization-condensation which occurs on the leading edge of the heat wave. This work involves the solution of five coupled partial differential equations. Besides the vaporization-condensation phenomenon, these equations account for conduction, convection, combustion, heat loss, diffusion and bulk fluid flow. For the one-dimensional linear model studied, the vaporization-condensation phenomenon does not induce appreciable change in the temperature at the combustion front; and its primary effect is to create a steam plateau and to increase the length of the heated zone ahead of the combustion front. This effect becomes more pronounced at lower pressures, higher porosities or reduced gas saturations. The peak temperature and the temperature profile on the leading edge of the heat wave stabilize after a certain period. The length of the steam bank remains practically constant, although the length of the water bank increases as the heat wave advances. INTRODUCTION The existence of the vaporization-condensation phenomenon in the heat-wave process and the important role played by the phenomenon have been recognized by several investigators. Kuhn and Kochl stated that steam plateaus were frequently observed on the temperature records of their experiments. The steam plateaus were attributed primarily to the vaporization and subsequent condensation of the interstitial water existing in the oil sand. Szasz2 suggested that both lighter hydrocarbons and water are vaporized on the leading edge of the heat wave, carried forward in the gas stream, and then condensed to create banks of oil and water. Martin et al suggested that the vaporization-condensation phenomenon is one of the main mechanisms of the heat-wave process, along with thermal expansion and viscosity reduction. Wilson et al. reported the existence of a steam plateau several inches in length in their small-scale tube-run experiments. However, this important phenomenon has never been taken into consideration in the numerous theoretical analyses by various authors. 5 The purpose of this work was to study the thermal aspects of a linear heat wave, taking into consideration the vaporization-condensation on the leading edge of the wave, to determine the effect of this phenomenon on the temperature profile of the reservoir, and to investigate how this effect varies when other process variables are changed. THEORY We consider a reservoir of porous medium of cross-sectional area A, extending from x = 0 to x = L. This reservoir contains, aside from the solid matrix itself, a gas phase and a "combined liquid phase" which is a combination of two immiscible liquid phases — namely, an oil phase and a water phase. The oil present in the reservoir is assumed to consist of three fractions, a noncondensable gas, a nondistillable residuum, and a vaporizable oil fraction which may be present in both the gas phase and liquid phase. Before the heat-wave process begins, preheating has taken place and has imparted an initial temperature distribution T,(x) to the reservoir. At the start of the process, a stream of oxygen-bearing gas is introduced through the face at x = 0. This gas supports the combustion of the residual fuel and supplies the heat throughout the process. In order to develop a tractable system of equations, the model properties are postulated as follows: (1) the system is isotropic and homogeneous; (2) there is a uniform fuel content throughout the reservoir; (3) combustion takes place in a moving vertical planar region of infinitesimal thickness; (4) the temperatures of the fluids and the solid matrix are identical; (5) radiation is negligible; (6) the gas and liquid saturations are uniform throughout the reservoir and remain unchanged

Jan 1, 1965

By F. W. DeVries

The subject article is an excellent comparison between two potential oxidants, molecular oxygen and hydrogen peroxide, as used in the Palangana field at the time of the trials. The tests showed no advantage to using hydrogen peroxide; however, it would be unwise to generalize that the experience in these trials was universally true. During the time of the work cited, extremely high levels of an unusual impurity were recycling in the lixiviant, which substance was a catastrophically destructive catalyst for peroxide. Since this material was not removed before recycle, it was not surprising that much of the peroxide fed was decomposing in the feed piping and never made contact with the uranium mineralization. Under these conditions, indeed, peroxide showed no improvement over oxygen. This is, however, perhaps the most adverse environment encountered to date in US in-situ uranium leaching. In other operations, peroxide has proved advantageous where two factors have been exploited: 1.Despite the tendency for Hz02 to decompose to water and oxygen in the in-situ leach environment, its higher redox potential before decomposition has provided higher leach rates. In some formulations, overloading beyond the O2 saturation equivalent with peroxide has allowed higher oxidant levels, and higher leaching rates, when overloading with molecular O2, led to vapor-locking.

Jan 1, 1983

By D. A. Flanagan, P. B. Crawford

A study has been made of the feasibility of storing liquid meihane at low pressures in undergrohd caverns. Methane liquefies at — 258°F at atmospheric pressure. It is shown that the methane evaporation rates will rapidly decrease and cool the surrounding rock so that at the end of one month they would be between 50 Mcf/hr for a cavern of 25-ft radius and 700 Mcf/hr for a cavern of 100-ft radius. At the end of 10 years, the evaporation rates would be 18 and 100 Mcf/hr, respectively, for caverns of the same radii. The evaporation rates may be reduced by a factor of 2 to 10 by the application of insulation. The cost for mining the caverns is estimated to be $.75 to $1.25/Mcf of storage. This is substantially less than surface storage; it is believed to be safer and to result in lower maintenance, savings in space and savings in strategic materials. INTRODUCTION During the past few years, there has been an increasing interest in the economic feasibility of liquefying methane. Methane liquefaction is being considered for tanker transport; in addition, liquefaction is being reconsidered for shaving peak gas demands. Several articles have described natural gas liquefaction and the progress of the tanker in making trial runs from the United States to Great Britain to determine the feasibility of tanker transport. At the present time, pipelines are not designed to supply peak gas loads during extremely cold periods such as are oiten encountered in the North and Northeast. Gas is being stored in underground reservoirs en-route to its destination, but in many instances satisfactory storage in porous reservoirs has not been practical, especially along the Eastern seaboard where few petroleum reservoirs have been found. In England and other foreign countries, it is unlikely that satisfactory porous structures could be found, and it may be desirable to mine or excavate the rock to obtain storage. By storing the methane near the consumption point, product availability can be increased during periods of need. Methane liquefies at - 258OF at atmospheric pressure, and 1 cu ft of liquid methane will make about 600 cu ft of gaseous methane. Methane liquefaction for shaving peak gas demands was conducted in Cleveland, Ohio in the early 1940&apos;s. The Cleveland plant was designed to liquefy 4 MMcf/D of natural gas.&apos; Development of several low-temperature processes has resulted in some improvements in the design of low-temperature storage vessels. Liquefied-methane storage vessels can be designed for various evaporation rates. The desired rate will depend on the reason for liquefaction. For shaving peak gas demands, the desired evaporation rates would be low, possibly between 0.2 and 1.5 per cent/day. For methane tanker transport and supply, the evaporation rates must be high and must equal the total daily rate of supply. It is apparent that the cost of storage facilities will depend on the objective and will vary appreciably. Surface storage of methane may cost between $3,000 and $20,000/MMscf, depending on the size and design. The failure of the surface storage vessels at Cleveland, with the resulting injury and loss of many lives, has caused considerable emphasis to be placed upon developing new, safer and improved methods of storing liquid methane. Storage of liquefied propane and butane in underground salt domes has been very satisfactory. The per-barrel cost of underground storage for any sizeable capacity is very small compared to the cost of surface storage for LPG mixtures. The larger the capacity of the underground storage, the less is the per-barrel cost. Numerous advantages appear to exist if liquefied methane could be satisfactorily stored underground, the principal advantages being increased safety, lower initial cost, lower maintenance cost, savings in space and savings in strategic materials. The purpose of this paper is to determine the feasibility of storing liquid methane underground in mined caverns. If a large spherical cavern is dug underground and is filled instantaneously with liquid methane, the surface of the sphere may approach the liquid methane temperature almost instantaneously. The temperature distribution for a sphere of radius r. in an infinite medium, initially at one temperature with spherical surface kept at T, from time t = 0, is given by Eq. 1.&apos;

(Under this heading will be published notes sent to the Secretary of the Institute by members or other persons introduced by members.) Member, aged 34, married, technical graduate, 10 years&apos; experience as mining engineer and mine superintendent, desires position. Can show low cost records and good references. No. 176.

Jan 1, 1916

[Officers and Committees of the Society of Petroleum Engineers 1 Officers and Staff of the AIME 2 . Officers of AIME Sections Predominantly Petroleum in Membership 3 AIME Local Sections and SPE Regional Organization Maps 5 Alphabetical List of Members 7 Geographical List of Members 102 Advertisers&apos; Index 133]

Jan 1, 1961