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By A. G. Spillette, R. L. Nielsen

The purpose of this paper is to further the understanding of reservoir response to hot-water injection by desuribing a two-dimensional, mathematical model of the process. Key assumptions are that no gas phase is present, and that the injected fluid reaches thermal equilibrium instantaneously with the reservoir fluids and sand. The resulting system of three partial differential equations is solved simultaneously through the use of a "leap-frog" application of standard alternating direction implicit methods for the solution of the mass-balance equations and the method of characteristics for solution of the energy-balance equation. The utility of the mathematical model is demonstrated by comparing numerical and analytic temperature distributions for hot-water bank injection and by comparing calculated with observed field behavior. Additional calculations show that hot waterfioding can recover significantly more oil than cold waterflooding, and that a hot-water bank recovers, with less energy input, nearly as much oil us continuous injection. Introduction Consistent field success with hot fluid injection processes requires good reservoir description and a thorough understanding of recovery mechanisms. The latter is fostered by a combination of well designed experimental studies and physically sound mathematical modeling. The purpose of this paper is to further the understanding of reservoir response to hot-water injection by describing a two-dimensional mathematical technique, indicating its validity, and demonstrating its utility for studying the effects of reservoir and operating parameters. Published experimental studies of hot fluid injection processes are few." Even if extensive data were available, two considerations discourage exclusive reliance on laboratory or field work. First, because of the severity of scaling requirements," laboratory results must be interpreted with care. Second, because of the one-shot nature of field experiments — injectivity/productivity tests and pilot floods—results seldom are available over the desired range of operating conditions. These factors emphasize the need for devoting attention to mathematical modeling to complement laboratory and field work. Through the use of mathematical models, scaling uncertainties can be bridged and response can be predicted for unique combinations of reservoir and operating conditions. Numerous mathematical models developed during recent years enable us to calculate temperature distributions, thermal efficiency (or conversely, fraction of heat lost), and oil recovery behavior for hot fluid injection. Ramey" and Spillette' recently have provided reviews of these methods. Most models have concentrated on predicting temperature distributions and thermal efficiency; few have been directed at predicting oil recovery.'."1° Although these techniques are useful for estimating effects of reservoir parameters and operating conditions on process performance, results are limited by the assumptions made and by the methods of coupling independently solved fluid-flow and energy-balance equations. A computer-based method is presented for predicting total reservoir response to hot-water injection that obviates most simplifying assumptions. The model simulates fluid flow and heat transfer in two dimensions within a vertical cross-section spanning the oil sand and adjacent unproductive strata. Known numerical procedures are used to solve the governing partial differential equations. The mathematical model handles the effects of reservoir heterogeneity, gravity, capillarity, relative permeability and temperature-dependent fluid properties. In addition, a wide range of operating conditions can be modeled, including hot-water followed by cold-water injection. Mathematical Description of Hot-Water Injection Key assumptions in the mathematical model for hot-water injection are that (1) no gas phase is present and (2) the injected fluid reaches thermal equilibrium instantaneously with the reservoir fluids and sand. Relative permeability and capillary pressure are assumed independent of temperature. Darcy's law for multiphase fluid flow relates the velocities of the oil and water phases to the phase pressure gradients by the following relations:

Jan 1, 1969

By H. J. Morel-Seytoux

The influence of patten, geometry on assisted oil recovery for a particular dispIacement mechanism is the object of investigation in this paper. The displacement is assumed to be of unit mobility ratio and piston-like. Fluids are assumed incompressible and gravity and capillary effects are neglected. With these assumptions it is possible to calculate by analytical methods the quantities of interest to the reservoir engineer for a great variety of patterns. Specifically, this paper presents (1) very brieily, the methods and mathematical derivations required to obtain the results of engineering concern, and (2) typical results in the dorm of graphs or formulae that can be used readily without prior study of the methods. Results of this work provide checks for solutions obtained from programmed numerical techniques. They also reveal the effect of pattern geometry and, even though the assumptions of piston- like displacement and of unit mobility ratio are restrictive, they can nevertheless be used for rather crude but quick, cheap estimates. ,These estimates can be refined to account for non-unit mobility ratio and two-phase flow by correlating analytical results in the case M = 1 and the numerical results for non-piston, non-unit mobility ratio displacements. In an earlier paper1 it was also shown that from the knowledge of closed form solutions for unit mobility ratio, quantities called "scale factors" could be readily calculated, increasing considerably the flexibility of the numerical techniques. Many new closed farm solutions are given in this paper. INTRODUCTION BACKGROUND Pattern geometry is a major factor in making water-fIood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected.

Jan 1, 1967

By R. W. Parsons

wben a displacement front encounters an isolated permeability heterogeneity, it will be perturbed. The details of this perturbation will depend on the beterogeneity size and shape, the Permeability contrast, and the mobility ratio. This paper deals with the displacement front behavior for one, simple, mathematically tractable model: a circular permeability discontinuity and unit mobility ratio. The progress of an initially planar front is shown for four permeability contrasts: k2/k1 = 0, 5/2, 2, m. The front distortion is more pronounced than streamline and isopotential distortion and it approaches a constant shape downstream from the discontinuity. INTRODUCTION The impact of reservoir heterogeneities on oil displacing processes depends upon the variation of the heterogeneous property (frequency distribution), its disposition (spatial distribution), and the inherent stability of the displacement mechanism.l The interplay of these factors plus the impracticability, if not impossibility, of describing a natural rock system in any detail makes exact displacement front movements difficult to determine. It is useful, however, to be able to qualitatively visualize what heterogeneities will do to a displacement front. In this respect certain simple models that can be treated analytically are of value. The following analysis will show the displacement front behavior for one such model. MODEL DESCRIPTION The flow field is two-dimensional and infinite in extent. The fluid flow is single phase, steady state and unidirectional at x, y = 2 m, or before insertion of the discontinuity. A circular permea- bility discontinuity is placed at the origin. Porosity and thickness are the same within and exterior to the heterogeneity. This is exactly the same model that was used by Greenkorn et al. to check analytically Streamlines as determined by Heie-Shaw flow models and finite difference computer techniques.2 FRONT POSITION CALCULATIONS The results of displacement front calculations are presented in Figs. 1 through 4 for four different permeability contrasts: k2/kl = O, %, 2, m. The times corresponding to the front locations are the Same for the 0 and cases! and for the 1/2 and 2 cases. The determination of front positions at various times is based on known analytical expressions for velocity potentials ().2 and stream functions ().2 These expressions are in terms of the x and y

Jan 1, 1969

By G. M. Gay, R. L. Perrine

This paper describes a method of numerical computation for three-dimensional, unstable, miscible displacement behavior useful for heterogeneous systems, as well as for more ideal conditions. In the method, flow equations are first linearized by a perturbation approach. The basic flow process is separated and a solution for its behavior readily obtained. The remaining problem of deviations from the basic flow caused by non-ideal conditions is then subjected to numerical analysis. Results obtained from use of the method are also presented. Although conditions assumed in the test cal-culations were severe, results show the type of dispersing flow expected and appear quite satisfactory. The method has eliminated or reduced in importance problems of oscillating values near steep fronts, excessive computer smoothing, etc. A unique advantage of the method is that the source of variations from ideal behavior can be observed. ,The one serious drawback results from the algebraic complexity of the perturbation approach, and the need for second-order terms to be retained in calculations of interest. Fewer array points are available and more computer time is required than would be desired. However, these difficulties are also experienced with other approaches to the solution of three-dimensional dispIacement problems. INTRODUCTION Prediction of behavior of the miscible displacement process within a porous medium for any system of engineering importance is plagued by a number of difficulties. With typical fluid properties the displacing fluid has the lower viscosity, and there is a natural tendency toward flow instability. The problem of predicting instability is compounded by the fact that every real system is heterogeneous. Permeability will vary from point to point — not entirely systematically, and yet not in a random fashion leading to a readily defined average. Furthermore, permeability is unlikely to be isotropic. These permeability properties, which are characteristic of any real porous medium, accentuate the effects of flow instability. Another factor to be considered is that flow dispersion accompanies the displacement process in a porous medium. Mechanistically, dispersion is due to the fact that flow between any two points in the medium follows multiple tortuous paths, each characterized by slightly different flow properties. The fact that the coefficient characterizing dispersive properties of the real medium JS a tensor with variable elements complicates matters. Further difficulties arise because the parabolic influence, while not negligible, is small. Thus, there is a tendency toward steep and uneven displacement fronts along which dispersion smoothing must be represented accurately. Yet frequently used numerical analysis schemes may tend toward either instability, oscillation or excessive smoothing, none of which gives the desired accurate picture of flow behavior. Thus, while many experimental and analytical studies of the process have been made, predictions of actual performance are still subject to considerable uncertainty and possible improvement. This paper reports on part of a study which attempts to develop improved methods for solution of the flow equations describing the miscible displacement process. Of necessity, the calculations were performed on a large digital computer. A three-dimensional system is represented, and the coefficients defining dispersion and permeability can be varied in a manner representative of a real system. Because the differential equations are nonlinear, a first step is to linearize them using a perturbation approach. Objective of this approach has been to separate the basic flow which would occur in an ideal system and for which predictions are readily made. Then the numerical analysis, which is necessarily complex, is directed toward solution of the perturbation equations. These equations state how the basic flow is modified

Jan 1, 1967

By A. T. Chatas

A description of the geometrical characteristics of spherical reservoir systems, a discussion of unsteady-state flow of such systems and examples of engineering applications are presented as backgmund material. The fundamental differential equation, a description of average spherical permeability and the introduction of the Laplace transformation serve as theoretical foundations. Engineering concepts are investigated to indicate particular solutions of interest, which are analytically obtained with the aid of the Laplace transform. These are numerically evaluated by computer, and presented in tabular form. INTRODUCTION A tractable mathematical analysis of unsteady fluid flow through porous media generally requires incorporation of a geometrical symmetry. The simplest forms include the linear, cylindrical (radial) and spherical. Most analytical endeavors have concentrated on cylindrical symmetry because it occurs more often in petroleum reservoirs. Nevertheless, some reservoir systems do exist that are better approximated by spherical geometry. Review of technical literature revealed but a single reference to unsteady spherical flow in petroleum reservoirs.l The motive and purpose of the present work was to remove this gap in technical information, and to provide the practicing engineer with some useful analytical tools. The mathematical details associated with the particular solutions of interest involved use of the Laplace transformation. Hurst and van Everdingen previously demonstrated the efficacy of this operational technique, and in many respects the present treatment was patterned after their earlier work.2 PRELIMINARY CONSIDERATIONS GEOMETRICAL CHARACTERISTICS Geometrically, a spherical reservoir system is defined at any instant of time by two concentric hemispheres whose physical properties of interest vary only with the radial distance. Every physical property is thus restricted to be a space function of only one variable: the distance along a radius vector emanating from the center. Such a system is composed of an outer region and an inner region, separated by a defined internal boundary. The inner region simply extends inward from this boundary, whereas the outer region extends outward from it to an external boundary. The position of the internal boundary is presumed fixed, so that the size of the inner region remains constant. On the other hand, the position of the external boundary at any given instant of time is determined by the distance into the system that a sensible pressure reaction has occurred, Thus, the external boundary may change position with time. It initially emerges from the inner region and advances outward to its ultimate position. When this ultimate position coincides with a geometric limit, the reservoir system is said to be limited. When it coincides with points subject to pressure gradients furthest removed from the internal boundary, yet short of a geometric limit, the system is said to be unlimited. In this investigation two different boundary conditions are imposed at the ultimate boundaries of limited systems. The first requires that no fluid flow occur across this boundary; the second that the pressure remain fixed at this boundary.3-5 UNSTEADY-STATE FLOW In a strict sense virtually all flow phenomena associated with a reservoir system are unsteady-state. The transient behavior of these phenomena requires accounting, however, only when time must be introduced as an explicit variable. Otherwise, steady-state mechanics may be used. Analytically, steady-state conditions prevail in a reservoir system only over that portion of its history when this relation is satisfied:

Jan 1, 1967

By F. W. Jessen, N. Mungan

The plastic flow characteristics of clay water suspensions were first recognized by Binghaml in 1916 and further studied by Ambrose and Loomis' in 1931-1932. Many physical and chemical properties of clay suspensions are deeply influenced by particle size distribution as well as by the exchange cation. Separation of a number of fractions is particularly helpful in making a detailed study of a suspension. A limited amount of work has been conducted on the effects of particle size on specific properties of mud drilling fluids. A knowledge of particle size distribution is essential for a better understanding of fundamental properties of clay suspensions, particularly viscosity and gel strength. The purpose of this investigation was to study the effect of particle size on the viscosity and gel properties of clay suspensions and to determine any changes in mineral composition accompanying variation in size. EXPERIMENTAL PROCEDURE Numerous methods may be used to fractionate a poly-dispersed clay suspension into nearly mono-dispersed systems. Particles larger than 44 micron (325-mesh) may be obtained by wet screening. For sizes from 44 to 1 micron, the fractionation may be accomplished by sedimentation, elutriation plus microscopy,' or turbidimetry.6 When dealing with systems which contain a major portion of particles below l-mi-cron size, slit ultramicroscopy,7 centrifuge methods of Svedberg,5 eams,9 and McBain,l0 and X-ray methods" may be employed. The Sharples super centrifuge has been proved suitable for the economical separation of suspended particles of submicron range.12,13,14 Three-hundred and forty-five gal of 1 per cent by weight Aquagel suspension was mixed in a high-speed 5-gallon mud mixer and the suspension was allowed to stand in 5-gal glass bottles for 30 days to assure full hydration. All particles larger than 44 microns were removed by wet screening. Five fractions in the range of 44 to 1 micron were obtained by sedimentation. The Sharples super centrifuge method described by Hauser and Reed.13 Norton and Speil,14 Ha user and Lynn,15 and Hauser and Schachman,10 as employed to yield five fractions of submicron size. A super centrifuge operation chart prepared by Fancher, Oliphant, and Houssierre12 was used to determine operating conditions for the desired particle ranges. The clay suspension, after removal of all material above 1-micron size, was centrifuged. During rotation of the bowl, the particles were deposited on a thin plastic liner which fit closely inside the bowl. After passing 5 gal of suspension through the centrifuge, the liner was removed and the particles on the liner were scraped off, remixed and recentrifuged. This was repeated five times. Thus, Fractions H, I, K, and L were obtained. The finest fraction, M, remained in an approximately 0.4 per cent suspension. Water was evaporated under reduced pressure from this suspension to yield the finest particles. Results of the fractionation are included in Table 1. In order to achieve proper orientation and humidity conditions for X-ray diffraction analysis, the following procedure was employed. The dilute suspensions were placed on glass slides and allowed to dry at room temperature. This was repeated several times. Previous to measurement each sample first was placed in a water desiccator for half an hour and then allowed to stand for 15 minutes at room temperature. thus yielding an equilibrium condition of about 52 per cent relative humidity. The relative humidity of the room in which the X-ray diffraction was carried out was maintained at approximately 50 per cent so that there was no change in the spacings during the X-ray examination. Samples

By A. G. Weber, H. J. Welge

A published calculation method for predicting incompressible, multidimensional fluid displacement has been adapted to the problems of water and gas coning in oil wells. Since depth and radial distance from the wellbore are the two key dimensions affecting the shape of a gas or water cone, coning calculations are well suited to the use of two-dimensional methods. The alternating direction implicit procedure (ADIP) was used for relaxation calculations of two-phase potentials in a two-dimensional grid. From the potentials and the capillary pressure relationship, saturation and pressure distributions were calculated which trace cone growth with time. Predictions have been made for well producing histories both before and after core breakthrough. To check validity of the method, two-dimensional calculations have matched the coning behavior and produced water-oil ratio history of a laboratory sand-packed model. They have also matched the coning behavior of several producing wells, for which the calculations were compared with produced water or gas cuts and logs showing water or gas cone movements. INTRODUCTION The application of two-phase, two-dimensional calculations using ADIP to various reservoir flow problems has been described in the literature.1-3 When adapted for computer solution, this method has proved to be a powerful tool for simulating well and reservoir behavior. This paper discusses the method as applied to well coning calculations. Single-well and coning calculations comprise an especially difficult class of two-dimensional problems which require special techniques for computer calculation and determination of reservoir characteristics. Refs. 4 through 8 describe previous approaches to the coning problem. Several examples of water and gas coning calculations, including studies on both laboratory models and producing wells, are presented here. The two-dimensional method accounts realistically for the most critical parameters affecting coning behavior, including production rate, formation stratification, horizontal and vertical permeabilities, depth of well penetration, gravity and capillary forces. The method considers the different densities and viscosities of the two phases and the relative permeability and capillary pressure characteristics of the rock and fluids. In addition to tracing cone growth in the vicinity of the wellbore, the method calculates the overall movement of the fluid interface throughout the well's drainage volume. Incompressible fluid flow is assumed to occur between the producing interval and the well's limit of drainage. Calculations can be made for the producing history both before and after cone breakthrough. A typical two-dimensional grid or array of blocks used to solve a coning problem contains about 400 blocks. The well's cylindrical drainage volume can be represented by about 20 radial subdivisions and the formation thickness by 20 vertical subdivisions. The grid spacing is normally smaller near the withdrawal interval to define the cone shape accurately. For this work we used an IBM 7074 digital computer having a core memory of 10,000 ten-digit words. A typical study, covering 5 to 10 years of well producing history, required from three to six hours of computing time. MATHEMATICAL SIMULATION OF CONING BEHAVIOR BASIC METHOD In coning calculations, the reservoir volume drained by the producing well is represented by a two-dimensional system of blocks as shown in Fig. 1 for water coning studies. The horizontal dimensions of the blocks increase with radial distance from the well axis in geometric progression, i.e., the block size is small near the wellbore and large near the well's drainage radius (re). Vertically, the blocks are bounded by horizontal planes located at different depths through the

Jan 1, 1965

By G. E. Warner

This paper presents a review and analysis of a highly stratified Burbank sand waterflooding project in Osage County, Okla. Permeability values in this reservoir range from less than 0.1 md to nearly 3 darcys, and 90 percent of the permeability capacity is contained in approximately 26 percent of the reservoir volume. To date, the project has recovered 103 bbl/flood-acre-ft since waterflood initiation, which represents 50 percent of the total preflood cumulative and 12 percent of the original stock-tank oil in place (OSTOIP). The outstanding feature of this project has been the economical recovery of a sizable quantity of oil at water-oil ratios higher than those normally considered prohibitive. Nearly 70 percent of the recovery to date has been achieved at water-cut values greater than 95 percent. An ultimate waterflood recovery of 138 bbl/flood-acre-ft, or 67 percent of the preflood recovery and 16 percent of the OSTOIP, is predicted. The ultimate primary and secondary recovery will be 302 bbl/acre-ft and approximutely 40 percent of the OSTOIP. The actual performance is compared with the predicted performance by both the Stiles and the Dykstra-Parsons methods, and applicabiliry of these methods to this particular reservoir is evaluated. The performance of this project indicafes highly stratified reservoirs can be successfully and economically waterflooded when either reservoir or economic conditions preclude the use of mechanical and chemical means of mdbility control. Introduction The concept of the stratified reservoir has been used by reservoir engineers for many years to describe the vertical variations in permeability within a reservoir. Numerous techniques have been advanced to predict the expected waterflood performance of the stratified reservoir, and in most cases they prove reasonably accurate. The advisability of undertaking a prospective waterflooding project is determined, based on these predictions. This paper presents a review of a waterflood project in a highly stratified reservoir that normally would be considered a marginal prospect, at best, when evaluated with any prediction technique properly adjusted for reservoir conditions. This kind of project can be successful if the predictions are used to design a waterflooding system capable of economically recovering an oil cut of 1 to 2 percent. Experience gained in the early stages of the project's development was profitably applied in the later development of the entire reservoir and could prove beneficial to other projects with similar reservoir stratification or fracture characteristics. The East Burbank pool waterflooding operations have been developed in three separate stages, each of which has been a separate project: Mid-Burbank Unit, Flood A, and Stanley Waterflood. When referred to collectively, these projects will be called the Composite Project. The Skelly Oil Co.'s Barber lease — the only portion of the pool not included in the three projects — is operated as a separate facility with a cooperative injection-well agreement. It contains less than 80 productive acres and would not significantly affect the over-all performance picture.

Jan 1, 1969

By C. Cronquist

Since April, 1962, Shell Oil Co. has operated a peripheral line-drive waterflood of the 10.750-ft lower Tuscaloosa (Cretaceous) Denkman sand in the Little Creek field. Located in southwestern Mississippi in the lower Tuscaloosa trend, the field was discovered by Shell in Jan., 1958. Among the largest in the trend, the accumulation is controlled stratigraphically and occurs in an extensive series of alluvial-point bar deposits across a nose that dips gently to the south. The crude oil is 39" API gravity and was highly undersaturated at initial conditions. Early production behavior indicated a depletion drive with slight water influx; primary recovery wm estimated to be 25 million bbl, or 24.5 percent of stock-tank oil originally in place. A.s a result of a favorable mobility ratio and remarkably uniform rock properties, the volumetric sweep eficiency in the waterflood has exceeded 90 percent. Despite the high connate water saturation (56 percent), the displacement efficiency by water injection has been quite efficient, contrary to traditional concepts. Based on observed field flood-out performance, ultimate recovery is calculated to be 46 million bbl. As anticipated, the production rate began declining during 1964 due to a continu ing reducrion in the number of producing wells as flood fronts advanced across the field. Cumulative recovery as of Jan., 1968, was 44.8 million bbl; waterflood operations ~hould be complete by 1970. Introduction Most waterfloods described in reservoir engineering literature involve pattern operations, the most common of which is the five-spot pattern. Only occasiona'lly are linear drives described, even though there probably are increasing numbers being put into operation. Increasing use of linear floods may reflect the accelerating trend towards early application of fluid-injection programs when linear drives are more efficient, as was the case at Little Creek. However. the Little Creek operation is unusual in several respects. It is one of a few successful waterfloods conducted in sands with connate water saturations approaching 60 percent, and it is among the deepest successful water-floods being operated anywhere. Development The Little Creek field was discovered in Jan., 1958, in the lower Tuscaloosa trend in southwestern Mississippi (Fig. 1). The discovery well, Shell-Lemann No. 1, was drilled on a seismic closure about 2 miles southeast of lower Tuscaloosa production at Sweetwater. The well was completed in the Denkman sand at 10,752 ft, and on initial potential it flowed 588 BOPD of 39" API crude on a %+-in. choke; psi was 730 and GOR was 442:l. Development proceeded rapidly on 40-acre spacing, and by the end of 1958 the field was producing approximately 9,100 B/D from 56 wells. Almost all this production came from the northern half of the field. The southern part was discovered in Nov., 1958, at a location almost 2 miles from previously established production. Subsequent drilling established an apparent conneotion about half a mile wide between the twd areas. Development of the field was practically complete by 1961 with the drilling of 155 producers and 35 dry holes. Some early wells were completed open hole but moslt are completed with casing cemented through the productive interval and perforated for production. Geology The lower Tuscaloosa structure in this area is a north-south nose with maximum dips of about 2" on the flanks. There is no discernible faulting at the producing horizon. Productive limits of the field are shown in Fig. 2, which is contoured on a marker just above the main productive zone. A common water level at 10,415 ft subsea was logged at both the northwest and southeast ends of the field. There is a gross oil column of nearly 100 ft (Fig. 2). Since there is less than 40 ft of closure, it is apparent that bhe accumubtion is controlled stratigraphically, being limited by a sand pinch-out across the creslt of the nose. The total produc-

Jan 1, 1969

By J. M. McDowell, E. C. Doty, F. Morgan

Improvements in the X-ray method of measuring liquid saturation and saturation distribution are presented. Two identical direct current amplifiers have been added to measure continuously the intensities of the X-ray tube output and the beam which has passed through the core under test. The ratio of these intensities is automatically recorded on a modified Brown Electronik Recorder. Arrangements have been made to drive the core automatically and in synchronism with the recorder chart so as to give a continuous curve showing the variation of liquid saturation along the length of the core. By determining the ratio of the two X-ray beam intensities simultaneously the measurements are made essentially independent of small fluctuation in voltage and current supplied to the tube. This improved technique has been used for investigating the fluid distribution along the length of cores and core assemblies when one fluid is displaced by another. Typical results of these studies are shown. INTRODUCTION In a previous publication' a method was described for measuring the oil saturation in cores which was based on the absorption of X-rays by the fluid content of the core. While that technique is capable of yielding accurate results, the original apparatus was not especially convenient for determining the fluid distribution along the length of a core. This was primarily due to the slow response of the amplifier and galvanometer and the necessity of making a point by point survey of the material under investigation. It was, therefore, not only possible for sections of the core having a variable or unusual saturation distribution to escape observation entirely, but changes in output of the X-ray generator between readings on the unknown and the monitor introduced errors in the measurements that could be avoided only by further stabilization of the source or by taking a large number of readings. This paper describes a method and apparatus for recording continuously and automatically the intensity of the X-ray beam that is transmitted by a core. The variation of saturation with time at a given section of the core may thus be found, or by scanning the core by driving it in synchronism with the recorder the saturation distribution may readily be determined. As indicated in the previous paper, the X-ray method possesses an advantage over the weighing technique in relative permeability experimentation in that the core need not be removed from the holder for the purpose of making a saturation measurement. Furthermore, the actual distribution of fluid and the effects upon that distribution of inflow and outflow heads may be investigated. And errors due to gas bubbles or loss of liquid that are frequently sources of error in volumetric methods of saturation determination are avoided. PRINCIPLE OF THE METHOD The energy in an X-ray beam that has passed through an absorbing material is expressed by the well known formula: E = E0, e-cd (1) where E, is the energy in the incident beam, µ the mass absorption coefficient, c the density or concentration of absorbing material, and d is the length of path of the beam in the absorber. The coefficient µ varies with the wavelength of the radiation as well as with the absorbing material. The output of an X-ray tube varies in an approximately linear manner with the tube current, but to the second or higher power of the anode voltage. Moreover, the quality or wavelength distribution of the radiation varies with the voltage.

Jan 1, 1950

By B. B. Wood, M. J. Rzasa, E. W. Hough

An apparatus for the determination of fluid-fluid interfacial tension by the pendant drop method has been constructed. The apparatus is refined beyond those previously described in that the samples are introduced into an evacuated windowed cell without contacting air or mercury. Interfacial tension data are reported for the water-methane system between 74 and 280°F and 15 and 15,000 psi. The variation of wettability of the stainless-steel dropper tip with pressure and temperature was observed incidentally to the measurements. INTRODUCTION The most refined previous apparatus --for the determination of fluid-fluid interfacial tension at reservoir conditions was built by Hauser and Michaels.' These authors used the pendant drop method, previously investigated by Andreas, Hauser, and Tucker.' Recently, Fordham3 has made the pendant drop method an absolute one by numerical integration of the differential equation of drop shape. It is necessary to know the difference in density of the two fluids and the acceleration due to gravity in order to evaluate the interfacial tension from measurements of drop dimensions. Contact angle is not involved in the measurements by this method. Some precise tests of the method have been made at atmospheric pressure and 77°F by Douglas," who found agreement with established values to within about 0.1 per cent for water and air, cyclohexane and air, benzene and air, and benzene and water. No values of interfacial tension from the recent pendant drop apparatusJ have been published by Hauser and Michaels. However, values for the water-benzene and water-decane systems are given in Michaels' thesis5 or Dressures from 15 .to 10,000 psi and temperatures from 73 to 268ºF. Some determinations on gas-oil and gas-water systems in the range of 15 to 4,000 psi and 78 to 178°F have been made by Hozott,' by the drop-volume method. The capillary rise method has been used to investigate the interfacial tension in gas-oil systems at 88°F to several thousand psi by Swartz.7 Other determinations in gas-oil systems at pressures under 1,000 psia have been made by Jones: and Beecher and Parkhurst.9 The scarcity of data for pressures above 5.000 psi is apparent. APPARATUS An assembly drawing of the working section of the interfacial tenqion apparatus is given in Fig. 2. 'The endanant drop (A) is housed in a pressure chamber having glass windows (B). An agitator (6) is provided. The metal parts of the apparatus coming into contact with the sample are made of AISI: Type 316 steel. Drain grooves are provided around the whdows so that the sample in contact with the O-rings is not returned to the working section when the pressure is reduced. A schematic arrangement of the apparatus is given in Fig. 3. The working section containing the pendant drop (A) is filled by samples from bombs (B) with the aid of the vacuum system (C). The O-ring sealed pistons (D) used to separate the sample from the hydraulic fluid are shown together with the pressure production and measurement system (E). A front view of the apparatus is shown in Fig. 1. Most of the hydraulic system is at the top of the panel. The pump and displacement piston are at the lower right. The Variacs for the air bath heaters. the camera. and the vacuum gauge are a1so visible on the panel. The working section together with a window closure and a drop-forming tip closure are shown in Fig. 9. The carbon arc light source with filter is visible in the upper part of the picture. Two sides of the air bath with the impeller and a part of the convection shield can also be seen. The assembled air bath is shown in Fig. 10.

Jan 1, 1951

By E. W. Hough, B. B. Wood, M. J. Rzasa

An apparatus for the determination of fluid-fluid interfacial tension by the pendant drop method has been constructed. The apparatus is refined beyond those previously described in that the samples are introduced into an evacuated windowed cell without contacting air or mercury. Interfacial tension data are reported for the water-methane system between 74 and 280°F and 15 and 15,000 psi. The variation of wettability of the stainless-steel dropper tip with pressure and temperature was observed incidentally to the measurements. INTRODUCTION The most refined previous apparatus --for the determination of fluid-fluid interfacial tension at reservoir conditions was built by Hauser and Michaels.' These authors used the pendant drop method, previously investigated by Andreas, Hauser, and Tucker.' Recently, Fordham3 has made the pendant drop method an absolute one by numerical integration of the differential equation of drop shape. It is necessary to know the difference in density of the two fluids and the acceleration due to gravity in order to evaluate the interfacial tension from measurements of drop dimensions. Contact angle is not involved in the measurements by this method. Some precise tests of the method have been made at atmospheric pressure and 77°F by Douglas," who found agreement with established values to within about 0.1 per cent for water and air, cyclohexane and air, benzene and air, and benzene and water. No values of interfacial tension from the recent pendant drop apparatusJ have been published by Hauser and Michaels. However, values for the water-benzene and water-decane systems are given in Michaels' thesis5 or Dressures from 15 .to 10,000 psi and temperatures from 73 to 268ºF. Some determinations on gas-oil and gas-water systems in the range of 15 to 4,000 psi and 78 to 178°F have been made by Hozott,' by the drop-volume method. The capillary rise method has been used to investigate the interfacial tension in gas-oil systems at 88°F to several thousand psi by Swartz.7 Other determinations in gas-oil systems at pressures under 1,000 psia have been made by Jones: and Beecher and Parkhurst.9 The scarcity of data for pressures above 5.000 psi is apparent. APPARATUS An assembly drawing of the working section of the interfacial tenqion apparatus is given in Fig. 2. 'The endanant drop (A) is housed in a pressure chamber having glass windows (B). An agitator (6) is provided. The metal parts of the apparatus coming into contact with the sample are made of AISI: Type 316 steel. Drain grooves are provided around the whdows so that the sample in contact with the O-rings is not returned to the working section when the pressure is reduced. A schematic arrangement of the apparatus is given in Fig. 3. The working section containing the pendant drop (A) is filled by samples from bombs (B) with the aid of the vacuum system (C). The O-ring sealed pistons (D) used to separate the sample from the hydraulic fluid are shown together with the pressure production and measurement system (E). A front view of the apparatus is shown in Fig. 1. Most of the hydraulic system is at the top of the panel. The pump and displacement piston are at the lower right. The Variacs for the air bath heaters. the camera. and the vacuum gauge are a1so visible on the panel. The working section together with a window closure and a drop-forming tip closure are shown in Fig. 9. The carbon arc light source with filter is visible in the upper part of the picture. Two sides of the air bath with the impeller and a part of the convection shield can also be seen. The assembled air bath is shown in Fig. 10.

Jan 1, 1951

By C. K. Eilerts, J. D. Ham

Laboratory research has been conducted to evaluate the characteristic effects of condensate saturation on the mobility of gas in typical reservoir rocks. A pump with two pistons provided phases in equilibrium at controlled flow rates and constant liquid-vapor volume ratios. Core samples were tested in a holder that permitted sealing steady-state phases in the pore spaces under flow test pressures for weighing with sufficient precision to give an accurate measure of the attained saturations. Parameters of the study were pressure, apparent velocity, flowing liquid-vapor volume ratio, fluid composition, core material and length-to-diameter ratio. Tests were conducted at 515 and 1,515 psia to determine the effect of pressure on the mobility-saturation relationship. Influence of the apparent velocities 0.30, 0.15 and 0.07 cm/sec and of five liquid-vapor volume ratios from 0.0001 to 0.01 was determined at 515 psia The principal fluid system was nitrogen and and separator liquid from a Gulf Coast condensate, but the effect of a condensate of different viscosity was also determined. The significance of a possible concentration of liquid near the outlet end of the test cores was investigated. Core materials included a consolidated sandstone and a low-permeability limestone. Relative mobility and liquid-vapor volume ratio relationships are concluded to be dependent on pressure, saturation and, to a lesser extent, on velocity. For each porous medium and fluid there is a minimum saturation essential to two-phase flow, and high velocities of flow have only limited effect on saturations in this range. INTRODUCTION It is now recognized that knowledge of the availability of a reservoir gas — the period that gas may be recovered from a reservoir at a given rate — is as important as the estimate of gas in place. When reservoir conditions are such that pressure decline owing to production will result in retrograde condensation, liquid saturation can increase in the structure around the production well in a way that may restrict flow capacity, and hence future availability. l Based on a numerical solution of transient radial flow of single-phase gas-condensate fluids, 2 a program for computing the accumulation of condensate in a reservoir and the effect of this condensate on deliverability has been developed. During this development a need evolved for data that described the influence of pressure, velocity of flow and condensed liquid on mobility as recovery progressed. This paper presents the results of experimental investigation to obtain insight into the mobility relationship at reservoir pressures of gas-condensate fluids. A core holder for flow tests at reservoir pressure was developed to weigh the core and its fluid contents under pressure to determine saturation. A specially constructed pump was used to drive a two-phase fluid through the core until a steady state prevailed. The core was used as a differential device, and properties measured were intensive rather than extensive. APPARATUS Fig. 1 shows a schematic representation of the major pieces of equipment used in the mobility determination. The weighable core holder is connected to a two-piston, constant-displacement pump. Attainment of steady-state flow is indicated by stability of the flow differential read from the high-pressure manometer. WEIGHABLE CORE HOLDER An important part of the data needed was the mobility-saturation relationship. This required that mobilities and saturations be measured at pressures, flow velocities and liquid-vapor volume ratios characteristic of condensate reservoirs.

By B. H. Caudle, W. J. Bernard

Factors which influence the success or failure of a waterflood can seldom be determined in the laboratory. For this reason pilot waterfloods are initiated in a repreventative portion of the oil reservoir in question. For a pilot flood to predict quantitatively the recovery to be expected in a field-wide waterflood operation, the pilot area must behave as though it were confined (surrounded by similar areas). In this study, laboratory fluid-flow models were used to determine the simplest pilot pattern, for particular conditions of mobility ratio and initial gas saturation, that would behave as though it were confined. Pilot patterns studied ranged in complexity from a single inverted five-spot to a grouping of nine regular five-spots. Only the innermost producing well in each pattern was studied. Model results showed that the optimum number of wells in the pattern depends upon the oil-water mobility ratio and the expected oil-bank size. Unfavorable mobility ratios will, in general, require more wells in the pilot pattern than will favorable mobility ratios. Pilot patterns in reservoirs which contain a dispersed, flowable, free gas saturation will require fewer wells than for the under-saturated case. The single inverted five-spot pattern was found to be unsatisfactory for predicting behavior of fully developed waterfloods. In particular, it is possible that, in reservoirs which contain a flowable, dispersed gas phase, the oil bank will never be observed at the producers due to the large amounts of free gas which continue to be produced with the oil. INTRODUCTION One method which has been used to predict the performance of a waterflood is the pilot flood. The pilot waterflood is a flood which involves only a small cluster of the reservoir wells and is located in a small, representative portion of the reservoir. The object is that oil produced from the pilot can, in some way, be related to the oil recovery to be expected from a field-wide expansion of the waterflood. However, these field pilot waterfloods have often been unreliable in the prediction of oil recovery in a fully developed waterflood. This unreliability has also been demonstrated in several laboratory studies of pilot floods. Some of the investigators have shown that there are situations in which the pilot flood oil production is far too optimistic with respect to the oil recovery in the fully de- veloped flood. Others4-G have shown that the pilot results can also be pessimistic, especially if the pilot waterflood is initiated in an oil reservoir which has been depleted by primary recovery and is at very low pressure. The major reason for this unreliability of pilot water-floods is the migration of fluids into or out of the pilot area. By the well-known method of images, if straight lines can be drawn to represent vertical planes of symmetry in a porous medium which contains pressure sources and sinks (injectors and producers), then these lines are invariant streamlines, or lines across which there is no potential gradient, and therefore no flow. In an actual reservoir, these lines of symmetry can never be established exactly because of reservoir inhomogeneities and irregular reservoir boundaries. However, if the reservoir is relatively large and contains wells in repetitive patterns, these lines of symmetry are commonly assumed to exist for the pattern units sufficiently far removed from the reservoir boundary. Lines of symmetry for the five-spot injection pattern are shown in Fig. 1. Each five-spot unit in this figure can be considered confined with respect to flow across its boundary. In pilot floods this is not the case. The lines of symmetry for the pilot patterns investigated in this study are shown in Fig. 2. It is obvious that the fluid within these pilots is not confined and is therefore able to migrate into or out of the pilot area. Intuitively, one can see that, if more wells are added to the pilot, the innermost unit tends to behave more and more like the confined pattern. However, there is a practical limit to the number of wells which should be placed in the pilot. This limit is usually determined by economic factors. It was the purpose of this study to use laboratory fluid-flow models to determine which of the previously mentioned pilot patterns will force the innermost producing well to behave as it would in a fully developed waterflood. Since fluid migration is influenced by initial saturation conditions and the mobility ratio, these factors were included in the study. The ultimate objective of this study was to develop data which would allow the operator to choose a pilot pattern and operating conditions that will yield a production history which can be applied directly as an estimate of the performance of each production well of the fully developed waterflood. BASIS FOR THE STUDY The basic problem of field pilot floods is the migration of the reservoir fluids into or out of the pilot area. This problem has been the subject of previously reported model studies on pilot floods. These studies have been concerned mainly with the development of arbitrary "correction factors" to be applied to the simple, unconfined pilot systems such as the single five-spot. The correction factors were intended to adjust the production history of the un-

By R. J. Sandrea, S. M. Farouq Ali

The results of an experimental and theoretical study of the effects of rectilinear impermeable barriers and highly permeable channels on the sweep efficiency and conductivity of a five-spot network are presented. The study was carried out using Hele-Shaw, and conductive sheet analogs for both. normal and inverted flood patterns. A functional relationship was developed which provides quantitative prediction of the above parameters; i.e., sweep efficiency and conductivity, for the nonhomogeneous system. To evaluate this, it is necessary only to measure the interference modulus of the obstacle using a simple expression. The results indicate that impermeable barriers, with an interference modulus greater than zero, always cause a decrease in the conductivity and the sweep efficiency of the pattern. On the other hand, permeability channels do not have a significant effect on these parameters, unless they are located along the streamlines. The study also discusses a method of formulating the difference equations pertaining to the two-dimensional Laplacian in a system containing rectilinear barriers. In addition, a technique is described for tracing the progress of a free surface, using marked particles, in a stream containing discontinuities SuCh as those occurring at the extremities of barriers. The above computational scheme was used in a digital computer program to simulate results of the Hele-Shaw analog. The computed values of sweep efficiency mere in good agreement with the experimental values. INTRODUCTION At the present time waterflooding remains the most widely used technique for the secondary recovery of oil. Among the numerous factors that affect the performance of a waterflood, the areal sweep efficiency constitutes one of the most critical parameters. It is a function only of the geometric distribution of the wells for a homogeneous medium and unit mobility ratio. Geological considerations, however, such as the presence of sealing faults or solution channels in the rock matrix, would generally exert an adverse effect on the areal sweep efficiency of a waterflood network. Surprisingly little information is presently available on the quantitative implications of such permeability interferences. It was the object of this investigation to consider the presence of rectilinear, impermeable and highly permeable interferences in an otherwise homogeneous five-spot pattern, and to analyze their effects on the resulting sweep efficiency and pattern conductivity. The experimental phase of the study was conducted using two different models: the Hele-Shaw flow cell and the field plotter. For experimental convenience, the geometric boundaries of the five-spot were assumed to constitute streamlines even in the case where the interference was asymmetrically placed with respect to a repeated five-spot pattern. A second object of the study was to develop a computational scheme for numerically calculating the pressure distribution in a five-spot flow pattern containing rectilinear, impermeable barriers, and to use this distribution to compute the sweep efficiency. EXPERIMENTAL PROCEDURE HELE-SHAW ANALOG The Hele-Shaw analog was used both as a visual model and for determining the sweep efficiency for systems involving impermeable barriers. The physical limitations of this model as a means of experimentally studying the motion of a fluid in porous medium have been adequately discussed elsewhere.2,7 Likewise, it can be easily verified that the analogy remains valid when a portion of the region between the plates contains an obstacle of the same thickness as the distance between the plates. The model used in this study was composed of

By O. L. Culberson, J. J. McKetta

Experimental and smoothed data are presented for the solubility of methane in water for temperatures of 77, 100, 160. 220. 280, and 340°F at prejsures to 10.000 psia. The minimum solubility phenomenon exists within this temperature range to pressures of 10.000 psia. INTRODUCTION The study of hydrocarhon-water systems has been extended to the determination of the solubility of methane in water at pressures to 10.000 psia. The experimental apparatus, and the technique. are the same as that previously reported.' - In the determination of the solubility of methane in water, only two phases were present at temperatures between 100 and 340°F. these being the vapor phase and the water-rich. liquid phase. The determinations involved the agitation of methane and water in an equilibrium cell. withdrawal of a sample from the liquid phase, and the analysis of the sample. The experimental value; determined in this manner are pre9ented in Table I and in Fig. 1. Since experimental and analytical techniques have improved since the initial experiments with this equipment, it was decided to repeat the 77°F isotherm determinations.' Fig. I shows that the individual results for this isotherm are much

Jan 1, 1951

By J. J. McKetta, O. L. Culberson

Experimental and smoothed data are presented for the solubility of methane in water for temperatures of 77, 100, 160. 220. 280, and 340°F at prejsures to 10.000 psia. The minimum solubility phenomenon exists within this temperature range to pressures of 10.000 psia. INTRODUCTION The study of hydrocarhon-water systems has been extended to the determination of the solubility of methane in water at pressures to 10.000 psia. The experimental apparatus, and the technique. are the same as that previously reported.' - In the determination of the solubility of methane in water, only two phases were present at temperatures between 100 and 340°F. these being the vapor phase and the water-rich. liquid phase. The determinations involved the agitation of methane and water in an equilibrium cell. withdrawal of a sample from the liquid phase, and the analysis of the sample. The experimental value; determined in this manner are pre9ented in Table I and in Fig. 1. Since experimental and analytical techniques have improved since the initial experiments with this equipment, it was decided to repeat the 77°F isotherm determinations.' Fig. I shows that the individual results for this isotherm are much

Jan 1, 1951

By O. L. Culberson, J. J. McKetta

INTRODUCTION The equilibrium constants for methane and for water, and for ethane and water have been calculated from experimental data for the two binary systems.2,3,11,12 These constants are for the two-phase systems for the temperature range of 100" to 340°F and the pressure range of 200 to 10,000 psia. The constants for ethane are greater than those for methane. Equilibrium constants for a natural gas from a natural gas-water system6 are about the same as those for methane. Equilibrium constants for water in all three systems are very nearly the same over the greater part of the range of temperatures and pressures studied. In ideal solutions, the vapor-liquid equilibrium constants for a component should be the same in all such solutions at a given temperature and pressure.5 Few solutions are ideal, and consequently the use of generalized constants often leads to error in situations where they do not actually apply. In decidedly non-ideal systems, it is desirable to have equilibrium constant data for the specific system. Vaporization equilibrium constants may be calculated either by thermodynamic methods or from experimental vapor-liquid equilibrium data. In the thermodynamic calculation. the equilibrium constant K may be shown to be" K = fP,/fl'..........(1) where fPi is the fugacity of the pure component i at the given temperature and at the vapor pressure of the pure component, and fp is the fugacity of pure i in the gaseous state at the temperature and total pressure of the system. At best the thermodynamic calculation results in a K applicable to ideal solutions. Equilibrium constants calculated from Equation (1) have been found to have only limited agreement with experimental values, even though the solutions for which they were calculated approached ideality."'" If the more volatile component is at a temperature above its critical, the accuracy of the equilibrium constant for the component is made more doubtful by the use of the vapor pressure term under such conditions. In order to make the thermodynamic calculation on a component above its critical temperature, one must resort to one of the empirical methods of extrapolation of the vapor pressure to conditions above its critical point.13 Application of the thermodynamic equilibrium constant then to the methane-water or the ethane-water systems would be risky since the systems are non-ideal, and the methane and ethane are above their critical in most petroleum operations. ETHANE-WATER SYSTEM In the temperature range of from 100° to 340°F and for pressures up to 10,000 psia, the vapor-liquid equilibrium data 'References given at end of paper. Manuscript received in the office of the Petroleum Branch March 16, 1951.

Jan 1, 1951

By J. J. McKetta, O. L. Culberson

INTRODUCTION The equilibrium constants for methane and for water, and for ethane and water have been calculated from experimental data for the two binary systems.2,3,11,12 These constants are for the two-phase systems for the temperature range of 100" to 340°F and the pressure range of 200 to 10,000 psia. The constants for ethane are greater than those for methane. Equilibrium constants for a natural gas from a natural gas-water system6 are about the same as those for methane. Equilibrium constants for water in all three systems are very nearly the same over the greater part of the range of temperatures and pressures studied. In ideal solutions, the vapor-liquid equilibrium constants for a component should be the same in all such solutions at a given temperature and pressure.5 Few solutions are ideal, and consequently the use of generalized constants often leads to error in situations where they do not actually apply. In decidedly non-ideal systems, it is desirable to have equilibrium constant data for the specific system. Vaporization equilibrium constants may be calculated either by thermodynamic methods or from experimental vapor-liquid equilibrium data. In the thermodynamic calculation. the equilibrium constant K may be shown to be" K = fP,/fl'..........(1) where fPi is the fugacity of the pure component i at the given temperature and at the vapor pressure of the pure component, and fp is the fugacity of pure i in the gaseous state at the temperature and total pressure of the system. At best the thermodynamic calculation results in a K applicable to ideal solutions. Equilibrium constants calculated from Equation (1) have been found to have only limited agreement with experimental values, even though the solutions for which they were calculated approached ideality."'" If the more volatile component is at a temperature above its critical, the accuracy of the equilibrium constant for the component is made more doubtful by the use of the vapor pressure term under such conditions. In order to make the thermodynamic calculation on a component above its critical temperature, one must resort to one of the empirical methods of extrapolation of the vapor pressure to conditions above its critical point.13 Application of the thermodynamic equilibrium constant then to the methane-water or the ethane-water systems would be risky since the systems are non-ideal, and the methane and ethane are above their critical in most petroleum operations. ETHANE-WATER SYSTEM In the temperature range of from 100° to 340°F and for pressures up to 10,000 psia, the vapor-liquid equilibrium data 'References given at end of paper. Manuscript received in the office of the Petroleum Branch March 16, 1951.

Jan 1, 1951

By B. J. Dotson, P. N. McCreery, R. L. Slobod, James W. Spurlock

A core sample porosity-check program is described. A number of laboratories participated in the investigation. which comprised measuring the porosities of ten selected natural and synthetic core samples. Each laboratory employed its own method (or methods) of measurement. These included Boyle's Law, water-saturation. and organic liquid-saturation methods. Brief descriptions of each method employed are given. In general, the measured values of porosity were in reasonably good agreement. The average deviation of porosity from the mean or average values for the group of samples was ±0.5 porosity per cent. The results of these measurements are compiled and presented in graphical form. INTRODUCTION The total hulk volume of a porous sample is derived from the sum of two volumes, the void or pore volume and the solid* or grain volume. The porosity fraction of the sample ia defined as the ratio of the void volume to the bulk volume. Multiplication of this ratio by 100 converts it to per cent porosity. Distinction is made here between total porosity and effective porosity. The former includes all void space, both interconnected and isolated, while the latter includes only those voids which are interconnected. This investigation deals only with the effective porosity.* Numerous cases had been noticed in which there appeared to be appreciable discrepancies in the results of porosity determinations on core samples. Differences of as much as 10 to 15 porosity per cent had been reported from different sources

Jan 1, 1951