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By A. Schild

The effect of heating a producing well on the rate of oil recovery has been analyzed in the simple case of a well producing oil by a radial drive and in the steady state. Differences of production rates with and without borehole heating have been calculated and plotted; these measure some of the benefits of the thermal recovery process. A striking feature is that the production increase tends rapidly to a constant value for large production rates. Some concrete examples, including a rough comparison with field data. are discussed. Heating requirements have been calculated and plotted on the assumption that the heaters used are 100 per cent efficient. Heating has been thought of as applying only to low volume wells producing heavy oils. However, the calculations suggest that the thermal process considered might be profitable even for some wells producing large quantities of light oil, especially in unconsolidated formations where fracturing is not possible. In the case of wells producing other fluids with the oil or of wells producing partly or wholly by gravity drainage, the theory developed does not apply in detail. It can be expected, however, that any general qualitative be-havior will remain valid. Under normal temperature conditions, high viscosity emulsions sometimes form around the wellbore, lowering the permeability in the vicinity of the well and impeding the production of oil. Borehole heating often prevents such emulsification. This important effect is not easily amenable to mathematical analysis and has not been included in the theory presented here. It should therefore be kept in mind that the benefits due to borehole heating may in fact exceed the values given by the following calculations. INTRODUCTION The recovery of viscous, low gravity oils can often be stimulated by applying heat to the production zone. The higher temperature lowers the viscosity of the oil, increasing its mobility, and therefore its rate of production. One thermal method of recovery 1,2,3,4. consists in operating a heater inside a producing well and, at the same time, producing oil from the well. In this paper a simple theoretical model is analyzed to study the effect of such heating on the recovery of oil. The reservoir mechanics of the process is the only aspect of the problem which is considered here. The details of the heating system are ignored, and it is simply assumed that the heater raises the temperature in the immediate vicinity of the producing well to a pre-assigned temperature T w. Although heating requirements are calculated, these refer only to the heat supplied to the formation and to the oil being produced; they do not include heat losses due to the inefficiency of the heater. A short outline of the theory follows: The heat supplied to the producing well flows out into the formation by means of thermal conduction. At the same time, the flow of oil carries heat by convection from the formation towards the producing well. After sufficient time has elapsed, a steady-state is reached where the temperature, the velocity of the oil, etc., no longer vary with time but are functions of position only. In the steady state the temperature decays like an inverse power from the high value Tw at the wellbore to the original reservoir temperature T. at some distance away from the well. The effect of the high temperature and low oil viscosity near the producing well is the same as if the oil were produced at reservoir temperature To but through a producing well of a larger radius. From this point of view, the energy and money being expended to provide heat

Jan 1, 1958

By T. S. Hutchinson, C. E. Kemp

The bottom water drive analysis presented by Muskat has been extended to include fields with wider well spacings. Curves are presented from which volumetric sweepout, water-oil ratio, and rate relations may be calculated. The effects of non-unity ratios on sweepout eficiency and productivity decline have been studied by an approximate method. Also, the effect of gravity on volumetric sweepout has been approximated for a particurlar geometry. INTRODUCTION The purpose of this paper is to report work done in applying the analysis of bottom water drive reservoirs given by Muskat1 to a larger class of reservoirs, to extend this analysis to include the effects of gravity and non-unity mobility ratios in an approximate manner, and to investigate the rate of decline of productive capacity. The bottom water drive type reservoir is one where the oil is underlain by a water zone of sufficient thickness that water movement is essentially vertical. This system is defined in more detail in the appendix and a one well element is shown diagrammatically in Fig. 1. Muskat obtained solutions to the equations describing the volumetric displacement efficiency of idealized bottom water drive systems by assuming that gravity effects due to differences in density betwecn oil and water were negligible and that the mobilities of oil and water were the same. If either of these assumptions is not made, the complexity of the system makes an analytical solution well nigh impossible at the present stage of mathematical development. Coles and Stade' developed an approximation to consider these factors. The authors have refined approximations, starting with the same basic assumption, which should give a somewhat quantitative picture of bottom water drive performance when mobilities are not equal and the effects of gravity are not negligible. The results of these approximate calculations can then be used to obtain the decline in well productivity as the field is depleted.

Jan 1, 1957

By H. J. Morel-Seytoux

Methods of predicting the influence of pattern geometry and mobility ratio on water flooding recovery predictions are discussed. Two methods of calculation are used separately or concurrently. The analytical method yields exact solutions in a convenient form for a unit mobility ratio piston-like displacement. A few typical pressure distributions, sweep efficiencies and oil recoveries are presented for various patterns. For non-unit mobility ratio, one may resort to a numerical method, such as that of Sheldon and Douherty. 1,2 Because the domains of applicability of the analytical and numerical techniques overlap, the exact solutions provide estimates of the errors in the numerical procedures. The advantages of the analytical and numerical methods can be combined. To develop a numerical technique as independent of geometry as possible, the physical space is transformed into a standard rectangle. The entire effect of geometry is rendered through one term, the "scale-factor", derived from mapping relations. The scale factor can be calcu-lated from the exact unit-mobility ratio solution for the particular pattern of interest. By this means recovery performances for arbitrary mobility ratio con be obtained for many patterns. A sample of tesults obtained in this manner is presented. INTRODUCTION Pattern geometry and mobility ratio are two major factors in making a waterflood recovery prediction. Because assisted recovery has become increasingly important to the oil industry, pattern configuration and mobility ratio also assume a greater significance in the assessment of the economic value of recovery projects. The influence of pattern geometry and mobility ratio in shaping a recovery curve and on the other quantities of interest to the reservoir engineer is the main subject of this paper. Much effort has already been spent on estimating quantitatively the influence of either pattern or mobility ratio or both on oil recovery. The literature reports many investigations of this nature. 3-9 However, many results or methods of recovery prediction presented in the literature cannot be considered fully satisfactory. Even for unit mobility ratio and piston-like displacement, where analytical solutions are available, the literature shows discrepancies. For non-unit mobility ratio, the divergence in the results is extreme. For infinite mobility ratio in a repeated five-spot, depending on the investigator, the sweep efficiency ranges from 0 per cent to 60 per cent. With respect to the influence of pattern on recovery, only the repeated five-spot has received much attention. Other confined patterns and pilot configurations have received very little attention. Two calculation methods are presented in this paper, either separately or concurrently: the analytical method of potential theory and the numerical method of finite-difference approximation. The analytical method is more restricted in scope than the finite-difference method, but it has the definite advantage of providing exact solutions within its range of applicability. If a unit-mobility ratio piston-like displacement is assumed, the analytical approach is possible. A few typical results are reported in this paper; the detailed description of the general method and of a great variety of results will be the subject of other articles. Fornon-unity mobility ratio, we must resort to a numerical scheme. The numerical technique is that which was described by Sheldon and Dougherty.l,2 It is not limited to piston-like displacement. However, mainly single interface results will be presented here. Because the respective domains of applicability of the analytical and the numerical method overlap, useful comparisons of exact and numerical solutions can be made for a variety of patterns. The advantages of the analytical and numerical approaches can be combined. The reason for the success of this analytical-numerical approach can be summarized in the following two points: 1. The numerical solution for arbitrary mobility ratio can be programmed most efficiently when the physical space in which the displacement actually takes place is transformed into a standard shape; and 2. This can be done with remarkable simplicity whenever an analytical expression for the pressure

Jan 1, 1966

By C. S. Matthews, H. C. Lefkovits

Drilling progress is often delayed by sticking of the drill string. The development of preventive and remedial methods has been hampered by incomplete understanding of the sticking mechanism. A recent lahorntory investigation hns indicated that one type of sticking may be attributed to the difference in pressure between the borehole and formation. This paper shows, by means of soil mechanics, that the primary cause for differential pressure sticking is cessation of pipe movement, whereas diflerential pressre and stanrtding time determine the severity of the sticking. The analysis stresses the importance of using low-weight muds with low solids content and low water loss to alleviate diflerential pressure sticking and describes why packed hole drilling, long strings of drill collars, and a large deviation from the vertical are conducive to sticking. Finally, preventrve and remedial methods ore evaluated, and a theory is presented on the release of stuck pipe by spotting oil. INTRODUCTION Since drilling with long strings of oversize drill collars has become standard practice in many areas, the incidence and severity of the stuck pipe problem has increased. It has been noticed that in the majority of these cases the sticking could not possibly be attributed to key seating or caving of shales. It appeared that, due to the differential pressure between the mud column and the formation fluid, the collars were pressed into the wall and so became "wall stuck". Points to note about differential pressure sticking are: (1) sticking is restricted to the drill collars, (2) the collars become stuck opposite a permeable formation, (3) the sticking occurs after an interruption of pipe movement, (4) circulation, if interrupted, can be restarted after the sticking is noticed, and (5) no large amounts of cuttings are circulated out after restarting circulation. Helmick and Longleyl investigated pipe sticking by differential pressure in the laboratory and found an empirical relationship between the differential pressure, the sticking time and the required pull-out force. In this paper an explanation of the mechanism is given based on Terzaghi's theory of clay consolidation. A qualitative description is given in the following paragraphs while the derivation of fonnulas is given in Appendices. This paper is a first attempt to explain pressure differential sticking and many points will require additional theoretical and practical investigation before the problem can be fully understood. PRESSURE DIFFERENTIAL STICKING AS A CONSOLIDATION PROBLEM In any borehole, where the mud pressure is higher than that exerted by the formation fluids, a mud cake is formed opposite the permeable sections of the hole and a continuous flow of filtrate takes place from the mud, through the cake and into the formation. This radial flow pattern requires a certain distribution of the hydraulic and the effective (grain-to-grain) stresses inside the mud cake. Any quantitative or qualitative change in the external pressure conditions will produce a change in the flow pattern and, consequently, also in the internal stress distribution inside the cake. In view of the low permeability and the high compressibility of a clay mud cake, the adjustment of the internal stress distribution is slow and is accompanied by a change in volume. Time dependent stresses are thus created which gradually diminish as the new state of equilibrium between internal and external pressures is approached. Some 30 years ago, Terzaghi developed his "Theory of Consolidation" to account for the time-dependent stresses and settling of clay formations under the influence of external loads. He derived a differential equation by which the time-dependent hydraulic stress and the consolidation can be computed for any point inside the layer during the consolidation process. His theory is based on the assumption that the change in stress is solely due to a change in water content and it may only be applied to one-dimensional consolidation phenomena. Other investiga-tors5,10 have expanded his theory to include processes of more than one dimension. The difference between the external pressures on the mud cake before and after sticking is a qualitative one (isolation of part of the cake by the static contact with the drill collars after pipe movement has been stopped)', and the time-dependent stresses thus created may be investigated by means of Terzaghi's theory. By this analysis the changes in the nature of the contact surface between the drill collars and the mud cake during the sticking can be explained; and the friction force between the two may be computed as a function of the sticking time, the borehole dimensions and the mud cake characteristics.

By R. D. Taylor, Jim Douglas Jr., H. H. Rachford Jr., P. M. Dyke

A major obstacle to the use of wetting agents in .secondary recovery by water flooding is the adsorption of the agents on the sand. As a result of adsorption, the surfactant always lags behind the floodwater front. Consideration of the chromatographic theory of adsorption indicates that the detergents will not lag as much if used in very high concentrations. An investigation was made of the possibility of using high concentrations economically by flowing slugs of wetting agents followed by normal flood water. The experiments consisted of adsorption studies on Alundum powder and Berea sandstone. Flow rests on a 12-in. Alundum core and 22-in. Berea core were used to determine rate of detergent movement. The results of the flow experiments indicate that the relative rate of surfactant advance is, indeed, sensitive to the concentration of the agent. A 10 per cent slug moved with a rate that war 78 to 95 per cent as fast as the rate of advance of the flood water. By contrast, one with 25 ppm (the number of parts of commercial detergent in a million parts of water on a weight basis) concentration moved less than one-fourth as fast as the flood water, and calculations indicate that in very long porous systems the rate of movement of the lower concentrations will be a small fraction of the rate of advance of the flood front. The results. of the adsorption studies were utilized to calculate the rate of advance of the detergent when only the initial concentration was known. The calculated rates showed substantial agreement with the experimental flow tests in the high concentration ranges. The adsorption results were also used to estimate the cost of the materials for a slug-type surfactant flood in the field. In addition to the faster rates of movement, the concentrated detergent slugs removed much more oil than the dilute solutions. However, the effectiveness of the slug process depends on many variables. The quantity of oil removed is increased markedly by increasing the flooding rate. The efficiency is also influenced by the type of crude, type of reservoir rock and initial water saturation. Therefore, a careful analysis of each reservoir system is required before the economic value of the process can be determined. INTRODUCTION It is well known that the displacement of oil by invading water during water flooding is far from complete. It is generally agreed that the unrecovered oil is retained in the porous medium by the capillary forces which may be relatively large compared to the forces generated by the flowing water. Therefore, it was logical that some early workers should turn to surface-active materials to reduce the capillary forces to facilitate the release of oil. As early as 1927,' a patent was granted for the use of surface-active materials in water flooding. In 1932, when soap solutions were passed through Bradford and Venango sands, it was reported that the results were inconclusive, erratic and that "further investigation is needed to determine exactly the function of the solution and to obtain a clearer insight into the phenomena involved."' Some of the modern scientific reports conclude with a similar statement,' showing that the lack of agreement on the mechanism of oil removal by wetting agents is still very widespread even though several comprehensive studies have been reported.'." Although there is a lack of agreement as to the general effectiveness of the detergents for water flooding, most investigators do agree that all of the common detergents are strongly adsorbed onto the solid surfaces of the reservoir. In the early calculations it appeared that all additives would be lost before reaching much of the formation area which contained the additional oil to be removed. Experiments indicated that if the usual small waterflood concentrations of wetting agents were used, the rate of advance of detergent through the formation would be only a small fraction of the rate of advance of the flood front. Indeed, some investigators4 felt that the use of wetting agents would never be economically feasible because of their adsorption. For example, DunningG estimated that the wetting agent in concentrations of 25 ppm, would advance only 0.05 times as fast as the flood front. Ojeda, et al,' found that a surfactant in a concentration of 10 ppm moved less than 0.01 times as fast as the flood front. It is significant, however, that both investigators found that increased concentrations of wetting agents moved faster, relative to the flood front, than solutions at the lower concentrations. Ojeda showed that an extrapolation of his data indicated a relative rate of 0.5 at 1 per cent concentration, while Dunning6 estimated a relative rate of 0.46 for a 1 per cent concentration. It was obvious that these concentrations could not be used for continuous injection because the cost of the injected detergent would far exceed the value of additional oil produced. Traditionally, detergents are used in very low concentrations for they show good

By H. Hooykaas

A few years ago Marsal published a method of predicting oil recovery as a function of time for an edge-water-drive reservoir with several rows of wells.' The method is based solely on oil- and water-production data obtained during a short period for the first row of wells and the gross productions (past and future) of all wells. This paper presents a streamlined version of the original publication and experimental evidence showing the reliability of this version. For this purpose scaled experirnents were performed in a large model (750 X 500 X 23 cm, 24.4 ft X 16.2 ft X 8.9 in.) in which edge-water-drive reservoirs with three rows of production wells were simulated. From the results of the experiments it is concluded that the method gives a fairly accurate prediction of the future production behavior of the reservoir and enables us to select the most profitable production plan. Results obtained with the method were always slightly conservative. INTRODUCTION The calculation method developed by Marsal aims at forecasting future reservoir behavior.' It can be applied to floods in which a number of down-dip wells are rapidly going to water. Essentially it is a method for predicting the future behavior of the up-structure wells on the basis of the observed behavior of the down-structure wells. As such, the method is especially useful for predicting behavior of edge-water drives toward several rows of wells. The requirement to be met for justifying the approach is identity of production mechanism in all regions of the reservoir. The attraction of the method then lies in the fact that it applies even when we have no complete description of the prevailing production mechanism. The original publication was in the German language and for this reason, perhaps, did not attract widespread attention. In our opinion it deserves to do so because it does offer in a simple way results which are in fair agreement with observed data. The aim of the present paper is to bring the method to the attention of a wider audience. The method in its most simplified form is reviewed and experimental data in support of it are presented. PRINCIPLES To show Marsal's principle. we will first write the continuity equation for very simple conditions, linear flow (in the positive x-direction) in an incompressible porous body [cross-section A(x), porosity +(x)], saturated with incompressible fluids (oil saturation S). When the oil in this formation is displaced by water, injected at x = 0 (inlet face), we get where q(t) is the total gross displacement rate and f the fractional oil flow. The equation can be solved if we make the assumptions: (1 ) that the fractional oil flow (f) is a univalent function of saturation (S); and (2) that the function is the same throughout the porous medium. Then: f = f(S) Solving this equation with the method of characteristics, we obtain

Jan 1, 1966

By E. J. Bonet, P. B. Crawford

It is fairly common practice to reinject water into the aquifer near the oil-water interface in water-drive reservoirs. There have been many studies of aquifer behavior without reinjection,l-5 but apparently no analytical studies have been made to indicate performance when injection wells are present in the aquifer. The diffusivity equation may be used to describe the pressure behavior in an aquifer. When sources are present it can be written as A general solution of Eq. 1 may be obtained as the sum of two solutions. One is a general solution of the homogeneous equation, obtained by dropping the source term in Eq. 1 and still satisfying the required boundary conditions. Another is a general solution of Eq. 1 satisfying homogeneous boundary conditions.1° The first solution, which corresponds to the aquifer without reinjection, has been given quantitative and qualitative treatment in the literature.l-5,8,9 The latter solution will be treated here. Solutions with variable injection rates are obtained by superimposing solutions with constant rates, so we have considered only the latter. Five cases have been treated here: 1. A linear aquifer of finite width and extent. Water is injected into the aquifer at point xo, yo at constant rate. The pressure along the line x = 0 is maintained at zero pressure. (See Fig. 1.) Equations showing the pressure distribution, rates, velocity and cumulative influx have been developed. Certain numerical results are shown. 2. A linear aquifer of finite width and extent. Water is injected into the aquifer at point xo, yo at constant rate. The rate of production along the oil-water water contact is maintained constant. Equations showing the pressure distribution inside the aquifer are presented. 3. A linear aquifer of finite width and extent. Constant pressures are maintained at opposite ends of the aquifer. Water is injected at constant rates at point xo, yo. Equations showing the pressure distribution are shown. 4. A linear aquifer of finite width and infinite extent. The pressure is maintained constant at the oil-water contact. Water is injected at a constant rate at point xo, YO. 5. A linear aquifer of finite width and finite extent. The pressure at the oil-water contact is maintained constant. Water is injected at constant rate per unit length along a line x,. The Linear Aquifer The linear closed aquifer, performing at constant terminal pressure was selected as the first case to be analyzed. The development of the equations is based on uniform injection per unit of thickness, and gravity effects are neglected. In practical application this condition is probably most closely achieved when the

Jan 1, 1970

By J. S. Lasater

Resu1ts of experinmental measurernents of heat capacities and thermal conductivities of some typical porous rocks are presented. Measured heat capacities agree closely with va1ues calculated front known chenlical . compositions of the rocks. On the basis of this agreement, heat capacitir.7 of fluid-satttrated rocks were calc~ililted. Therrnal conductivities of the rock samples were measured under varioits conditions of fluid saturation. From these data therrnal dif-fvsivities were calculated. A significant variation of thermal diflusivity with trnlperature is indicated. Knowledge of the thermal characteristics of fluid-bearing porous rocks has become increasingly important with the development of thermal oil-recovery processes. Reliable thermal data for petroleum reservoir rocks are not available and approximate values are generally assumed for reservoir calculations. 'The effects of temperature, pressure and fluid saturation on thermal properties of porous rocks have not been carefully studied. The purpose of the present work was to measure and report the thermal characteristics of some typical porous rocks. A group of eight sedimentary rock samples, including limestone, shale, sandstone and silt-stone, was selected for the study. Properties reported include heat capacities, thermal conductivities and thermal diffusivities. The effect of fluid saturation on these properties was also considered. Determinations of thermal properties require precise measurements which are time consuming and difficult to reduce to a routine basis. Methods have not been developed for measurement of thermal proper-ties under conditions of pressure, temperature, and fluid saturation, which may be encountered in thermal recovery processes. As one approach to these problems, some preliminary work on methods of estimating thermal properties from other more readily measurable characteristics of the rock-fluid system is reported. The samples selected for the studies were oilfield cores from within, or closely associated with oil-productive zones. Descriptions of individual samples are given in Table 1. Clay minerals present in the samples were determined by differential thermal analysis (DTA). Quartz content was estimated from DTA cooling curves. For all but the thermal conductivity tests, a representative 200-gm sample of each core was disaggregated, thoroughly extracted in diox-ane and oven dried at 100°C. The cleaned and dried sample was care- fully split into appropriate portions for the several tests. Chemical analyses of the samples were obtained to permit calculations of heat capacities by methods which are outlined later. Resuits of chenlical analyses are given in Table 2. Heat contents of the test samples were measured by a Runsen-type calorimeter. The heat content of the unknown sample is measured relative to the known heat content of platinum. The apparatus is referred to as a relative error type because of the comparative measurements, and has the advantage of canceling systematic errors. Experimental results are reproducible within 0.5 per cent. A temperature base of 298.16 K is taken for heat content measurements. Measurements were made at five temperatures (260, 440, 620, 800 and 980° F). It was necessary to preheal the sample above the maximum experimental temperature to eliminate volatile constituents. Assuming the weight loss on pre-heat, ing was mostly water, a correction to the observed heat content was made to account for the water originally present in the sample. This latter procedure was followed in the determination of calculated heat contents as will be described later. The apparatus and the method of measure-

By N. R. Morrow, C. C. Harris

The experimental points which describe capillary pressure curves are determined at apparent equilibria which are observed after bydrodynamic flow has ceased. For most systems, the time required to obtain equalization of pressure throughout the discontinuous part of a phase is prohibitive. To permit experimental points to be described as equilibria, a model of capillary behavior is proposed where mass transfer is restricted to bulk fluid flow. Model capillary pressure curves follow if the path described by such points is independent of the rate at which the saturation was changed to attain a capillary pressure point. Aemodified suction potential technique is used to study cyclic relationships between capillary pressure and moisture content for a porous mass. The time taken to complete an experiment was greatly reduced by using small samples. INTRODUCTION Capillary retention of liquid by porous materials has been investigated in the fields of hydrology,l soil science,2 oil reservoir engineering,3 chemical engineering," soil mechanics,5 textiles: paper making: and building materials In studies of the immiscible displacement of one fluid by another within a porous bed, drainage columnsl and suction potential techniques2 have been used to obtain relationships between pressure deficiency and saturation (Fig. 1). Except where there is no hysteresis of contact angle and the solid is of simple geometry, such as a tube of uniform cross section, there is hysteresis in the relationship between capillary pressure and saturation.2 The relationship which has received most attention is displacement of fluid from an initially saturated bed (Fig. 1, Curve R2), the final condition being an irreducible minimum fluid saturation Swr. Imbibition (Fig. 1, Curve A), further desaturation (Fig. 1, Curve R), and intermediate scanning curves have been studied to a lesser but increasing extent.2 ,3,9-12 This paper first considers the nature of the experimental points tracing the capillary pressure curves with respect to the modes and rates of mass transfer which are operative during the course of measurement. There are clear indications that the experimental points which describe these curves are obtained at apparent equilibria which are observed when viscous fluid flow has ceased; and any further changes in the fluid distribution are the result of much slower mass transfer processes, such as diffusion. Unless stated otherwise, this discussion applies to a stable packing of equal, smooth, hydrophilic spheres supported by a suction plate5 with water as the wetting phase and air as the nonwetting phase. The discussion can also be applied, in many

Jan 1, 1966

By H. H. Rachford, D. S. Howard

In the withdrawal of fluids from tilted aquifers it is of value to be able to predict pressure patterns during the course of the pressure decline. As an example of this, in the displacement of fluids from oil reservoirs being produced by water-drive, prediction of the reservoir pressure is an important factor in fixing production rate. The prediction of pressure patterns in the depletion of an inclined aquifer has conventionally been made by solving the well known flow equations for the pressure Patterns in a horizontal aquifer, and correcting these patterm for the pressure difference due to the hydrostatic head associated with the vertical distance between a point in the horizontal aquifer and the corresponding point in the tilted aquifer. Inasmuch as the equation describing flow in tilted strata is different from that for horizontal flow. there was question as to the validity of the simple corrective procedure current1y in use. To examine the magnitude of error made using this procedure, an inclined aquifer was chosen for which the error was expected to he large, and the equation for flow in this tilted stratum was solved numerically. The results of the conventional procedure of correcting the solution of the equation for horizontal flow was compared with the solution of the correct equation by studying the difference between predicted pressures by the two methods. Three forms of the hydrostatic head correction were studied. The results for all three forms of the head correction are similar. The error in the approximate solution is quite dependent on the position of the horizontal aquifer with respect to the inclined one. The error is greatest at the producing end ad increases with amount of fluid withdrawn. The magnitude of the errors is not large if a good choice is made for the position of the horizontal datum. The most satisfactory position for the datum in all cases is near or slightly about the mid-point of the inclined stratum. Use of the best approximate method studied with the best datum tested yielded predicted pressures in error no greater than 7 psi. INTRODUCTION The movement of water by expansion from an aquifer to displace fluids from a contiguous oil reservoir was first recognized over 20 years ago.9 Since that time much work has been done to relate this mechanism to reservoir behavior mathematically. The result of this effort on the part of many workers has led to an understanding of underground fluid movement which has enabled us to follow and predict the behavior of the water-drive reservoir. One reason that good progress has been made in the application of mathematics to the study of pressure patterns and water movements in aquifers has been that the differential equation which describes this process is of a relatively simple form. The equation for the isothermal, horizontal, viscous flow of water through homogeneous sandstone is identical with that for the diffusion of heat through homogeneous solids, and this equation and means of obtaining solutions for it with many types of boundary conditions have been studied extensively. That this work has been highly successful is clearly emphasized by the large number of solutions developed for problems of interest both by methods of formal mathemat-

Jan 1, 1957

By F. F. Skiba, P. J. Root

A mathematical model has been used to investigate crossflow effects in a stratified reservoir during an idealized displacement process. A process in which one incompressible fluid displaces completely another incompressible fluid of the same density and viscosity was considered. The reservoir was assumed to be composed of homogeneous layers which are discrete but interconnected. Approximate five-spot flow geometry was simulated by arranging two pie-shaped cylindrical (two-dimensional) wedges in series. Some of the common production methods rely, for their effectiveness, on the fact that the formation consists of isolated strata. This is particularly true of selective plugging and single-zone production-injection methods. The effectiveness of these techniques for several cases in which adjacent strata are in communication has been evaluated. The usual production-injection schemes for fluid injection processes involve using the same completion interval in both the production and the injection wells. The efficiency of this, as well as alternative productioz-injection procedures has been examined for some cases involving communicating strata. INTRODUCTION The performance of many fluid injection projects is marred by early breakthrough and by production of a high percentage of the displacing phase after breakthrough. This channeling effect, if it occurs in reservoirs which have large permeability variations, is often explained on the basis of a model composed of discrete, isolated strata. Corrective or preventive measures based on this same model are also common. The behavior of stratified models has been the subject of considerable study. An excellent review of the early literature was given by Seba.1 Studies of the depletion performance have since been made for continuous, unrestricted communication between strata2-4 and for production from one permeable bed in continuous but restricted communication with an adjacent permeable bed.5,6 Model studies of displacement processes in stratified systems with crossflow also have been reprted.7-12 Finally, methods which account for crossflow have been developed for computing displacement behavior in stratified systems.13,14 Most methods for controlling or preventing channeling involve some change in the interval open to production and/or injection. Although many variations of the selective completion problem have been studied in regard to the depletion of a reservoir, little attention has been given to the behavior of a displacement process under similar conditions. Sebal used a resistance network model to study the performance of a process in which one incompressible fluid displaces an identical fluid from a linear, stratified reservoir. He investigated the possibility of improving the vertical coverage by limiting the completion interval of the production well. This investigation deals with techniques in which selective completion of the production and/or the injection wells is used in an attempt to control channeling. At one extreme, selective plugging and single-zone isolation (assuming perfect execution) should be successful if the reservoir is actually made up of independent strata. At the other extreme, they can hardly be expected to be successful if the channeling is caused by a mechanism in which stratification effects are negligible even though there are extreme variations in the formation permeability and/or the injectivity profile of the wells is not uniform. By contrast, it is difficult to anticipate the effect that the amount of communication between the beds of a stratified system will have on the efficiency of selective completion techniques. The objective of this study is the quantitative determination of the effect of communication on the behavior of some particular stratified systems which will at least lead to qualitative conclusions.

Jan 1, 1966

By J. J. Arps

This paper reviews the methods currently in use for estimating primary oil reserves and discusses the principles on which these methods are based. Particular emphasis is placed on how these methods change with the type of information available during the life cycle of an oil property. This paper contains various novel estimating methods and shortcuts heretofore unpublished. INTRODUCTION Estimating oil reserves is one of the most important phases of the work of a petroleum engineer since the solutions to the problems he deals with usually depend on a comparison of the estimated cost in terms of dollars, with the anticipated result in terms of barrels of oil. His recommendations to management regarding the best course of action are therefore normally based on the most favorable balance between these two. Specific engineering problems which require such a knowledge of recoverable oil reserves and a projection of future rates are: [a.] the exploitation and development of an oil reservoir; [b.] the construction of gasoline plants, pipelines and refineries; [c.] the division of ownership in unitized projects; [d.] the price to be paid in case of a sale or purchase of an oil property, and the magnitude of the loan which it will support; [e.] the proper depreciation rate for the investment in oil properties; and [f.] evaluation of the results of an exploration program. This discussion will be confined to the various methods and tools which are currently in use for estimating oil reserves to be obtained during the primary phase of an oil-producing reservoir and for a projection of the future production rates. Reserves which may be obtained by secondary recovery methods or fluid injection programs and gas and gas condensate reserves will not be discussed in this paper. Unfortunately, reliable oil reserve figures are most urgently needed during the early stages when only a minimum amount of information is available. Management's interest in the oil recovery from a property—aside from its use for accounting purposes—usually declines when the property approaches its economic limit, just at the time when the reliability of the estimates is at its best. To illustrate this general idea a chart is presented (Fig. 1) showing the three periods in the life of an imaginary oil property. Time is shown on the horizontal axis, while the cumulative production and estimated ultimate recovery are plotted vertically. No particular units are used and this schematical chart is not to scale. During the first period, before any wells are drilled on a property, any estimates will of necessity be of a very general nature, based on experience from similar pools or wells in the same area, and usually expressed in barrels per acre. This will

Jan 1, 1957

By H. S. Price, J. C. Cavendish, R. S. Varga

This paper presents a new technique for solving some of the partial differential equations that are commonly used in simulating reservoir performance. The results of applying this technique to a simple problem show that one obtains accurate pressure values near wells, as well as accurate pressure pdients, which can be explicitly calculated. The method is completely rigorous in that convergence of the discrete numerical solution to the continuous solution for both pressure and pressure gradient is established. High-order, piecewise-polynomial approximations are used near the wells where pressure gradients are steep, while low-order, piecewise-polynomial approximations are used elsewhere to reduce greatly the calculation time. This combination is shown to give a uniformly good approximation to the solution. These approximations, obtained by using a Galerkin process with suitable Hermite subspaces, are shown to be theoretically and numerically superior to the usual approximations obtained from standard finite-difference techniques. Not only are much greater accuracies obtained, but computer times are also greatly reduced. The application of this technique to multiphase flow problems (e.g., single well coning problems) would have considerable practical interest, but such extensions of this technique with full mathematical rigor have not been made as yet. However, the numerical methods presented here are general, and in principle extend to multidimensional, multiphase flow. Moreover, the preliminary results given in this paper are sufficiently encouraging that we feel the effort in attempting these extensions is justified. INTRODUCTION The problem of obtaining accurate pressure distributions and pressure gradients around wells is of considerable importance in the numerical simulation of reservoir performance. The most common approach to solving this problem is to use finite difference techniques (see McCarty and Barfield9 or Peaceman and Rachfordl0). This approach, however, has many disadvantages, the major one being that many grid points are generally necessary for accurately describing the pressure distribution and the pressure gradient around wells. This need for a fine grid results in large computer times and often in prohibitively high costs. Besides investigating the method of finite differences, some authors, such as Welge and weber17 and Roper, Merchant and Duvall,13 have considered a combination of analytical and numerical techniques with some success. These approaches, however, are all nonrigorous and quite often cannot even be applied. In this paper, we present a numerical formulation of high-order accuracy, based on the Galerkin method, for solving this problem. We treat here only the partial differential equation that describes steady-state, single-phase flow. However, the methods presented are general and in principle extend to multidimensional, multiphase flow. Specifically we treat special cases of the problem in two dimensions described by: where G is a rectangle (with sides parallel to the coordinate axis) with boundary ?G, ?/?n denotes the outward normal, and y and B are non-negative constants such that y + B > 0.

Jan 1, 1970

By B. H. Caudle, A. B. Dyes

In a recent publication' it was shown that wells with a free surface in a homogeneous gravity-drainage reservoir have a hyperbolic decline with index n '. This paper reports efforts to extend this theory to practical field cases. As a first step in making the extension, a large number of lease production curves from gravity-drainage fields in the stripper stage were fitted with the general hyperbolic decline equation, q/q, = 1/(1 + y) y and n in each case being determined by statistical methods. It was found that this equation is reliable for decline curve extrapolation for periods up to at least 25 years. The resrilts obtained were disturbing in the sense that values for the index, n, were often smaller than one, which fact leads to the prediction that a well would produce all infinite amount of oil in infinite time. A theoretical investigation based on the results of the previous paper provides a suitable explanation for these low values of n. It suggests that these are obtained if production occurs from two or more layers of diflerent permeabilitv and thicktress or two lnyers having different skin effects. It is predicted that as the more permeable layers are exhausted, the index of decline, n, will rise from a value smaller than 2, to n = 2. A practical method is given for fitting the general hyperbolic decline Eq. 6 to production decline data. When this method is used, the index of decline observed in gravity-drainage reservoirs in the stripper stage when wing only data over early years 01 decline usually agrees quite closely with that determined using data over 25 years or more. This indicates that the hyperbolic decline equation is reliable for predicting behavior of such reservoirs. A method is also suggested for taking into account any changes in the value of the index INTRODUCTION As a result of both experimental work with models and theoretical deductions, it was recently concluded' that wells having a free surface in a homogeneous reservoir producing by pure gravity drainage should have a hyperbolic decline with n = 2. The present report details efforts to extend this work on ideal homogeneous reservoirs to actual field cases. It should be remembered that both the previous work and the present extension are based on the assumption that the reservoir is at very low pressure, and hence, nearly all the potential available for driving fluid to the well is the gravity head. Attempts to apply conclusions of this study to reservoirs which have considerable pressures supplementing the gravity drive may lead to difficulty. WELLS WITH NO FREE SURFACE In a dipping gravity-drainage reservoir such as that shown in Fig. 1, some of the down-dip wells have no free surface. The previous study' showed that the up-dip wells, which have a free surface, should follow Eq. 1. The following approximate analysis, of a type which was justified experimentally for up-dip wells in the work just mentioned, leads to results for the down-dip wells.

By M. H. Gaskell, D. M. Kehn, G. T. Pyndus

A correlation of the bubble point pressure for black oil systems is developed using the standard physical-chemical equations of soiutions. The correlation is based on 158 experimentally measured bubble point pressures of 137 independent systems and is expressed in terins of the usually measured field pnrameters— flash separation gm-oil ratio, rank oil gravity, total gas gravity, and reservoir temperature. The data were obtained on systems produced in Canada, Western and Mid-Continent01 United States, and South America. The average error (algebraic) in the representation is 3.8 per cent, and the maximum error encountered is 14.7 per cent. INTRODUCTION In the absence of experimentally measured properties of reservoir fluids, it is often necessary for the field engineer to make estimates regarding the fluid properties based on the usually measured producing parameters. To aid in these estimations, various correlations have appeared in the literature in recent years. Among the pertinent properties of interest is the bubble point pressure. A correlation for this parameter has been reported by Standing'. However, this correlation was based essentially on California produced crudes and this limitation was pointed out with its presentation. The correlation presented in this paper utilized data on crude oil systems from Canada, Wes- tern and Mid-Continental United States, and South America. CORRELATION DEVELOPMENT The basic assumption used in this development is the same as employed by Standing', There is a wide variety of ways to combine these parameters; however, in this instance the combination was made on the basis of Henry's law2. Accordingly, the relationship proposed is Although Eq. 2 defines an individual system, it is of limited value since H' is a function of gas-phase composition and the system temperature. It was observed that for the systems where the bubble point was measured at several temperatures that the ratio of the bubble point pressures and the ratio of the corresponding absolute temperatures (R) were practically identical. Thus, for correlation purposes the bubble point pressure may be taken as a direct function of the absolute temperature. This relation is valid only for those systems that are not near the critical point. Accordingly, this correlation will be inadequate for systems in the region of the critical point. The solubility of the various hydrocarbons found in the gas phase increases with the molecular weight. Thus, the saturation pressure should be inversely related to the gas gravity. Applying these principles to Eq. 2 and rearranging terms gives: The variables 02 the left side of Eq. 3 were designated as the "hubble point pressure factor". The number of mols of tank oil per barrel is a function of the "mclecular weight" of the tank oil. Although the tank oil is a complex mixture, it was assumed for the purposes of this correlation that a unique molecular weight could be assigned to a given oil. This was designated as the "effective molecular weight", and was related to the oil gravity, This empirical relationship was developed simultaneously with the correlation by assuming values of M,. and working to obtain a smooth curve for both the correlation and the effective molecular weight. The relationship between the oil gravity and the effective molecular weight used in this correlation is shown in Fig. 1. The effective molecular weight is somewhat higher than the molecular weight of the C fraction. The difference between these values is largest for the low-gravity systems. It is noted that this effective molecular

By L. H. Simons, H. H. Spain

I NT RODUCTION Theory indicates that linear water-floods should exhibit scaling and stabilization properties in both oil-wet and water-wet porous media'. Experimental verification of these proper-ties in oil-wet media was obtained some time ago', and more recently, Perkins', employing a high permeability unconsoli dated sand and a low oil-to-water viscosity ratio, has obtained flooding data in a water-wet medium which follow the pattern of scaling and stabilization. Also, Root and Calhoun3 have found similar trends in the displacement of gas by liquids from unconsolidated sands. In general, however, the experimen-tal evidence appears still somewhat conflicting since scaling and stabilization of water floods in water-wet media has not been observed in most of the studies to date'.".'. The purpose of this paper is to provide a more comprehensive picture of waterflood behavior in water-wet media and to corroborate the validity of the scaling and stabiliza-tion concepts. The need for differentiating between the intrinsic nature of water-oil displacements inside a porous medium and perturbating secondary end effects is discussed, pertinent experimental procedures are outlined and the results of flooding tests conducted at low and at high oil-to-water viscosity ratios on con- solidated, water-wet Alundum cores are analyzed. END EFFECTS IN WATER-WET MEDIA Outlet End Effects The peculiar feature of the outlet end effect in water-wet cores is that it not only results in an excessive wetting phase saturation at the outflow face,'.' but that it also retards the moment of water breakthrough: i.e., causes an undue delay in the appearance of water in the produced effluent. Conditions existing in a water-wet core when water first arrives at the outflow face are schematically shown in Fig. 1. At this flooding stage the saturation distribution, Fig. la, has not yet been distorted by the outlet end effect. A water-invaded pore at the outlet core face, opening into the oil-filled void space between the end of the core and the end plate of the flooding cell, is illustrated in Fig. lb. The curvature of the water-oil interface is concave toward the outlet, and the pressure on the water side of the interface is lower than on the oil side by an amount equal to a certain capillary pressure (Fig. lc). Before the water (of this particular pore) can be produced from the core, it is apparent that the pressure in the water phase must exceed that in the oil outside the core. Accordingly. when water first reaches the outlet face, it will not leave the core but will accumulate inside, and only oil will be produced. Eventually, as the water injection is continued. sufficient pressure is built up in the water to reverse the curvature of the interfaces in the outlet pores, and only then will water be produced from the core. This stage, illustrated in Fig. 2. corresponds to the conventional "water breakthrough" observed in flooding experiments. For purposes of discussion, it is convenient to distinguish between the flooding stage at which water first arrives at the outlet face of a core (Fig. 1) and the stage at which water is first produced from the core ( Fig. 2). The former will be referred to as "water arrival" and the latter water breakthrough. In oil-wet media

By W. A. Burns

Vertical flow is an important mechanism in many petroleum reservoirs. Yet no adequate method has heretofore been proposed for determining the in-situ vertical permeability in a reasonable length of time. Core measurements of vertical permeability do not necessarily represent effective in-situ values. Cores may be representative of only localized pockets of high or low permeability, and total reliance on cores might cause one to overlook the presence of vertical fractures altogether. Conventional single-well tests, interference tests, and pulse tests commonly are used to determine horizontal transmissibility, khh/u, but generally are not designed to measure vertical trans-missibility or other groups containing vertical permeability, ku. A new well test described here provides a measure of in-situ vertical permeability as well as the previously measurable horizontal permeability. This "vertical test" determines the vertical diffusivity, kv/gcu, and horizontal transmissibility, khd1/u (where dl is the length of injection or production perforations). The test is basically a short-term interference or pulse test normally lasting less than a day. Conventional down-hole equipment is used between two isolated sets of perforations in the same well, as shown in Fig. 1. A "layer-cake" description of a reservoir can be obtained by running two or more vertical tests in the same well, each over different vertical intervals. Each test can be analyzed for the effective vertical and horizontal properties of the interval tested. In addition, a vertical well test can determine the effective- ness of a shale barrier or tight zone by testing across it. Field use to date of vertical testing has confirmed its utility in reservoir description. Mathematical Basis Interpretation of vertical tests for ku and kh is based on comparison of measured pressure response with computer-generated response. Pressure behavior during a vertical test in a homogeneous, anisotropic, infinite-acting reservoir (infinite in radial extent and bounded in both directions vertically) is given by the diffusion equation for slightly compressible fluids with negligible gravity effects.l A schematic diagram of the problem is presented in Fig. 2, and an analytic solution, based on the image

Jan 1, 1970

By A. M. Sarem, J. M. Campbell

Molecular refraction is introduced as a new and improved third parameter for prediction of the PVT behavior of hydrocarbon systems. This parameter, characterizing the complex as well as the pure hydrocarbon systems (1) is a direct measure of London dispersion forces which affect the PVT behavior; (2) can be measured directly, accurately and easily for complex as well as pure hydrocarbon systems; (3) varies significantly between the reference substances thus allowing accurate interpolation of PVT properties; and (4) has a fundamentally sound basis. Molal average molecular refraction was used with the pseudocritical mixing rule proposed by Leland and Mueller to predict the molal volume of liquid and vapor for 84 published data points on nC4-nCI0, Cl-nC5, Cl-nC4-nC10 systems in the region of coexisting vapor-liquid and at the critical point. The same technique was applied to predict the densities of liquid hydrocarbon mixtures in the two-phase and single-phase regions near the critical point for seven different systems each having different properties of the heptanes-plus fraction, but all simulating the fluids of either gas-condensate or volatile oil reservoirs. A modification of the Leland-Mueller mixing rule for the determination of pseudocritical properties is also presented which yields more accurate liquid density predictions than the original form when used with the proposed third parameter. INTRODUCTION The PVT behavior of multicomponent systems has received widespread attention in the literature in recent years. A large portion of the reported work has stemmed from attempts to overcome the inherent difficulties encountered when using the standard compressibility-factor chart which shows 2 as a function of reduced temperature T, and and reduced pressure p,. This chart assumes that z, is constant for all systems. The error in this assumption is not pronounced for pipeline-type gases high in methane and low in heavy ends, particularly when contained at moderate pressures. For such gases the error in the calculated z is usually less than 2 to 3 per cent. However, the reliability of this approach becomes somewhat nebulous for gas condensate and volatile oil systems at high pressure. One logical approach has been to recognize the variation of 2,. This idea was first suggested by Meissner and Seferianl and used by Lyderson, Greenkorn and Hougen2 to prepare extensive tables of thermodynamic properties. Other third parameters have been proposed by Stockmeyer, Kihara, Riedel, Lightfoot, Bloomer and Pitzer. These were tested by Satter and Campbel13 for many gas mixtures and it was shown that they were inter-related. All of these third parameters have a common fault — they cannot be directly evaluated for the heptanes-plus fraction. Consequently, one necessary requisite of an improved method for predicting the density of multicomponent hydrocarbon systems, was development of a third parameter that could be evaluated for that fraction. PREVIOUS MULTICOMPONENT DENSITY PREDICTION METHODS Sage and Lacey4 suggested a method of using partial molal volumes for computing the density of hydrocarbon gas mixture for pressures to 3,000 psi. In this technique, they approximate the complex multicomponent gaseous mixtures by a quarternary system of methane, ethane, propane and butane. Sage, Hicks and Lacey5 suggest a method of using partial molal volumes for computing the density of hydrocarbon liquids. The results agree within 3 per cent of the experimental values. However, the composition range is limited to about 10 per cent by weight of methane. Consequently, this correlation does not cover the low-molecular-weight liquid similar to natural gasoline and high-pressure gas condensates.

Jan 1, 1966

By Michael P. Robinson

It has been suggested that streaming potentials are not nomlally logged because the streaming potentials known to be generated across mud filter cakes are substantially cancelled by streaming potentials generated in contiguous shale beds. Laboratory measuments of streaming poterztials acrons hand specirnens of shale have been adduced as evidence to support the suggestion. The experiments show that streanzing potential depends on the resistivity of the equilibrating solution and on pressure drop. Meizsurenlents were made perpendicular to the bedding planes of the shales. The mechanism of streaming potential generation in shale which the suggested cancellation theory iniplies has been critically examined. Conclusions reached are tested by comparing self potentials logged before and immediately after changing the resistil~ity (but not the weight) of mud in a borehole. The resultant SP change is found to equal the theoretical electrochetnical potential change, i.e., cancellation of .strearning potential is independent of mud resistivity. Since streaming po/entials generateal across mud filter cakes depend critically upon mud reistivity, shale .strearlling potential in situ must he equally sensitive. Using plausible values for the pemleahility, porosiy arzd compressibility of shale, the van Ererdingerl-Hurst approach shows that the pressure drop between horehole pressure and formation pressure in a radially honzogeneous shale is unlikely to coincide with the zone of filtrate invasion. If, perchance. this coincidence occurs with one mud a chatzge 10 a second must result in non-coincidence, i.e., a .YP logged in the second mud should show a streaming potenlial. The dilernrna may he overcome by postrrlating: (I) perrneabilities of shale7 parallel to their beddine planes greatly exceed their cross-bedding permeabilities; (2) a resistivity-sensitive mud cake of low permeability forms either on the face of, or probnhly in the lanlinations of, many shales. These postulates are examined with reference to the pres.sure and SP histories of the McClosky and Aux Vases zones in the Illinois Basin and some srcpport for them found. It is concluded that a definitive solultion to the streaming potential problem does not exist. INTRODUCTION Recently Gondouin and Scala' published a contribution to the streaming potential problem which is notable particularly for the elegance of its experimental techniques. The conclusions drawn by Gondouin and Scala from their studies amplified those previously suggested by Schehck'. In essence they suggested that the streaming potentials known to develop across mud filter cakes" are not normally observed on SP logs because they are largely cancelled by streaming potentials generated in adjacent shales. This suggestion appears so reasonable that many workers in the logging field will be prone to accept it. We incline strongly to the view that the suggestion is basically correct. Nevertheless, it is important to realize that the cancellation hypothesis in the form put forward by Gondouin and Scala does not appear to meet all the known experimental facts. It is the principal intention of this note to call attention to what appears to be a flaw in the relevancy of the experimental evidence adduced by Gondouin and Scala and to suggest an alternative hypothesis to remove it. The consequences of the new hypothesis are compared with field data which, we believe, are unique. A second but not less important purpose of this note is to emphasize that even the new hypothesis does not fully explain all field observations. Hence we conclude that further study of the streaming potential problem is required before it can be said that a definitive solution to it has been attained. The bare experimental bones of laboratory data on streaming potentials appear to be as follows. 1. A streaming potential is developed across a mud filter cake. This streaming potential is virtually independent of cake thickness but depends on the mud resistivity. The relationship is of the form, 2. A streaming potential is developed across a shale. This potential is independent of shale thickness but depends on the resistivity of the permeating solution if the shale has been first equilibrated in this solution. The relationship is of the form, The relationship in (1) was determined first by Wyllie3, confirmed by Gondouin and Scala and qualita-

By H. Kazemi

An ideal theoretical model of a naturally fractured reservoir with a uniform fracture distribution, motivated by an earlier model by Warren and Root, has been developed. This model consists of a finite circular reservoir with a centrally located well and two distinct porous regions, referred to as matrix and fracture, respectively. The matrix has high storage, but low flow capacity; the fracture has low storage, but high flow capacity. The flow in the entire reservoir is unsteady state. The results of this study are compared with the results of the earlier models, and it has been concluded that major conclusions of Warren and Root are quite substantial. Furthermore, an attempt has been made to study critically other analytical methods reported in the literature. In general, it may be concluded that the analysis of a naturally fractured reservoir from pressure transient data relies considerably on the degree and the type of heterogeneity of the system; the testing procedure and test facilities are sometimes as important. Nevertheless, under favorable conditions, one should be able to calculate in-situ characteristics of the matrix-fracture system, such as pore-volume ratio, over-all capacity of the formation, total storage capacity of the porous matrix, and some measure of matrix permeability. INTRODUCTION The analysis of flow and buildup tests for obtaining in-situ characteristics of oil and gas reservoirs has received considerable attention in the past decade. Most of the available techniques result in reliable conclusions in macroscopically homogeneous reservoirs or in the homogeneous reservoirs with only certain types of induced and/or inherent heterogeneity (such as wellbore damage, etc.). In general, the greater the degree of heterogeneity, the less the reliability of the information deduced from the pressure transient data. A commonly encountered heterogeneous system is a naturally fractured reservoir where two types of distinct porosities occur in the same formation. The region containing finer pores may have high storage and low flow capacities. This is called the matrix. The remaining region may have high flow capacity with low storage. The latter region is generally the set of interconnecting fractures and fissures of the rock, and for this reason it is called the fracture. Ordinarily, we wish to obtain the permeability and porosity of each region and perhaps the frequency of the fracture distribution in a reservoir. Such information is necessary for reservoir engineering. Other information, such as wellbore damage, will be useful in evaluating possible remedial work for such fields. Few authors have suggested theories to aid in calculating the in-situ characteristics of a naturally fractured reservoir similar to what we have described above. Pollardl suggested that a naturally fractured reservoir contained three distinct regions: a damaged or an improved region surrounding the wellbore, and the two remaining regions the same as described earlier. He suggested that the flow was taking place from the tight matrix into the highly conductive fractures, then into the we wllbore region and finally into the well column. He concluded that the average pressure buildup in each of these distinct regions can be expressed approximately in terms of an exponential decay function of time. He also hypothesized that the decay coefficients for each of these functions were significantly different from each other; consequently, each of these functions became dominant in turn, in the process of pressure buildup. Thus, by a proper graphic plot of the logarithm of wellbore pressure differences vs buildup time, each of these functions could be determined (see Fig. 1). Pollard suggested methods of determining the wellbore damage and fracture volume. Later Pirson and Pirson2 extended

Jan 1, 1970