Reservoir Engineering Problems Research Articles

The role of diffusion transfer in the evolution of heterogeneous reservoir systems

Taking into consideration time and dimensional relationships suited to geological data, scientific examinations of reservoir engineering, thermodynamical and geochemical boundary problems are dealt with. Based on Hungarian and international observations, it is assumed that due to the presence of hydrocarbons an increased precipitation and clogging take place in the boundary zones of hydrocarbon and water systems. This phenomenon is proved by static and dynamic model tests as well as by thermodynamic examinations. This phenomenon can be explained by the diffusion of CO 2, which is a common component of hydrocarbon and water that are immiscible with each other, and by the formation of an apparent extraction process. In the course of geologic ages, this phenomenon takes place even at very small concentration differences and has an influence on the formation of the full ionic mixture system.

The Use of Capillary Tube Networks in Reservoir Performance Studies: 1. Equal-Viscosity Miscible Displacements

Abstract This paper concerns the use of network principles to study displacement phenomena in porous media. The information presented is for equal-viscosity, equal-density miscible displacements. The paper explains the reasons for using an interconnected network of capillary tubes to model the interconnected network of pores in a reservoir rock. A method is presented for defining the heterogeneity of a presented for defining the heterogeneity of a network of tubes based on tube-size and tube-location distribution functions. A technique is described for constructing a network whose heterogeneity models the heterogeneity of pores in a reservoir rock. The use of networks to provide information which can be used in the solution of reservoir engineering problems is illustrated with example calculations of the effect of heterogeneity on fingering, breakthrough, and selective plugging in linear systems, and the effect of heterogeneity on areal sweep efficiency in a five-spot pattern. Introduction Oil in a reservoir is contained in an interconnected three-dimensional network of pores. Direct evidence of the nature of this network of pores comes from examination of petrographic thin sections and three dimensional Scanning Electron Microscope (SEM) pictures of the pores. The SEM pictures show that the pores in a reservoir rock are channels through which flow can occur. These channels have highly irregular configurations so irregular that it is not practical at this time to calculate flow behavior through individual channels or through the interconnected network of the channels. It is practical, however, to use a computer to calculate flow behavior in an interconnected network of capillary tubes and several investigators have studied the problem of using a network of tubes to model a network of pores. pores. Fatt pioneered the idea of using a network of cubes model for reservoir engineering studies. He demonstrated that capillary pressures, relative permeabilities, and electrical resistivities permeabilities, and electrical resistivities calculated for a network model have the same characteristics as those measured for real pores in reservoir rocks. From this, Fatt concluded that the network of tubes is a valid model of real porous media. Rose reinforced Fatt's conclusion and showed that computers can be used to study the displacement characteristics of networks and to obtain results "…which can be supposed to have a direct bearing on the mechanics of petroleum recovery…" This paper takes two steps beyond the work of Fatt and Rose. First, it describes a technique for constructing a network whose heterogeneity models the heterogeneity of natural pores. This is done by matching calculated equal-viscosity miscible displacement behavior in the network with measured behavior in a laboratory core. Second, it illustrates the use of the network model for calculating the effects of heterogeneity on fingering, breakthrough, and plugging in linear systems and areal sweep efficiency in a five-spot pattern. The networks used in the studies in this paper consist of several hundred interconnected capillary tubes of different sizes. Four different types of connections or configurations were investigated and are shown below. These configurations are discussed in detail later in the paper. SPEJ P. 99

Reservoir Engineering in the 70's and 80's

Most of the significant contributions to reservoir engineering were made by a handful of prodigious giants in the 1930's and 1940's. The most significant contribution we can make in the next 20 years will be to fully understand -- perhaps with the help of that latest prodigy, the computer - what those giants were driving at. Introduction Reservoir Engineering is a branch of engineering that derives its name from the phrase "petroleum reservoir". The derivation of the term "petroleum engineering" might be considered in somewhat the same fashion. In either case, it is the petroleum reservoir that is all-important because the authority of a petroleum engineer usually ends somewhere between petroleum engineer usually ends somewhere between the oil field and the refinery. Unfortunately, neither the term "petroleum engineering" nor the term "reservoir engineering" is adequately descriptive. These terms mean nothing to a layman, and only little more to other engineers. This problem has worried many members of the Society of Petroleum Engineers for some time. Although it is possible to coin names more descriptive of our function - Energy and Natural Resources Engineering, Geohydraulics Engineering - such names still miss the mark in many respects. So do definitions of either petroleum engineering or reservoir engineering. A frequently cited definition of reservoir engineering is "the application of scientific principles to the drainage problems arising during the principles to the drainage problems arising during the development and production of oil and gas reservoirs". This definition misses the mark, also, in that the essence of reservoir engineering is only hinted at in the word "problems". The reservoir engineer tries to optimize the drainage of a valuable fluid from a subterranean reservoir of generally unknown size and character. This is the problem; he is working with something he never sees. problem; he is working with something he never sees. As F. H. Allen has said, "Petroleum Engineering, certainly as it will be practiced even more so in the future, is a very indirect science. We cannot even get in direct contact with the oil and gas in their native reservoirs. We can only deal with indirect readings and conduct operations from the surface of the ground which we hope will have certain effects at depth". Indirect determination of some characteristic of an object is a well established method usually introduced in elementary general science courses. The mass of an object may be determined directly with a beam balance, or indirectly from the measured volume and density of the object. In reservoir engineering it appears that there is no hope of ever physically examining the object directly. It is not physically examining the object directly. It is not likely that we shall mine or exhume many reservoirs. Thus the responsibility of the reservoir engineer usually involves a two-step process: to make and interpret indirect measurements of the quantitative characteristics of the reservoir, and to employ this information and basic physical principles to forecast the behavior of the reservoir under any potentially useful production scheme. potentially useful production scheme. Although significant publications concerning reservoir engineering problems began to appear in the 1920's, this field of study began essentially only 35 years ago. Major subjects such as multiphase flow through porous media and the material balance for an oil reservoir have appeared during this period. JPT P. 33

Graphical Determination of the Constants in the Corey Equation for Gas-Oil Relative Permeability Ratio

The Corey equations for relative gas and oil permeability and the gas-oil relative permeability ratio are: (1) SL − SLR 2 SL − SLR 2krg = 1 − 1 − Sm − SLR 1 − SLR (2) SL − SLR 4kro = 1 − SLR (3) SL − SLR 2 SL − SLR 21 − 1 − krg Sm − SLR 1 − SLR=kro SL − SLR 4 1 − SLR where SL is the total liquid saturation and equal to 1 minus the gas saturation (1 - Sg), and where Sm and SLR are constants. Eq. 3 for the relative permeability ratio has been found to give a fairly accurate representation of actual relative permeability ratios in many cases. It is sometimes used to test, extrapolate and smooth experimental data. It can also be useful when a convenient analytical expression for relative permeability ratio is required in computer programming of reservoir engineering problems. The shapes of Corey relative permeability ratio curves for some selected values of the constants Sm and SLR are shown in Fig. 1. Since Eq. 3 contains only two constants, knowledge of two points on the curve of krg/kro vs Sg is sufficient to evaluate both constants. The algebraic solution of the two simultaneous equations is tedious, however; and the graphical method developed by Corey in his original papers appears to be incorrect and is at best a method of successive approximations that requires repetitive graphical constructions and numerical computations as well. This inconvenience has probably prevented the Corey equation from receiving the attention it deserves from reservoir engineers. The first objective of this paper is to present a simple graphical method for determining the constants of the Corey equation from two known points. The second is to present a graphical method, eliminating numerical computations, for determining enough additional points to permit construction of a reasonably accurate plot of relative permeability ratio vs gas saturation over the region of interest in reservoir engineering calculations. The method makes use of three figures (Figs. 2, 3, and 4). Each intersection of the lines plotted on these figures corresponds to one value of SLR and one value of Sm as indicated by the labels. The values plotted on the vertical and horizontal scales are the gas saturations at two different values of the gas-oil relative permeability ratio, krg/kro. The location of each intersection is found by substituting the chosen values of SLR, Sm, and krg/kro into Eq. 3 and solving for SL. Since (1 - SL) is Sg this gives the gas saturation corresponding to the given values of SLR, Sm and krg/kro. This was done for each combination of SLR and Sm at the same two chosen values for krg/kro, yielding two values of Sg for each combination of SLR and Sm. These two values of Sg were then plotted, one vertically and the other horizontally, to mark the intersections, and then lines were drawn connecting points of constant SLR and constant Sm. Each of the three figures was constructed in the same way, but for a different pair of krg/kro values. Once each figure is constructed, it provides a compact source of information on the relationships between the two gas saturations at the two different values of krg/kro and the Corey equation constants, SLR and Sm. P. 1111ˆ

A THEORETICAL INVESTIGATION ON THE FORMATION FACTOR/PERMEABILITY/POROSITY RELATIONSHIP USING A NETWORK MODEL*

ABSTRACTThe knowledge of hydraulic and electric properties of porous media and the relations between them is essential for the quantitative evaluation of electric well logs and the solution of other reservoir engineering problems. The state of the art in this field is not yet satisfying. Theories still show considerable discrepancies with practice due to oversimplified model approaches. Empirical relations are either too coarse, not fully determined, or valid under specific geological and geographical conditions only. This article deals with the development of a general theory of the electric and hydraulic resistance behavior of porous media on the basis of a very general statistical network model. A general solution of the relations between formation factor, permeability, and porosity is presented by means of a rigorous mathematical treatment of two limiting cases of such a network. The solution shows that the product of the formation factor and the permeability can be expressed in the expectation values and the variation coefficients of pore channel cross section and shape factor and by a network factor, that depends on the mesh texture of the network. This network factor is in the range zero to one. It is further shown that the path length increase enters both the electric and the hydraulic tortuosity by its square.

Fundamentals of Reservoir Fluids

Editor's Note: The following paragraphs briefly introduce and summarize material to be found in a five-part series of Technical Articles which will be published in consecutive issues of JOURNAL OF PETROLEUM TECHNOLOGY. This series will cover the fundamentals of sampling, testing, adjusting and interpreting oil and gas sample data for use in reservoir studies. The first installment begins on page 12 of this issue. References, Tables and Figures will be numbered consecutively, but will be published only with the particular installment of the series in which they are first mentioned. Fundamentals of Reservoir Fluids--Introduction During the movement of oil and gas to the surface from the reservoir in which they are found, the temperatures and pressures to which they are subjected change significantly; as a result, their physical properties undergo many radical changes. The economic value of produced oil and gas is dependent upon these physical properties, and the operator finds it invaluable to be able to predict handling and producing techniques which will allow him to produce his reserves in a form that will provide a maximum profit. For many years, therefore, investigators have studied the phase behavior of hydrocarbon materials with the goal of fully developing methods for determining answers to problems concerning the physical behavior both of produced hydrocarbons and of those that are left in the reservoir. Written material regarding the fundamental physical concepts governing hydrocarbon behavior and describing the methods employed in practically applying these concepts to solving production problems is scattered throughout the literature. The purpose of this series, therefore, is to bring together these concepts and methods of their application in solving practical, day-to-day reservoir engineering problems. When production starts and pressure is reduced in a hydrocarbon reservoir, both liquid and gas are formed from what was at first only a liquid (as in an oil reservoir) or only a gas (as in a gas reservoir). One or the other of the two phases (liquid and gas) is produced differentially to some degree because of variations in permeability of the rock to gas and oil as saturations change. Therefore, the hydrocarbon analysis of the composite produced materials changes from that of the original material in place in the reservoirs. Obviously, then, the behavior of reservoir fluids during production operations becomes quite complex, and it is necessary to obtain laboratory analyses of the initial reservoir fluids for conditions of change where liquid and gas separate both differentially and under equilibrium conditions. With these data, production problems involving separation under various conditions can then be solved. The practical approach to the study of reservoir fluid behavior is to anticipate pressure and temperature changes to which the reservoir material will be subjected during production operations, both in the reservoir and at the surface; then the changes to reservoir fluid samples, which occur for each of these pressure and temperature conditions, are measured by laboratory tests. The study of oil and gas reservoir performance requires quantitative data on the composition, characteristics and behavior of the oil and gas in the reservoir under original conditions; in addition, similar data must be obtained for the oil and gas under all changing conditions of temperature and pressure-as the materials move to the wellbore, as they are produced to the surface, and as they are either gathered in the stock tank or piped to the consumer. The laws for perfect gases and perfect solutions do not apply, without modification, to the behavior of hydrocarbon mixtures. Although in recent years many investigators have made notable progress toward developing means for quantitatively evaluating hydrocarbon phase behavior, the industry still does not have a reliable theoretical method by which it can accurately and completely calculate the behavior of complex hydrocarbon mixtures under high pressures. Where the production problem deals with changes in the reservoir material under conditions approximating that of equilibrium conditions, such changes may be calculated with reasonable precision. For this purpose, the concept of K-values has been employed. A K-value is the ratio of the mole fraction of a component in the equilibrium gas phase to the mole fraction of the same component in the equilibrium liquid phase. In essence it is a measure of volatility, which is controlled by the balance between molecular forces at the condition of temperature and pressure to which the material is subjected. A complete description of equilibrium calculations, how they are made, their qualifications and application to reservoir engineering problems will be covered in this series.

Volumes of Liquid Hydrocarbons at High Temperatures and Pressures

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 288–292. Abstract One of the major difficulties in predicting the performance of oil reservoirs from their early pressure history lies in the uncertainty of estimating the volume of the liquid hydrocarbons contained in them. As a first step in filling this need, an equation was developed to determine the molal liquid volume of pure hydrocarbons over a wide range of temperature and pressure. The second step consisted of adapting the equation to apply to mixtures, with the heavy hydrocarbons expressed as C7+. The equations are similar in form to van der Waals' equation, but the constants a and b are considered as functions of temperature. In addition to the gas constant R, there are four constants characteristic of each hydrocarbon. When compared with experimental values found in the literature, the average absolute deviation in the calculated molal volumes is found to be a maximum of 0.33 per cent for any of the pure liquid hydrocarbons studied. This maximum deviation was that found when comparing the calculated and observed values over a temperature range of 86° to 482°F and a pressure range from the bubble-point to 10,000 psia. The equations expressing the correlation for mixtures were developed from 647 experimental measurements of volume on 47 bottom-hole samples covering a temperature range of 72° to 250°F and a pressure range from bubble-point to 5,000 psig. The average absolute deviation was found to be 1.6 per cent with the maximum for any measurement of 4.9 per cent. Introduction Accurate information of the pressure-volume-temperature behavior of hydrocarbon liquids is of considerable importance in the field of both applied and theoretical science and, especially, in the solution of petroleum reservoir engineering problems. These PVT relationships can be expressed graphically, in tabular form or as equations of state.

Analysis of Waterflood Performance - Block VI Ranger Zone, Wilmington Field, Calif.

Abstract An engineering analysis of the performance of the Block VI Ranger zone water flood operation from its inception in July, 1956, to date is presented. Implications of this performance with respect to future potential of a full-scale project are interpreted. Details are given of the expansion program currently underway, together with a description of the cooperative plan of operation in effect with offset operators. The dual purpose to be accomplished in the flood is explained. The objectives are to effect an economic waterflood operation and to control subsidence of the overlying area through control of reservoir pressure. Reservoir engineering and mechanical problems connected with the operation are treated. Introduction The first waterflooding Operations in the Ranger zone of Wilmington field, Los Angeles County, Calif., were initiated in July, 1956, as a pilot operation on the Producing Properties, Inc., N–1 and S–1 leases in Fault Block VI. The project is situated near the most easterly extension of the field and in the region where the Ranger zone underlies the downtown area of the city of Long Beach. The N–1 and S–1 leases of Producing Properties, Inc. are communitized leases comprising approximately 346 acres of town-lot development. Because the drilling of oil wells is prohibited by city ordinance within the area of these leases, the development drilling was accomplished from drill sites located on the west berm of the Los Angeles County flood control channel. This strip, which is located approximately 1,400-ft west of the western limit of Fault Block VI, is 26-ft wide and 5,570-ft long. As will be seen later, the fact that all wells producing from the properties are slant holes drilled from the western drill site has created unique problems in waterflood planning and in interpretation of the results observed in the pilot operations to date. At the time pilot operations were commenced, a total of 65 producing wells existed on the two leases in Fault Block VI; cumulative production had reached 8,889,773 bbl of oil, 12,191,422 Mcf of gas and 398,214 bbl of water. The Parcel A properties of the city of Long Beach. operated by Richfield Oil Corp. and bordering the pilot area to the south, had reached a development of 20 wells and had produced 2,348,465 bbl of oil, 3,764,623 Mcf of gas and 79,607 bbl of water. Development drilling in Fault Block VI of the Ranger zone stops at Pine Avenue in the city of Long Beach, or at its linear projection. The oil-productive Ranger zone unquestionably extends to the east in substantial development beyond this arbitrary boundary. The pilot area is offset to the north by the E. C. Simmons N–3 lease which had two producing wells and had produced 141,315 bbl of oil, 218,046 Mcf of gas and 11,531 bbl of water. Thus, at the commencement of the pilot operation. cumulative production from the Fault Block VI Ranger zone had been 11,379,553 bbl of oil, 16,174,091 Mcf of gas and 489,352 bbl of water.

The Application of the Diffusivity Equation to Linear Flow Problems in Oil and Gas Reservoir Engineering

Sample solutions of the diffusivity equation for linear flow are derived in this paper. These solutions can be used to investigate the flow problems qualitatively in oil and gas reservoir. An example is presented to show the application of the equation to predictions of production performance in natural gas reservoir of completely dissolved-in-water type.

Effect of Unsteady-State Aquifer Motion on the Size of an Adjacent Gas Storage Reservoir

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 18–22. Abstract In natural gas storage operations, seasonal pressure fluctuations in the gas reservoir cause the water from the surrounding aquifer to flow into and out of the gas sand. The theory of unsteady-state liquid flow through porous media developed by Van Everdingen and Hurst has been applied to predict the water movement into and out of the gas bubble for several postulated pressure cycles. Those cycles with as many pound-days above the original aquifer pressure as pound-days below, may cause the gas reservoir to slowly grow or shrink rather than hold to a constant volume. Applications to an actual field case study give the predicted gas reservoir monthly pressures and volumes as compared with the observed monthly pressures and volumes. Introduction A large number of natural gas storage reservoirs are bounded by or adjacent to large water-saturated formations called aquifers. The presence of these aquifers is usually evidenced by the production of water from wells delineating the gas-bearing sands. Some gas storage reservoirs in use today have been purposely developed on aquifers. Cyclic pressure variations in a gas storage reservoir cause water influx and efflux from the surrounding aquifer. This, in turn, results in a varying gas reservoir volume. The prediction of the effect of this aquifer fluid movement on the size and size variation of the gas reservoir can provide information valuable in the study of several reservoir engineering problems. The economics of gas storage operations are directly influenced by the influx of aquifer fluid into the reservoir since a shrinking storage reservoir requires increasing pressures for the storage of the same quantity of gas. Material balance and reserve or recovery calculations also obviously require knowledge of reservoir volume. Various other reservoir engineering calculations such as interpretation of well interference data, evaluation of physical characteristics of porous media, water coning, gas injection and pressure maintenance studies are typical problems where variations of volume due to edge or bottom-water encroachment becomes important.

A Comparison of Calculated krg/kro Ratios With a Correlation of Field Data

Abstract It is shown that krg/kro ratios computed on the assumption that the average sandstone reservoir has a poresize distribution characterized by a linear 1/Pc2 saturation plot are in good agreement with corresponding krg/kro ratios obtained by Wahl, Mullins and Elfrink by the correlation of field measurements. Equation for Calculating krg/kro Ratios Methods of calculating relative permeability data have recently been reviewed and extended. It was shown that for sandstone reservoirs where 1/Pc2 is approximately a linear function of effective saturation (as suggested first by Corey) it is possible to express relative permeabilities in very simple terms. For systems wetted by connate water and producing oil and gas (gas saturation growing at the expense of oil) the expression for the krg/kro ratio is ....................(1) The accuracy of Eq. 1 has been frequently confirmed in our laboratories; because of its simplicity we make routine use of it in the analytical solution of problems in reservoir engineering. Nevertheless, comparisons of the krg/kro ratios yielded by Eq. 1 with appropriate reservoir data have been few. The publication by Wahl, Mullins and Elfrink of an empirical equation for krg/kro ratios is thus of interest since this equation is specifically stated to be based on the correlation of field measurements made on sandstone reservoirs.

Application of Large Computers to Reservoir Engineering Problems

Abstract The primary applications of automatic computing equipment to the field of engineering are (1)the development of engineering information more economically and (2) the production of improved engineering analyses. While experience has demonstrated that both large and small computers are useful in the first application, it presently appears that the large computer will be required to investigate multiphase flow and to predict the flow behavior of oil and gas reservoirs considering two- and three-space dimensions. Some of the mathematical difficulties which arise in connection with the equations describing flow of fluids in oil and gas reservoirs are briefly reviewed, and some of the recent developments in the application of numerical techniques to reservoir engineering problems are discussed. The general computational requirements for typical problems of this type are included, and the specific time requirements for effective application of a few of the newer analyses to actual reservoir cases using both large and small computers are compared. Introduction The advantages of using high-speed computing equipment in engineering work fall generally into two categories. First, it is possible to conserve engineering manpower in that the inherent high computing rate of these devices can be directed so as to perform the engineering calculation work of many men. The second and potentially more significant advantage afforded by effective application of the high-speed computer is the ability to produce information which otherwise would not be available to the engineer. This is usually made possible by employing new or improved methods of analysis. New and improved methods of engineering analysis are beginning to evolve from the aggressive research programs on the application of numerical methods which various industrial research groups initiated five to 10 years ago. Techniques have been developed for studying problems in reservoir mechanics, such as unsteady gas flow and flow of single-phase fluids in two- and three-space dimensions, and improvements have been made in techniques for studying multiphase flow.

Composition Correlations of Natural Gas in Reservoir Engineering Problems

Abstract This paper is presented as a summary report of the use of well gas composition correlations obtained from mass spectrometer recordings as a means of identification and determination of reservoir continuity. Conventional methods for detecting composition differences are expensive, elaborate, and difficult to obtain. This excludes the use of extensive composition data for most applications. During recent years the mass spectrometer has come into general use as an analytical tool in petroleum refineries. The use of mass spectrometer composition patterns in characterizing or "finger-printing" the produced gas from a reservoir, presents a novel method for correlating gas samples from well to well. The mass spectrometer provides a trace similar to an electric log, having peaks which represent the abundance of certain hydrocarbons in the well gas sample. Without going further into the detailed analysis, the idea has been advanced that these traces or patterns could be used as a means of identifying a particular natural gas. This theory has proven to be essentially correct. The mass spectrometer pattern method is simple and cheap as compared to other standard methods. It greatly facilitates the solution of reservoir and geological problems in which correlation of well gas compositions is a factor. Specific field applications have been made. This paper concerns the results obtained in 465 individual gas analyses from 35 fields and 77 reservoirs. In a number of cases it has been found that such data have been extremely valuable in the determination of reservoir continuity. In at least one case, the method was a valuable contribution in tracing a reservoir from sand to sand in a complex faulted field involving numerous gas reservoirs. Field applications are presented to illustrate the possibilities of the method at the present stage of development and to stimulate the employment of this new approach by geologists and petroleum engineers in the industry.

Some Data Processing and Engineering Calculations With Slow to Medium Speed Computers

Abstract The paper describes methods of solving several reservoir engineering and data processing problems using slow to medium speed computing machines. The problems handled are:Solution of the Hurst-van Everdingen material balance equation for which at first only water influx terms and y curves for PVT samples were calculated with the IBM 602A and 604 computers, while later the complete solution of the equation was programmed on the IBM 607 computer. The application of this equation requires computing cumulative water influx volumes at successive dates and matching these figures with the difference between the corresponding cumulative reservoir volumes withdrawn, and the corresponding cumulative expansions of the initial volume of reservoir oil and gas.Vapor-liquid equilibrium flash calculations which are solved rapidly with the IBM 602A or 604. Auxiliary calculations were made to convert the results into usable engineering quantities.Statistical analyses, performed on core data for several fields, providing a better understanding of the reservoir characteristics.Preparation of the annual (statistical) reserve report. This report starts with the previous year's figures for the gross and net reserves, cumulative and ultimate production, separated into oil, condensate and total liquid figures by leases. Revisions to reserves, classified according to 10 categories such as discoveries, new zones, extensions, etc. are added to the opening reserves and ultimate production figures, while the yearly production figures are subtracted from the revised figures and added to the cumulative figure. Statistical data concerning leasehold titles and ownership fractions, well counts, etc. are recorded. All figures are summarized according to zones, fields, leases, divisions and areas.Miscellaneous uses of analytical procedures for production accounting figures, such as oil pipe line runs, etc. provided better control of production operations. Introduction The annual reserve report is a statistical statement of gross and net reserves, including revisions of reserve estimates and production during the year. The responsibility for preparing this report was assigned to reservoir engineers and by 1952 the report required considerable engineering, clerical and stenographic time.

Application of Laboratory PVT Data to Reservoir Engineering Problems

Abstract The paper summarizes the historical background of thepressure-volume-temperature analyses of reservoir fluids, the errors involvedin both the sampling and testing of reservoir fluids, the type of informationrequired of a PVT determination, and the field conditions that limit theapplication of anyone analysis. Particular emphasis is placed on the necessityfor approximating as closely as possible the liberation sequence occurring inthe producing formation, flow string, and surface separators. A combineddifferential and flash or "composite" liberation is suggested as thebest means of approximating this liberation sequence. Historical Background Petroleum reservoir engineering commonly is considered to be one of thenewest fields of petroleum science, yet much work of a theoretical andintuitive nature was done many years before the modern techniques of reservoiranalyses were developed. The period 1910–1924 saw considerable work in the field of reservoirbehavior done by the U. S. Bureau of Mines. This work, although entirelytheoretical, pointed out the importance of gas in the recovery of oil from thereservoir. The statement by J. O. Lewis that 20 per cent or less of theoil originally in place in a pool was recovered from the ground under uncurtailedproduction conditions caused some operators to re-examine and modify theirproduction methods. However, though these works showed methods of productionthat have subsequently resulted in greater oil recoveries, they in general wentunnoticed, even though there was a fear that the nation's petroleum resourceswere being exhausted. The period 1924–1933 saw the industry take considerably more interest inreservoir behavior because of an unfounded fear of its inability to replace oilreserves, the possibility of government regulation, and the energy of one man, Henry L. Doherty. Doherty aroused heated discussions in the industry concerningconservation. To prove or disprove his theories the first experimental work onthe reservoir behavior of petroleum was undertaken. The papers of Dow andCalkin, Beecher and Parkhurst, and Mills and Heithecker are classics althoughtheir experimental procedures were crude. These papers proved that theproperties of petroleum in the reservoir are quite dissimilar to the propertiesmeasured at the well head. Gas dissolved in the oil phase was recognized ashaving considerable importance as had been predicted by the earliertheorists. T.P. 3710

Pressure Gradient of Fluids in an Oil Reservoir

Because flow of fluids in an oil reservoir tapped by a well is not subject to the Darcy's law, it produces one of the most complex problems in oil reservoir engineering. In this paper, a method of calculation to obtain pressure gradient in an oil reservoir is described. The results calculated are shown in the figures, and they indicate how radically different the flow of gas-dissolved oil is from that of homogeneous fluid.