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By A. G. Weber, K. H. Coats, M. H. Terhune, R. L. Nielsen

Two computer-oriented techniques for simulating the three-dimensional flow behavior of two fluid phases in petroleum reservoirs were developed. Under the first technique the flow equations are solved to model three-dimensional flow in a reservoir. The second technique was developed for modeling flow in three-dimensional media that have sufficiently high permeability in the vertical direction so that vertical flow is not seriously restricted. Since this latter technique is a modified two-dimensional meal analysis, suitably structured three-dimensional reservoirs can be simulated at considerably lower computational expenses than is required using the three-dimensional analysis. A quantitative criterion is provided for determining when vertical communication is good enough to permit use of the modified two-dimensional areal analysis. The equations solved by both techniques treat both fluids as compressible, and, for gas-oil applications, provide for the evolution of dissolved gas. Accounted for are the effects of relative permeability, capillary pressure and gravity in addition to reservoir geomety and rock heterogeneity. Calculations are compared with laboratory waterflood data to indicate the validity of the analyses. Other results were calculated with both techniques which show the equivalence of the two solutions for reservoirs satisfying the vertical communication criterion. INTRODUCTION Obtaining the maximum profits from oil and gas reservoirs during all stages of depletion is the fundamental charge to the reservoir engineering profession. In recent years much quantitative assistance in evaluating field development programs has been provided by computerized techniques for predicting reservoir flow behavior. Because of the spatially distributed and dynamic nature of producing operations, automatic optimization procedures, such as those now in use for planning refining operations, are not now available for planning reservoir development. However, present mathematical simulation techniques do furnish powerful means for making case studies to help in planning primary recovery operations and in selecting and timing supplemental recovery operations. A number of methods have been reported which simulate the flow of one, two or three fluid phases within porous media of one or two effective spatial dimensions>-4 However, applying computer analyses to actual reservoirs have been limited mostly to two-dimensional areal or cross-sectional flow studies for two immiscible reservoir fluids. To obtain a three-dimensional picture of reservoir performance using such two-dimensional techniques, it has been necessary to interpret the calculations by combining somehow the results from essentially independent areal and cross-sectional studies. To the authors' knowledge, the only other three-dimensional computational procedure, in addition to those presented here, was developed by Peaceman and Rachford8 to simulate the behavior of a laboratory waterflood. Two computational techniques which may be used to simulate three-dimensional flow of two fluid phases are described in this paper. The first method, called the "three-dimensional analysis", employs a fully three-dimensional mathematical model that treats simultaneously both the areal and cross-sectional aspects of reservoir flow. The second method, called the vertical equilibrium (VE) analysis", is applicable

By C. Perez-Rosales

A statistical method for determining simultaneously some of the basic geometrical characteristics of porous media such as porsity, specific surface* mean pore width, mean grain thickness and absolute permeability is presented. The proposed method is characterized by its simplicity and the minimum amount of laboratory equipment that it requires. The experimental procedure used to evaluate the various geometrical characteristics is based 'pan the 'surface analysis Of a a In view of this fact the app1icability Of the method is limited to homogeneous and isotropic materials. INTRODUCTION The behavior of a fluid flowing through a porous medium depends, among other things, upon the internal geometry of the medium; hence the importance of developing efficient methods to determine the geometrical properties of porous materials. This paper describes a statistical method to determine simultaneously some of the basic geometrical properties of porous materials such as porosity, specific surface, mean pore width, mean grain thickness and absolute permeability. The mathematical formulation has been developed that the data required to calculate the various geometrical characteristics of a sample can be easily measured by analyzing a section of the sample with an evenly spaced grid. THEORY A simple way of obtaining information about the internal geometry of a porous material is to throw a point at random over a cross-section of a sample. l-Through this procedure the porosity can be detemined.l,2 By considering that the material is homogeneous and isotropic, and that the point is dropped many times, the porosity 4 is given by where N is the total number of times the point is thrown and n is he number of times the point falls within pore areas. Another simple manner of analyzing the structural characteristics of a porous material is to superimpose an arbitrarily long line on a cross-section so that its length is evenly distributed over the surface area. Through this procedure the porosity can also be determined. If L is the total length of the line, and 1 is the sum of the lengths of the line segments within void spaces, the porosity is given by 4 = —.1.............. (2) The advantage of this type of analysis is that geometrical characteristics other than porosity can be obtained. Thus, if c represents the number of intersections between the line and the perimeter of pores, it can be shown3 that the specific surface, defined as he surface area of pores per unit bulk volume, is given by To give a proper description of the internal geometry of a porous medium, it is necessary to define quantities that characterize the notions of pore size and grain size. Unfortunately, because of the complexity of porous materials, it is difficult to give exact geometrical definitions of what is meant by the ConCePtS of "poresl' and "grains", especially when dealing with consolidated materials. Never theless, one often talks about the "size of pores" and the "size of grains" without defining accurately the terms. A possible solution to this problem follows. Assume that an arbitrarily long line is placed on a section of a sample so that the line is evenly distributed over the surface area (see Fig. 1). 1n a system like this, each line segment within a void space will be, by definition, the pore width in a given location and direction. Consequently, if the

Jan 1, 1970

By C. F. Weinaug, P. M. Blair

Many difference equations used to approximate reservoir flow problems treat the phase pressures implicitly but not the mobility-density coefficients. Such difference equations are neither wholly explicit nor implicit, but might be described as mixed. Mixed equations are relatively easy to apply. But the associated time truncation error is relatively large, and when used to solve problems characterized by high flow rates, these equations may be unstable for practical size time steps. This paper outlines the development of a completely implicit difference analogue for reservoir simulation, along with a Newtonian iterative method for solving the resulting nonlinear set of algebraic equations that arise at each time step. While this implicit equation requires two to three times more work than does the mixed equation, it is shown to markedly decrease the time truncation error and to yield a stable solution for much larger time steps than does the mixed equation. INTRODUCTION Calculation of multiphase, multidimensional flow in porous media is generally accomplished by numerical methods that involve approximating systems of partial differential equations by systems of partial difference equations. The early development of difference equation techniques was directed toward the solution of linear differential systems. However, the equations of multiphase fluid flow through porous media are highly nonlinear in that mobility and density often are strong functions of pressure and saturation. Thus, solution of the flow problems by difference equations involves solving sets of algebraic equations whose coefficients change from step to step of the calculations. Current practice is to evaluate most coefficients at the beginning of a time step and then to apply difference methods well suited for solving linear problems. At least two major difficulties arise from the use of this practice. First, evaluation of coefficients at the old time level and evaluation of pressures at the new time level results in larger time truncation errors near displacement fronts than if all quantities in the distance derivative were evaluated at the same time level. Second, evaluation of mobility coefficients at old time levels results in an unstable difference equation in regions of high flow rate. The first of these difficulties often results in optimistic recovery behind the displacement front, and the second requires the use of small time steps or special techniques in solving coning problems1 or problems of gas percolation.2 Evaluation of all quantities in the distance differences at the new time level results in a completely implicit difference system. Such a difference system has a lower time truncation error than equations in which mobilities are evaluated at the old level and pressures evaluated at the new level. The algebraic equations resulting from the fully implicit difference equation are, in this case, nonlinear and require some iterative method for their solution. This paper develops fully implicit difference equations for two-phase flow in porous media, describes their solution by Newtonian iteration, and gives examples of problems more easily solved by the new method than by previous methods. EVOLUTION OF DIFFERENCE EQUATIONS FOR NONLINEAR PROCESSES The completely implicit difference equation used in these calculations results from evolution beginning with explicit difference equations, proceeding through what we will call "mixed" equations, and arriving now at a completely implicit equation. Let us illustrate the evolution by considering different analogs of the nonlinear equation

Jan 1, 1970

By M. W. Clegg

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

By R. C. Earlougher

Jan 1, 1970

By T. N. Dixon, J. E. Briggs

A study was made of numerical techniques for solving the large sets of simultaneous equations that arise in the mathematical mode ling of oil reservoir behavior. It was found that noniterative techniques, such as the Alternating Direction Implicit (ADI) method, as well as some other finite difference approximations, produce oscillatory or unsmooth results for large time steps. Estimates of time step sizes sufficient to avoid such behavior are given. A comparison was made of the Point Successive Over-Relaxation (PSOR), Two-Line Cyclic Chebyshev Semi-Iterative SOR (2LCC), and iterative ADI methods, with respect to speed of solution of a test problem. It was found that, when applicable, iterative ADI is fastest for problems involving many points, while 2LCC is preferable for smaller problems. INTRODUCTION With the advent of high speed, large memory, digital computers, there has been an increasing emphasis on the development of improved methods for simulating and predicting reservoir performance. Two-dimensional, three-phase reservoir models with various combinations of PVT effects, as well as gravity and capillary forces, are common throughout the industry. Such models are also available through consulting firms, to anyone desiring to use them. Three-dimensional models will probably be practical in only a few years. We conducted a study of some of the numerical methods used for solving the large sets of simultaneous equations that arise in such models. A typical set of equations for a reservoir model is shown below:

Jan 1, 1969

By B. S. Gottfried

This paper is concerned with possible transport mechanisms which occur during segregated burning (i.e., burning in an oil reservoir in which the oil-bearing formation is overlain by a "clean" porous zone containing only gas). ,Two analytical models are presented. In the first, burning is assumed to occur at the gas-oil interface, and the dominant mechanism is taken to be the rate at which oxygen diffuses to the interface. The second model assumes that combustion occurs within the clean zone, with the dominant mechanism being the mechanism of fuel deposition from the oil-bearing formation to the clean zone. ,Comparison of the results of the analyses with limited experimental data indicates that the latter mechanism is much more plausible. Both models are idealized representations of the actual process and are somewhat conjectural, however, owing to the lack of more definitive laboratory or field data. INTRODUCTION In recent years there has been considerable theoretical and experimental research directed toward understanding the recovery of crude oil by underground combustion. Although two different recovery schemes have been proposed, known as forward and reverse combustion, it is only forward combustion that shows promise of becoming a practical recovery technique.17 Most of the analyses of the forward combustion process have considered it to be pistonlike; i.e., oil is displaced by a vertical combustion zone which, with its ensuing gases, pushes die oil forward as the flame front is propagated through the reservoir.l-8,ll,l2,14-16 However, information gained in field pilot studies indicates that, at least to a certain extent, forward combustion proceeds in a segregated manner in oil reservoirs.10 An ideal segregated system is one in which the oil-bearing formation is overlain by a "clean" porous zone containing only gas. The location of the combustion zone in such a system is not immediately evident, although combustion is believed to occur either at the gas-oil interface or within the clean zone. In either case, the combustion zone may be horizontal and it moves in parallel rather than in series with the produced oil. The purpose of this paper is to explore the likely mechanisms by which segregated burning can occur, and to determine the sensitivity of the resulting models to changes in various physical parameters. Two governing mechanisms are considered: the case of a horizontal combustion zone at the gas-oil interface with the rate of combustion governed by the rate at which oxygen diffuses to the interface, and the case of combustion within the clean zone with the combustion process controlled by the transport of fuel from the oil-bearing formation to the clean zone. Both models are somewhat hypothetical and involve considerable simplification of the actual process. However, the results allow some preliminary understanding of segregated burning which is useful in the absence of more definitive laboratory or field pilot data.

Jan 1, 1967

By S. T. Yuster

An analysis has been made of the factors responsible for tilted fluid contacts in petroleum reservoirs. The factors are static and dynamic with the former being controlled by those variables responsible for the capillary rise of fluids, and the latter include rate of formation tilt and hydraulic circulation. The explanation that rate of formation tilt may be responsible for tilted contacts appears untenable. The role of some of these factors in the migration, fractionation. accumulation and possibly the prospecting for oil is indicated. INTRODUCTION While it is generally considered that the segregation of gas, oil, and water in a petroleum reservoir results in approximately horizontal planes separating these phases. there are factor; which modify this simplified picture to a very great extent. Some of these factors are static. and the departure of the fluid interfaces from horizontal may represent a static equlibriun. Some of these factors may be dynamic and the interface positions may be non-equilibrium and represent a steady .state condition. Of course combinations of these two situations may also exist. The reasons most commonly given for this behavior are hydraulic circulation of fluids, change in character of the formation, and a rate of tilt of the formations more rapid than the rate at which the fluids may re-establish an equilibrium. Russell's Principles of Petroleum Geology' contains an extensive discussion of tilted fluid interfaces and their importance in the migration and accumulation of petroleum. Russell cites examples of tilted water tables at Lance Creek, Wyo.; Rock River, Wyo.: Cut Bank. Mont.; Cushing, Okla.: and Graham; Okla. Also given was the Wasson Field of West Texas which has saucer shaped oil-water and gas-oil interfaces with the saucer being deeper in the case of the oil-water contact. The Bradford Field in Pennsylvania has a tilted water table. San Ardo. Coalinga None and some other California field.; have tilled contacts. A recent paper by King Hubbert discuses the effect of hydraulic circulation of the water underlying the oil in a given stratun and it- implications in the accumulation of and drilling for the oil. The foregoing would indicate that tilted fluid interfaces are not uncommon and that it would be of importance to underbtand the forces which are responsible. Further. it would be of interest to examine certain idealized models of situations which may cause tilting with the thought in mind of deriving relatinnships between the important variables. These relationships may only hold exactly for the model* assumed but the results may apply semi-quantitatively to actual formations and at least indicate trends. The discussion will be divided into the effect of static factors and the effect of dynamic factors. STATIC FACTORS It has already been mentioned that one reason given for tilted contacts is a variation in formation properties. Specifically this is a change in the pore size of the formation capilaries. If the internal surface of the reservoir is preferetially wet by water, capillarity will cause the water 10 rise to a greater extent above the free water table in a small capillary than in a large one. Consequently the water-oil contact will be higher in the lower permeability sands than in the higher permeability sand.;. The free water table may be defined as the position the oil-water interface would take if capillarity were absent. Since the phenomenon is the capillary rise of water in an oil environment, a derivation of this shold give a relationship between the variables. Fig. 1 is an idealized model of the situation with a uniform bore circular capillary ubstitttting for the tortuous non.circular formation pore. The upward force.; on the column of water will be equated to the forces downward to give the equilibrium situation. forces upward = force downward where r is the radius of the capillary in ceritimetera. a is the interfacial ten4on oil-water in dynes per centimeter, 0 is the

Jan 1, 1953

By A. S. Odeh

This paper analyzes the effect of limited entry to flow at the wellbore on the steady-state productivity of a well. Wells that have been opened to flow along a fraction of their productive interval are termed wells with limited entry. Previous work treated the cases of a partially penetrating well, a well producing from the central portion of the productive interval and a well in which several intervals equally spaced were open to flow. In this paper the open interval can be located anywhere within the productive interval. Thus, in a sense, it generalizes previous work. The finite cosine transform was used to arrive at a solution for steady-state flow of a slightly compressible fluid. The solution was programmed for a CDC 1604 computer. Numerical vaIues for rd = 660 ft, r, = 1/4 ft, and range of sand thickness of 20 to 200 ft are presented in graphical form. The effect of rd and r, values on the result is shown in a table. The correct calculation of skin and damage ratio in the presence of limited entry to flow is explained and illustrated by examples. Moreover, the paper shows how to calculate the net decrease in productivity due to the combined effect of limited entry and perforations. INTRODUCTION In some wells only a fraction of the productive interval is open to flow. Location of this fraction is usually dictated by formation characteristics and reservoir behavior. For instance, if a gas cap exists, the open interval is located away from the gas-oil contact to prevent any possible gas coning. Wells that intentionally have been opened to flow along a fraction of their productive formation are tened wells with limited entry. Obviously, unintentional completions of this type also exist. Limited entry to flow decreases well productivity. Magnitude of the loss depends on the fraction of the formation open to flow, on the thickness of the sand, on the location of the open interval and on the ratio of rd /r, where r , is well radius and rd is the drainage radius of the well. The use of pressure buildup data on producing wells to calculate the condition of the formation around the wellbore is an accepted practice. van Everdingenl and Hurst2 introduced the concept of she skin factor s considered to be due to a thin layer of different permeability immediately around the wellbore. These authors dealt with the case of a well of complete radial geometry, i.e., a well with open-hole completion that completely penetrates the formation. The presence of a low-permeability skin results in a loss of productivity, as does limited entry. Therefore, if pressure buildup data obtained on a well with limited entry are used to establish the presence or absence of skin (i.e., formation damage), and a correction is not made for this loss of productivity, the calculations would result in an erroneous skin value. They might indicate the presence of formation damage when in reality there is none, or they might indicate a value larger than the true value. This could lead to an incorrect basis for planning remedial measures. Muskat3 studied the problem of partially penetrating wells for the case of incompressible flow. He presented equations and figures which allow estimation of loss in productivity. Brons and Marting,4 using equations based on Nisle's work,5 studied the loss of productivity for three cases. The first was for a partially penetrating well; the second was for a well producing from only the central portion of a productive interval; and the third was for a well in which several intervals equally spaced were open to flow. Their work was for steady-state depletion-type reservoirs wherein the well radius of drainage is established and the fluid is considered to be slightly compressible. Considered in this paper is the problem of wells with limited entry in which the open intervals are located anywhere within the productive sand. The finite cosine transform is used to arrive at a

Jan 1, 1969

By P. J. Closmann

By P. J. Closmann

Steam zone growth as a function of time has been calculated for the case of constant rate steam injection into a preheated reservoir. To simplify the calculation a linear temperature profile has been assumed in the cap and base rock at the start of steam injection. The results indicate that at early times augmentation of steam zone growth due to preheating should be greatest. At longer times the steam zone development becomes close to that calculated with no preheating. INTRODUCTION With the increasing application of thermal recovery processes to recover viscous oil, cyclic steam injection has become important in many large-scale projects. In this process, the cycle of steam injection followed by oil production is repeated a number of times. At the beginning of the second and later cycles, steam is injected into a reservoir that has already been heated but that has lost part of its heat both in produced fluids and by conductive heat loss away from the injection zone. In such a case, the temperature level of the injection zone and the temperature distribution of the surrounding rock will affect the growth of the steam zone developed during the subsequent steam injection. Knowledge of the size of steam zone developed is important in determining the amount of oil displaced and the extent of heating in the reservoir. It is also useful to be able to compute the size of the steam zone for cases where thief zones take most of the injected steam. This paper presents a fairly straightforward method of estimating the steam zone developed in a preheated formation, based on certain simplifying assumptions. Some cases of steam injection into a reservoir at its original temperature have already been considered elsewhere.1-3 Because it is difficult or impossible to obtain an accurate representation of the temperature distribution in the reservoir some time after initial heating has taken place, in this work, a linear temperature profile in the cap and base rock is assumed (Figs. 1A and 1B). The linear profile has the advantage of yielding heat flow equations that

Jan 1, 1969

By R. G. Grieves, G. Thodos

A method is presented for the accurate calculation of the cricondentherm and cricondenbar pressures of multicomponent hydrocarbon mixtures of known composition. The mixtures may contain six and quite possibly any number of components including paraffins, isoparaffins, olefins, acetylenes, naphthenes and aromatics. The approach is similur to that used for calculating critical pressures and cricondentherm and cricondenbar temperatures. The critical pressure, the normal boiling point and the approximate vapor pressure behavior of each component are all that art required. A stepwise culculation procedure is necessary for mixtures containing more than two components. From an analysis of 22 binary systems and 118 mixtures, the average deviation of calculated cricondentherm pressures from reported values is 2.4 per cent. For nine multicomponent mixtures the average deviation is 1 per cent. Considering 19 binary systems and 108 mixtures, the average deviation of calculated cricondenbar pressures from reported values is 1.7 per cent. For 15 multi-component mixtures, the average deviation is 2.2 per cent. INTRODUCTION A knowledge of the phase behavior in the critical region of multicomponent hydrocarbon mixtures is of value both in industrial processing operations and for the optimum operation of gas condensate reservoirs. Accurate methods of calculating the critical temperatures and critical pressures4,6,7,8,9,23 and cricondentherm and cricondenbar temperatures6p10 of multicomponent hydrocarbon mixtures are available in the literature. If the cricondentherm and cricondenbar pressures could be calculated with equal accuracy, the entire phase diagram of a multicomponent hydrocarbon mixture could be well approximated. The work of Etter and Kay6 is limited to systems containing the normal paraffins and has not been tested on systems containing a heavier component than heptane. In addition, the development of their multicomponent equations is based upon a limited number of mixtures containing from three to six components. Silverman and Thodos have considered systems containing both paraffinic and non-paraffinic hydrocarbons, but their correlation is limited to binary systems and is highly inaccurate for methane systems. Eilerts has done extensive work on the cricondenbar pressure; he has produced an excellent correlation for binary systems. However, his procedure for multicomponent mixtures is chiefly useful for highly complex mixtures requiring a knowledge of the vapor-liquid equilibrium behavior of the mixtures; he has not considered the cricondentherm pressure. The objective of this study was the development of an accurate and rapid method for the calculation of the cricondentherm and cricondenbar pressures of multicomponent mixtures containing all types of hydrocarbons and having a wide volatility range. The approach that was adopted is similar to that used by Grieves and Thodos for cricondentherm and cricondenbar temperaturesl0 and for critical pressures.9 However, methane systems had to be considered separately and a modified stepwise calculation procedure was utilized for the cricondertherm pressure. The correlations were developed in a manner similar to those for critical pressures and cricondentherm and cricondenbar temperatures. Based upon binary data reported in the literature it was observed that the ratios of cricondentherm and cricondenbar pressure to the pseudocritical pressure (molar average), pt/ppc and pp/ppc, respectively, in two-component systems depended upon the mole fraction of the low-boiling component and upon the diversity in properties of the two components. A dimensionless boiling-point parameter Tb,/Tb was chosen to represent the diversity in properties of the components. For a binary system, Ti,'is the molar average of the normal boiling points of the two components involved. For a multicomponent system it is either the molar average of the normal boiling points of all of the components involved or the molar average of the normal boiling point of the pure low-boiling component and of the atmospheric boiling point of the low-boiling-free mixture of

Jan 1, 1965

By M. P. Tixier, F. Segesman

Explanations bused on theory and laboratory tests tire offered for certain unusual features of SP logs which may befog their interpretation, namely the "sawtooth" SP and the reduction or increase of SP with time. The sawtooth SP is frequently seen in SP recordings of thick, very permeable watcr. sands of the Louisiana Gulf Coast. Using SP data from a resistor network analog, this anomaly is explained on the basis of a thin shale streak within the sand. under which the invading filtrate accumulates by gravity segregcitiorr. The electromotive force then appearing across the shale streak gives rise to the anomalous SP. Reduction of the SP on successive logging runs Ira often been observed in very permeable sands when as indicated by the resistivity curves, the invasion depth has been reduced to practically zero. Laboratory results verify that this phenomenon may be due, to the presence of air electromotive force, across the mod rake when the fluids on either side differ in activity. Also, there is, in some cases; an increase of SP deflection on successive logging runs, because the emf initially present across the mud cake disappears as the somewhat saline water just behind the mud cake is progressively flushed out by the invading filtrate.. Field example and laboratory data are presented. I N T R ODUCT1ON Some unusual features are frequently observed on certain SP logs which make interpretation difficult. The purpose of this paper is to offer explanations of several cases of interest. All of these arc related to the conditions of invasion. The cases to be discussed are as follows. 1. The sawtooth SP anomaly which is frequently seen within the thick, highly permeable saltwater sands of the Louisiuana Gulf Coast 1. Reduction of the SP deflection from the usual sand line in very permeable sections when the depth of invasion is practically nil. As will be explained, such a reduction is attributable to a membrane electromotive force across the mud cake. 3. An increase of the SP with time just after the iormation is drilled as a result of progressive flushing of the invaded zone. FUNDAMENTALS OF SP PHENOMENA An explanation of SP phenomena must begin with the following basic ideas. 1. The SP log derives its character from ohmic potential differences in the hole produced by currents flowing through the mud.' These currents are driven by electromotive forces which are primarily electrochemical in origin. Other possible types of SP-producing electromotive forces may be disregarded for the purposes of this paper. 2. The electrochemical emf's associated with permeable formations are now understood to consist of liquid-junction emf's and membrane emf's.',' As schematically shown by thc battery symbols in Fig. 1, the liquid-junction emf, E,,,, exists at the contact between waters of different chemical activities, a,,,, (mud filtrate) and tr,,. (formation water); the shale membrane emf, lS.sn. exists across the adjacent shales whcn they separate waters of different activities. The emf's just cited are additivc in producing SP currents (arrowed circles of Fig. I). Thus, neglecting for the moment any possible membrane emf across thc mud cake, the total electrochemical emf, E,, will be given by their sum, where K,., -! K,q,, = 12 + 59, or 71 at 75 °F. In the log interpretations the SP of a thick sand (i.e.. the static SP) is generally related to the activities of the filtrate and formation water through Eq. 1. by setting the static SP equal to - E,.

By Robert G. Nisle

The classic theory of pressure build-up in shut-in oil wells as developed by Horner and van Everdingen is based on two-dimensional radial symmetry in the well-reservoir system. Such symmetry does not exist in the case of a well which parfiially penetrates the producing formation. As a result of this lack of symmetry the use of the classic theory in such cases become questionable. In this paper the mathematical theory has been extended to include the case of partially penetrating wells. Numerical solutions illustrating the up-dication of the equations are presented. The effect of partial penetration on pressure build-up is shown by a comparison of synthetic pressure build-up curves derived from the numerical solution of the equation for partially penetrating wells for various degrees of penetration. It is shown that partial penetration is detectable from the characteristic shape of the pressure build-up curve and that formation productivity may be calculated from the pressure buildup data in a manner identical to that described by the classic theory. INTRO DUCTION The use of pressure build-up data on shut-in oil wells is a well-established technique for the measurement of reservoir productivity. The work of Homer' and van Everdingen' is well known. Since the publication of their pioneering work, others"' have elaborated and extended the technique. These authors have dealt exclusively with the case of wells that completely penetrate he producing formation. Two-dimensional radial symmetry is achieved, thereby, and the problem is greatly simplified. This ideal situation is seldom encountered in practice. But, in spite of this, the technique is often employed anyway. The question, therefore, arises: how much confidence can be placed in the results of such calculations when the data are taken on wells that only partially penetrate the producing formation? It is the purpose of this work to answer this question. Only the single-phase fluid case will be considered. van Everdigen' has presented a rigorous solution of the two-dimensional case, but because of mathematical complexity, this solution has not proved to be particularly useful. Horner' utilized Kelvin's point source solution in two dimensions and showed that it is a sufficiently good approximation for oil reservoir studies. The geometry of the well and the producing formation is illustrated in Fig. l. Geometrically the formation may be described as an infinite slab. The infinite slab is defined as the solid (the porous medium in this case) bounded by two parallel planes. Thus, the slab extends to very great distances in both the positive and negative directions of two of the coordinate axes, but is finite in

By J. J. Arps, T. G. Roberts

Since the introduction of the relative permeability concept in the middle thirties1,2 various investigators have shown3,10,11,12,15 how the basic equations for the flow of oil and gas through porous media can he utilized to compute the recovery from depletion type or solution gas drive type reservoirs under certain conditions, when the necessary physical data pertaining to the reservoir rock and its reservoir fluids are known. In the study by Muskat and Taylor" in 1945, the effects of viscosity, gas solubility, shrinkage, and the permeability-saturation characteristics of the producing formation on the production histories and the recovery of gas drive reservoirs were analyzed. Each parameter was varied a limited number of times, while keeping the others constant. The work was not carried to the point where the data could be used directly to estimate the primary recovery in those cases where certain rock and fluid characteristics were known or could be assumed. Since the publication of this classic study, the work by Beal in 194616 and Standing in 1952'" has established general correlations of oil viscosity and shrinkage with gas solubility and oil gravity. In addition. a considerable number of relative permeability relationships for different types of reservoir rocks has been published2,5,13,17,19,20. Also, the burden of the numerical work required in the solutions of the differential equation has. during the last few years, been greatly reduced with the availability of modern electronic computing facilities. The purpose of this paper is therefore to present the results of a large number of such recovery computations covering the normal range of variation of the main parameters such as the type of rock, the API gravity of the oil, and the amount of gas in solution. As is to be expected, the ultimate recovery is found to increase with the oil gravity. except for the higher solution gas-oil ratios. Within the normal range of solubilities, the ultimate recovery generally appears to decrease with the amount of gas in solution for the higher oil gravities, and to show a slight increase for the lower oil gravities. Intermediate oil gravities seem to fall between the two trends. The type of reservoir rock, as identified by its relative permeability relationship, appears to have a very pronounced effect on the ultimate recovery. In general, sands and sandstones show higher recoveries than limestones and dolomites, although certain intergranular limestones seem to show a higher theoretical recovery than unconsolidated sand. The recovery from sands and sandstones generally decreases with increasing cementation and consolidation, while the recoveries from limestones and dolomites are highest for the intergranular type and lowest for the fracture type porosity.

Jan 1, 1956

By W. R. Foster, J. M. McMillen, A. S. Odeh

The complete equations of average linear momentum balance for a single-phase fluid in an incompreisible, homogeneous, porous medium are derived. The derivation begins with Euler's equation of motion for a continuum and uses an integral transform recently developed by Slattery. 7 For steady flow of a compressible, Newtonian fluid, the usual equations of motion result. For transient flow, the space-time description of the pressure is determined in the lowest approximation by the telegrapher's equation. From the analysis a new phenomenological coefficient results which connects the viscous traction to the deriv ative of the linear momentum density. The magnitude of this coefficient determines the velocity of sound through the pore structure in this approximation to the pressure field. INTRODUCTION The modification of Darcy's law of momentum balance for steady, single-phase flow through porous media has been discussed for many years. The first modification was suggested by Forcheimerl who added terms of higher order in the velocity. These can be expected to appear because the underlying microscopic equations of momentum balance are themselves nonlinear in the point velocity field. The Reynolds tensor pvv, which represents the convective flux of momentum density, appears in the momentum balance equation. Only in rectilinear flow (parallel stream lines) does the divergence of this tensor vanish. Since the steady flow stream lines in most porous media are not parallel, nonlinear dependence of the pressure gradient on the velocity should naturally appear. This nonlinearity has nothing to do with turbulence in the ordinary sense of random fluctuations in the pressure and velocity fields. It arises simply because the stream lines converge and diverge, even for steady flows. Klinkenberg2 demonstrated that the permeability coefficient in Darcy's law depends on the absolute pressure or, alternatively, on the density field. However, because he neglected inertial terms of the Forcheimer type, his correction coefficient could not be represented by a constant but tended toward a constant as the velocity decreased. Forcheimer's and Klinkenberg's modifications can be combined in a rigorous way to account for both inertia and slip during steady flow. This will be shown in a future paper. The transient change of pressure in porous media has been described by the diffusion equation.3 This form results from eliminating the velocity and density fields from a combination of the equations of motion in the form of Darcy's law, the continuity equation and an equation of state. Fatt4 suggested that the cause of deviations from the prediction of the diffusion equation for pressure transients lies not in the choice of Darcy's law as the equation of motion but on the existence of dead-end pores which might invalidate the averaged equation of continuity. On the other hand, Oroveanu and Pascal5 noted chat the time derivative of the momentum density must be included in the equations of motion since this measures the local rate of change of momentum density. Their differential equation for pressure is the telegrapher's equation (neglecting gravity). However, their form of this equation predicts that the speed of pressure propagation through the pore structure is the same as that through the bulk fluid. M. K. Hubbert6 attempted a derivation of Darcy's law by volume averaging the Navier-Stokes equations. Since these equations represent momentum balance at a point within an open set of points containing the fluid itself, Hubbert's volume averaging cannot lead to tenns involving transfer of momentum between the fluid and the walls of the pores. Once these viscous tractions are lost by choosing a control volume containing only fluid, they cannot

By M. Prats

Most of the information available on the heat efficiency of hot fluid injection processes, both water and steam, has been obtained from calculated temperature distributions in the pay zone and adjacent formations. The usual approach has been to write the heat balance equations in terms of the temperatures, and then to introduce whatever simplifications are necessary to help obtain an analytical or a numerical solution. In either case, the assumption has often been made that the vertical thermal conductivity in the flooded interval is infinite, so that the temperatures within the flooded interval are then independent of vertical position. Because it was first made by Lauwerier,l and has been used extensively since, this assumption will be referred to as the Lauwerier assumption. Excellent reviews of the literature on the heat efficiency of hot fluid injection processes have been given by Spillette,2 Flock et al.,3 and Ramney.4 Of course, the most significant contributions take into account the effect of a finite vertical thermal conductivity on the vertical temperature profile. The most general analytic expression for the heat efficiency of a hot fluid injection process is that of Antimirov5 who considers injection of a heated incompressible fluid into a reservoir through an arbitrary number of wells. The rate of heat injection into the reservoir, as well as the injection temperature, is an arbitrary function of time. The geometry of the horizontal flow is arbitrary, although the reservoir is considered to be of uniform thickness and properties and to be of infinite areal extent. Heat transfer within the reservoir is by horizontal convection and conduc- tion, and by vertical conduction. In the formations adjacent to the flooded interval, heat transfer is by conduction in any direction. Thus, the available expression for the heat efficiency due to hot water injection has been developed for rather general conditions. This degree of applicability has not been obtained for other thermal recovery processes. By making the Lauwerier assumption we have been able to obtain expressions for the heat efficiency that are essentially independent of the thermal recovery process, be it steam, hot-water, or underground combustion. Clearly, then, the approach followed here is more restrictive than that of Antimirov5 in that it uses the Lauwerier assumption. At the same time less restrictive assumptions are made about the horizontal heat transfer mechanisms, either in the flooded interval or in the formations adjacent to it. The main difference between our approach and that of other investigators is that the heat balance in the pay zone is expressed for the pay zone as a whole rather than for a volume element within it. The Lauwerier assumption is introduced after the problem is developed along these lines as far as possible. The details of the development of the heat efficiency are given in the Appendix, while the main features of the model are discussed in the next section. Results and their implications are discussed later in a separate section. The Model Certain assumptions have been made to determine

Jan 1, 1970

By D. Havlena, A. S. Odeh

The use of the straight-line method of solving the material balance equation is illustrated by means of six field cases. Also, the application of statistical criteria to arrive at the most probable answer is shown. The theory underlying the straight-line method of solution and the applicability of the statistical criteria was presented in a previous paper.' The field cases include saturated and undersaturated oil reservoirs with and without water drive. The aquifers discussed are: limited radial, infinite radial, very small aquifer and infinite linear. The field cases also include a gas reservoir producing under water drive. INTRODUCTION In a previous paper,' the authors presented the theory underlying the solution of the material balance as an equation of a straight line. The appropriate equations for various material balance cases as well as the methods of analysis and interpretation with comments and discussion were also included. To illustrate the various theoretical cases treated previously, five field cases are analyzed in this paper by employing the straight-line method of solving the material balance equation (MBE) and one example previously published is referred to. The use of statistical criteria to arrive at the most probable answer is also shown. All the field examples presented, except Case 2, are excerpts from complete reservoir studies. To illustrate the method, only sections specifically dealing with the material balance principles are included. Additional geologic information and basic data are reported to better acquire an understanding of the cases and thus to better follow the reasoning that suggested the successful application of the straight-line method of solving the MBE. The six cases are: (1) saturated reservoir, small gas cap, limited aquifer; (2) saturated reservoir, very small gas cap, infinite aquifer; (3) undersaturated-saturated reservoir, very small aquifer; (4) highly undersaturated reservoir, no water drive; (5) high undersaturated one-well reservoir, limited aquifer; and (6) gas reservoir, infinite linear aquifer. THE D4 SAND, GUICO FIELD, VENEZUELA The D, sand, which was discovered in 1943, is presently in a depleted state. Since its discovery it has produced under water drive, gas-cap-gas expansion, and solution gas drive. In Nov., 1947, water injection was initiated to arrest further pressure decline. When discovered, the D, sand was a saturated reservoir with a gas cap /oil zone volume ratio m estimated volu-metrically at 0.0731, an average permeability of 500 md, a porosity value of 25 per cent, and an oil viscosity at reservoir conditions of 0.3 cp. The volumetrically determined stock-tank oil initially in place was 23.1 million bbl. The volumetrically weighted physical data and production data available until Nov., 1953 are reported in Table 1. In Ref. 1, the effects on the straight-line plot of various values of ro/r for a constant ?to, or of various dimen-sionless times for a constant r8/r10 were theorized and were illustrated in Fig. 3A of that reference. In this field case, the previously theoretically predicted effects are established. Thus, the MBE calculations using Eq. 3c of Ref. 1 were performed for various r6/r10 and dimension-less time values. Eq. 3c of Ref. 1 is:

Jan 1, 1965

By J. E. Berry

AII evaluation is made of the acoustic velocity log for measurement of formation porosity. Plots of field-observer1 velocities vs core-measured porosities of sandstones and limestotnes with inter intergranular porosity show that the velocity log gives a useful measure of porotity, in agreement with published data. A new method of plotting electrical and velocity log data makes it easier to recognize hydrocarbon-water coritnct~ from log darn and to make serni-quantitative estinlates of hydrocarbon saturation. Two examples of this interpretation technique are given. This paper also discusses the various factors that affect acoustic velocity and shows how corrections can be made for some of these factors. INTRODUCTION Although the continuous velocity log was developed primarily as an aid to seismic interpretation, it is finding widespread use for measurement of porosity. The purpose of this paper is to evaluate this use of the log. Results are presented for the velocity-porosity relationship in many sandstones and one limestone. Practical applications of porosity values derived from the velocity log to improve interpretation of electrical surveys are presented. Various parameters which affect velocity in porous media are considered. Porosity, composition, cementa-tion, pressure difference (overburden pressure minus fluid pressure), fluid saturation, and wellability are discussed. Some of the ideas are opinions based on general considerations of well logging problems while others are supported by published data and our own observations. Major conclusions from these studies arc given in the body of the paper and detailed discussions of some of the various factors affecting porosity are given in the Appendix. POROSITY Sandstones The primary factor affecting the velocity of sound in porous media is porosity. Wyllie, et al,1 have reported a time average equation for the relationship between velocity and porosity.* This has found considerable acceptance in the industry. Other relationships between velocity and porosity have been proposed, none of which are entirely satisfactory. It is doubtful that any one relationship will completely describe all situations. We have tried an empirical relationship based on correlating log velocities with core-measured porosities. Measured porosities were averaged over a depth interval equal to the spacing used in recording the velocity logs. The depth range for the information used was from 2,000 to 12,000 ft. Velocity measurements were normalized for the effects of depth and overburden pressure. A detailed discussion of the basis for this normalization is given in the Appendix. The change is usually insignificant and when working with individual formations it can be neglected. All velocity measurements were normalized to a depth of 10,000 ft. The velocity-porosity data for sandstones in Fig. 1 came from 20 wells scattered throughout the Mid-Continent and Gulf Coast areas. The scatter of the data points is attributed to three causes: 1. There is no theoretical basis for expecting an exact velocity vs porosity relationship and it is not possible to correct precisely for the effects of such factors as impurities, grain shape, manner of cementation, etc. Some of these factors are discussed in the Appendix. 2. Porosities measured by core analysis are not necessarily representative of what the velocity log "sees". 3. Inaccuracies appear in the velocity log reading. This is particularly true of velocities from one-receiver logging tools.*" A linear-time curve (time-average equation) is plotted in Fig. 1 along with the best straight line through the points. Velocities used for the linear-time curves were 19,500 ft/sec for the matrix velocity (zero porosity) and 5,500 ft/sec for fluid velocity. For clean sandstones with velocities greater than 10,000 ft/sec, there is little difference between the velocity-porosity and the time-porosity curves. Both curves are well within the scatter of data points. The data points in Fig. 1 were restricted primarily to clean sandstones, using the SP and/or gamma-ray logs as clues to the lithology. Where a lithologic de-

By W. F. Kieschnick, and W. J. McGuire&apos, Eugene Harrison

This paper concerns the induction and extension of fractures into rock formations as involved in drilling, completing, and production stimulating operations on wells. Conclusions concerning formation breakdown are derived from (I) a review and extension of published analyses relating to mechanical theories of rock stress and the state of stress in the earth's crust and (2) a correlation of field data from fracturing operations. Conclusions concerning the mechanics of fracture extension, which indicate the relationship between fracture dimensions and rock properties, depth, and volume of injected fluid, are tentative and largely establish limits of relationships. These conclusions are derived from stress calculations, limited field data, and laboratory experimental studies. The experimental work involves the study of the stresses at the fracture boundaries and the geometry of pressurized fractures by means of photo-elastic modeling methods. Results of this investigation indicate that a large majority of pressure induced wellbore fractures are vertical, particularly in deeper wells; and variations in the pressures necessary to create and extend fractures can be explained largely on a basis of established rock properties. It is also shown that variations due to tectonic forces should usually be expected to be slight. Other results indicate that during that extension of fractures rather large fracture volumes are temporarily created by the parting of the formation. The purpose of this paper is to present the results of calculations and laboratory experiments concerning the mechanics of fracture induction and extension with a view to broadening existing knowledge relating to these phenomena. It is believed that continued progress in developing knowledge of this type is important to the further development of techniques for drilling and completing wells. When a wellbore is subjected to sufficiently high pressure, fracturing of the formation surrounding the well occurs. This phenomenon is a common cause of lost circulation during drilling operations, is a deliberately planned factor in most squeeze cementing operations, and is the controlling factor in many productivity stimulation operations. The exploitation of formation fracturing in recent years has been particularly impressive in sand-viscous fluid well stimulation treatments which were first introduced to the industry by the Stanolind research group1,2,3 several years ago. The borehole fracturing phenomenon has been analyzed mathematically by application of the principles defining the elastic and inelastic behavior of thick-walled cylinders of homogeneous, isotropic, and impermeable material.1,5,6 This basic argument is re-presented in this paper along with new considerations which strengthen it. In addition to these arguments relating to fracture induction some calculations and experimental results relating to the mechanics of fracture extension are presented. Since the nature of the pressure induced fracture at distances from the well is of great importance in considerations of well stimulation procedures there appears to be a need for an integrated approach which deals with the mechanics of fracture extension as well as with wellbore rupture.

Jan 1, 1955