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Collaborating Authors
Fall Meeting of the Society of Petroleum Engineers of AIME
Abstract Expense of bactericide treatment in injection water can be a major item in the operation of a waterflood or disposal system. Each operator of such a system desires to know whether such expense is necessary and which bactericidal chemical is most economical for his system. The diagnosis to be described makes use of modifications in recognized analytical methods for on-the-spot determinations of total sulfide and of populations of "sulfate-reducing bacteria". Activity of the bacteria is judged on the basis of increases in sulfide concentrations and/or in increases in bacterial populations as the water progresses through the system under study. The methods used in this diagnosis are of sufficient sensitivity that indications of bacterial activity should be apparent if down-hold bacterial sulfide formation is a significant factor in any water injection system. If the diagnosis fails to show a definite bacterial problem, more careful study of other factors is indicated. Descriptions will be made to cover typical evidence for:Uncomplicated appearance of bacterial sulfide in injection water accompanied by increasing numbers of sulfate-reducing bacteria or accompanied by high bacterial populations. Localized pockets of bacterial sulfide formation. Water passing such pockets would pick up sulfide and bacteria either continuously or in "slugs". Cases where one or more supply waters contain dissolved sulfide with or without significant numbers of sulfate-reducing bacteria. Little or no additional sulfide is formed by the bacteria but the soluble sulfide reacts with iron salts, metallic iron etc., to produce "black water". Treatment with chemicals having properties other than or in addition to bactericidal activity is required. Complications associated with imperfect mixing of widely differing supply waters. Concentrations of sulfide and bacteria passing sample points fluctuate, hence diagnosis is possible only by alterations in the operation of the system.
- North America > United States (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract In 1949, William E. Stiles presented an article entitled, "Use of Permeability Distribution in Water Flood Calculations" in which he outlined a method for prediction of water flood performance. In the method Stiles derived equations which were based upon the assumption that the direction of fluid flow from an injection well was in a linear direction. These equations were mathematically derived by a statistical presentation of permeability data. This paper introduces to the method the fact that initially the direction of fluid flow from an injection well is radial and then continues to treat the direction of flow in three distinct periods. The first is radial flow; the second is a period of transistion from radial to linear flow; and the third is after reservoir fill-up when it is assumed that linear flow conditions do predominate. Equations are then derived for the radial flow period which express water cut and the commensurate fraction of water flood oil recovered in terms of dimensionless permeability. Additional modifications are also suggested in application to field performance.
Abstract Discovered in 1937 and now one of the nation's larger waterflood developments, the Loudon pool, Ill., has a history of practical application of advanced conservation techniques. Careful spacing analysis, multiple horizon completions and gas partial pressure maintenance were all part of primary depletion history. Primary recovery of 180,000,000 bbl from 24,500 productive acres of Chester sands will be greatly enhanced by the current waterflood operation. Waterflood exploitation was begun in 1950. After flood ability was demonstrated, an expansion program was begun and by June 1, 1957, the flood covered an area of 13,700 acres. Current planning indicates the flood area will total 19,000 acres when fully developed. Water flooding has increased total pool production 21,000 B/D during the past four-year period. Because of the flood program size, unique problems have been encountered in maintaining an adequate supply of water for injection. Waterflood behavior of the reservoirs has been carefully analyzed as a guide to optimum ultimate results. Introduction The Loudon pool is located in south-central Illinois on the northwest flank of the Illinois basin. Its location in relation to other producing pools in the basin is shown in Fig. 1. Since discovery of the field in 1937, development and production operations at Loudon have been characterized by use of the best conservation practices which were applicable. The latest and most significant of these techniques is the water flood program which by June 1, 1957, covered 13,700 acres, involving the properties of 40 operators. The water flood is expected to increase pool ultimate recovery by 140,000,000 bbl. Development and Production History The producing horizons under flood at Loudon are four Mississippian Chester sand reservoirs, the Weiler, Paint Creek, Bethel and Aux Vases, encountered at subsurface depths ranging from 1,400 to 1,600 ft. Productive areas of these four reservoirs are outlined in Fig. 2. The Weiler, Paint Creek, and Bethel sands contribute the principal oil reserves.
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Kansas > Chester Formation (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin > Tar Springs Formation (0.99)
Abstract The use of empirical data to validate injection predictions and to prepare oil production forecasts is described. Histories of typical inputs show that reasonably reliable injection predictions can be made from equations based on Darcy's Law. The production performance of five Illinois floods is presented in a graph of accumulated increased recovery versus accumulated water injection per acre-ft, thereby permitting comparisons and forecast independently of time and input rate. The various steps used to apply this empirical data to a forecast are described, beginning with the method of estimating the accumulated injection necessary to achieve first production increase. Flood performance indicates this to be a function of permeability heterogeneity. The forecast of subsequent behavior is shown to consist of selecting the most appropriate empirical curve to use as a guide, with its selection based on relative reserves and degree of confinement. The introduction of time and rate is described as a stepwise integration of the accumulated production versus injection curve at the forecast injection rate.
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
Abstract Predictions of reservoir performance are usually based on laboratory measurements of core properties. Laboratory measurements, for example of oil recovery by waterflooding, are in turn related to the wettability of the rock surface. This has been shown by recent papers in the petroleum literature on the subject of wettability. Data have already been presented by this laboratory which show that wettability determines the shape of the water-oil relative permeability curves for a given porous medium. Thus, ideally, laboratory measurements should be made on cores which have the same wettability as the reservoir rock. This paper presents results of laboratory relative permeability measurements on oil field cores. Measurements were made in the water-oil system using the dynamic or "Penn State" relative permeability method. Saturations were obtained by using a radioactive oil soluble compound. Data were obtained on cores as taken from the field in an unextracted condition. Measurements were then made on the same cores after toluene extraction. A comparison of the relative permeability vs saturation curves obtained from the core samples before and after extraction showed a measurable change in the curves, but the changes were small and not due to significant changes in wettability. It can be concluded that the laboratory procedure of core cleaning with toluene extraction and subsequent handling during core analysis does not significantly change the relative permeability characteristics from those of the core material at the start of the core analysis operation. This conclusion is based on data from cores that were preferentially water-wet, cores that were preferentially oil-wet, and cores that were of intermediate wettability. Introduction Reservoir rocks are porous media with high specific surface area and exceedingly fine pore structure. It is not difficult to understand why a knowledge of the surface properties of reservoir rocks is fundamental to an understanding of how fluids flow in such porous media. The molecular processes that occur on the surface of the reservoir minerals and at the fluid interfaces have been shown to be a dominating factor when considering the recovery of oil from porous media. Intensive research is being conducted by most oil field research laboratories in an to evaluate qualitatively and quantitatively the role of wettability. The activity in this field can be verified by noting the number of recent publications and patents dealing with the subject of "wettability". Prior to these recent articles, only a meager amount of wettability data was available in the petroleum literature. These articles show that wettability can materially affect predictions concerning the volume of oil-in-place, and controls to a great degree the relative success of completion methods and several recovery processes.
- Geology > Mineral (0.49)
- Geology > Rock Type > Sedimentary Rock (0.31)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
Abstract A centrifugal reservoir model has been constructed for studying solution gas-drive phenomena. The model has been used to study the effect of oil properties, well location and producing rate on the recovery of oil from a solution-gas-drive reservoir. Gravity segregation effects were minimized by the slow rotation of the model about a horizontal axis. The studies were conducted on a synthetic porous media having a permeability of less than 10 md; the bubble point of the crude oil ranged from a few hundred to over 2,000 psi; connate water was present. It was found that the crude oil properties had a very large effect on the total oil recovery. The effect of well spacing and rate of production is presented. It was found that for the conditions of the test the well spacing and production rate may have an effect on the oil recovery depending on the reservoir system and producing technique. Introduction In 1952 the Texas Petroleum Research Committee initiated a research project to study criteria for determining the most efficient rate of producing an oil reservoir. A large number of articles bearing directly on this subject have appeared in the literature. Three recent reports on this subject have included literature reviews so a review is not repeated here. Field data have been used, model studies made, and certain mathematical techniques have been used to estimate the effect of reservoir rock and fluid properties, rate of production and well spacing on solution gas-drive performance. Following the review of the literature it was decided that a laboratory model would be built in which one could simulate a solution gas-drive reservoir so that one could determine experimentally the effect of production rate, well spacing, and fluid and reservoir properties on oil recoveries. Small parts of reservoirs have been built in various shapes and sizes to represent reservoir conditions; however, gravitational effects in the actual reservoir and the part of a reservoir used in the laboratory may not be the same. The overall effects of gravity in either an actual reservoir or a part of a reservoir used in the laboratory are not well defined.
Abstract Equations for the motion of miscible fluids are considered which are based on a single hypothesis, namely, the fractional flow of the invading fluid depends in a known way on its saturation and saturation gradient. They are similar in form to the equations of the Buckley-Leverett theory. The differential equation satisfied by the fractional flow, considered as a function of the saturation and the time, is derived. A similar equation may also be obtained in the Buckley-Leverett theory for immiscible displacements. This equation, because of its simple form, is susceptible to well-known numerical methods and makes the computation of the history of a displacement a reasonable project. A comparison of the implications of the equations with some of the published data is made. While it seems possible to reconcile some of the apparently incompatible interpretations which have been given on the ground that the techniques employed affect the nature of the motions, several differences still remain. For a horizontal drive, in which gravity segregation enters, it is shown that a motion may exist in which the planes on which the saturation of the invading fluid is constant are inclined at a constant angle with the direction of motion. Introduction Many investigations have been made into the behavior of a fluid while being displaced from a porous medium by a miscible fluid. On only one occasion, however, have equations been suggested as descriptive of the motion. For this reason an account is given here of the consequences which follow from some simple hypotheses about the movement of miscible fluids. The equations are similar in form to those of the Buckley-Leverett theory for immiscible displacements and differ from them only in detail. Consequently, the method outlined here for discussing them is equally applicable to the Buckley-Leverett theory and provides a simple way of explaining and computing the formation or nonformation of a stabilized zone in that theory due to the interaction of gravity and capillary forces. The interpretation ascribed to the many experiments on miscible flooding does not, at first sight, present a consistent picture. The dependence of the length of the mixing zone on rate, viscosity and pore structure is explained in a different way by the various authors.
Abstract A set of composite equilibrium vaporization ratios is presented that may be used to predict the quantity and composition of all components in separation calculations with a degree of accuracy that is satisfactory for normal field separation processes. The values presented have been obtained from a statistical analysis of seven most commonly used sets of equilibrium values and combined into one set which has more general application than any one of the individual sets from which the values were derived. These charts, therefore, offer a convenient and consistent set of values for use throughout the normal range of separation for the components of methane through heptanes-plus. Introduction When equilibrium vaporization ratios, or K-values, are used for calculations, the results are dependent upon the values selected. An arbitrary application of one particular set of K-values to all separation problems will produce correct results for some fluids and incorrect results for other fluids. In general, a non-selective application of one set of values will give erroneous results. An examination of existing equilibrium data indicates that the engineer has a wide choice in the selection of K-values that he can apply to separation calculations. He frequently has to use several sets of correlations for different ranges of temperatures and pressures and/or various correction factors to correct for certain discrepancies. These discrepancies have often been a source of difficulty in routine field separation problems, company negotiations, and in the prediction of yields for proposed unitizations. Therefore, a need exists for a single set of K-values that would be sufficiently accurate for all normal separation problems. The purpose of this investigation, therefore, has been to examine existing equilibria data statistically and prepare a series of charts that may be used to solve routine oil and gas separation problems.
Abstract The formation water resistivity is presently calculated from electric log data with the assumption that both the waters in the drilling mud and the formation are essentially sodium chloride solutions. This is found to be in error with most of the drilling muds in use today. This paper treats the effect of mud chemicals on formation water resistivity when SP data is used for the water resistivity calculation. The Nernst equation for activities of ionic solutions, that are essentially univalent, is used to evaluate the spontaneous potential. This equation is: (Equation) Eq. 1 has both a shale membrane and a liquid junction component. Only the shale membrane component was investigated in this study, since it is usually the most significant parameter. It may be expressed as: (Equation) Since the activity of the mud filtrates must be known for given resistivities, both of these parameters were measured in this investigation. The results showed that several properties which are being measured at the well head can be used to find the activity of a mud filtrate if the resistivity is known. The activity of mud filtrates rarely varies with the sodium chloride in solution alone. Important properties causing activity changes are filtrate alkalinity and calcium content. Graphical representations are prepared showing the correlation with each of these parameters. Introduction C. and M. Schlumberger and E. G. Leonardon in 1934 considered the self potential curve of electrical logging to be composed of the combination of a streaming potential and a boundary potential. They believed that the boundary potential was set up at the face of impermeable material, such as clay or shale, due to the interaction of fluids containing different salt concentrations. The electro-chemical component of the self potential curve was given as (Equation) where K is an unknown constant, Rm is the mud resistivity, and Rw is the connate water resistivity.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
- Geology > Mineral > Halide > Halite (0.45)
- North America > United States > Texas (0.89)
- North America > United States > Louisiana (0.89)
Abstract This paper deals with the time-varying solutions of free-surface problems in porous media as an extension of the steady-state theory developed by M. King Hubbert. Examination of the equations shows that a marked similarity exists between these and those of the linear exact wave theory for the propagation of a disturbance at the interface of two superposed fluids. This purely formal analogy is extended so that solutions in hydrodynamic theory may be transformed quite simply to give solutions to similar problems in porous media. The auxiliary problem in water wave theory, namely the shallow water problem, is next considered. The resulting equation is found to exhibit a similar analogy to the Boussinesq equation or the Dupuit-Forchheimer theory of ground-water flow. On the basis of these analogies and the relationship between the theories of deep and shallow water waves, an analysis is made of the errors involved in the Dupuit approximation. A discussion on the application of the Dupuit approximation to model experiments indicates the importance of the size of the model on the interpretation of results. A method is suggested for analysing gravity flow problems by means of a combination of the Dupuit theory and the more exact theory. Introduction This paper is concerned with the study of the motion of an interface separating immiscible liquids of different density and viscosity in a porous medium. It is assumed that the flow of the fluids in question is governed by Darcy's law and that the presence of an interface is due to complete segregation under the action of gravitational forces. Hence in a multi-fluid system, whenever gravitational effects are of importance, interface or free-surface problems naturally present themselves. Strictly speaking, the term "free-surface" is usually applied to the hypothetical surface of demarcation between air and water in ground water studies. However, it is a convenient description and is applied quite generally to surfaces of separation as defined above, thus avoiding any confusion with the interfacial phenomena studied in capillarity theory.