bluuebunny/crossref_metadata_2025_split huggingface dataset:
Swept Areas After Breakthrough in Vertically Fractured Five-Spot Patterns
Authors: Simmons Jack , Landrum Bobby L. , Pinson James M. , Crawford Paul B. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 73–77.

Abstract
Potentiometric model data have been obtained to estimate the effect of vertical fractures on the areas swept after breakthrough in water flooding and miscible displacement programs such as gas cycling where the mobility is near one. The data are presented for the case of the five-spot pattern in which the center well is fractured various lengths and orientations. The data indicate that for 10-acre spacing, fractures extending over 200 ft in either direction from the fractured well may result in reductions in sweep efficiencies from 72 to approximately 34 per cent. However, the area swept after breakthrough may be quite large and only 10 or 12 per cent less than would be obtained if the reservoir were not fractured.
For the specific case when the volume of fluid injected is equivalent to 100 per cent of the pattern volume, the swept area may vary from 80 to 88 per cent, depending on the length of the fracture. The former value is that which occurs when the breakthrough or sweep efficiency was only 34 per cent and the latter figure of 88 per cent is that which is obtained if the reservoir were unfractured. It is pointed out that although the sweep efficiency may be very low in vertically fractured five-spot patterns, the area swept at low water-oil ratios may be only 5 to 10 per cent less than those achieved if the reservoir were unfractured.

Introduction
Since the initiation of commercial reservoir fracturing techniques it has been desirable to determine the effect of fractures on the areas swept after breakthrough. Most water flooding or gas cycling projects are continued for substantial periods after the breakthrough of the injected fluid. Although the sweep efficiency serves as one criterion for rating various flooding patterns, the area swept after breakthrough for various water-oil ratios or percentage wet gas, if cycling, is of perhaps more importance than the sweep efficiency alone. Sweep efficiency data on the vertically fractured five-spot have been presented.
Previous work on the line-drive pattern has shown the effect of vertical fractures on the area swept after breakthrough for the case in which the distance between injection and producing wells divided by the distance between adjacent input wells was equivalent to 1.5 (see Ref. 2). The data indicated that for the line-drive pattern it may be desirable to flood or cycle substantially perpendicular to the fractures in order to achieve the greatest recovery for the smallest volume of fluid injected. For this study the center well of a five-spot is assumed as the fractured well.
A Water Shut-Off Method for Sand-Type Porosity in Air Drilling
Authors: Goodwin Robert J. , Teplitz A.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 163–167.

Abstract
A new type water shut-off for use in air drilling has been developed. The method has been 99 to 100 per cent effective in several different formations of intergranular-type porosity. Since costs for materials, time and equipment used are relatively small, the process should extend economies of air drilling to many new areas.
The treatment involves a new technique for forming a water-insoluble precipitate within the pores of a rock. Advantage is taken of the difference in mobility of a liquid and a gas in porous media to achieve the greatest volume of precipitate in a given pore. Reactants selected for the laboratory and field tests were aluminum sulfate solution and gaseous ammonia.
This process has been tested in both intergranular and fractured-type porosities. It has consistently shut-off between 99 and 100 per cent of the water flowing from formations having intergranular-type porosity and permeabilities ranging from a few millidarcies to over a darcy. The treatment is not particularly suitable for shutting-off water from fractured formations although plugging of the order of 50 per cent or greater has been achieved in all such applications. Among advantages of the treatment are:no reaction waiting time after a relatively short placement time,a low materials' cost of about $3/ ft of hole treated,use of common service-type equipment for treatment, andno unusual requirements for mixing and placement.

Introduction
In rotary drilling with air or gas it has been possible to increase bit life by tenfold and more than double rate of penetration over corresponding performance when drilling with mud. These factors have amounted to as much as 22 per cent savings on total cost of drilling a well. However, these advantages are rapidly lost when water is encountered in an air- or gas-drilled well because water interferes with the removal of cuttings from the hole and also gives rise to other difficulties. In attempting to combat water troubles, operators have commonly resorted to such measures as mist drilling, treatment with cement or chemicals, converting to conventional mud drilling, or setting casing. In many cases these measures have either been costly or ineffective.
Effect of Unsteady-State Aquifer Motion on the Size of an Adjacent Gas Storage Reservoir
Authors: Katz D.L. , Tek M.R. , Coats K.H. 
Published: February 2020

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.
Streaming Potential Phenomena in SP Log Interpretation
Authors: Hill H.J. , Anderson A.E. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 203–208.

Abstract
Laboratory data for 155 field muds and 77 shales have been used to develop correlations to estimate the net streaming potential component of the SP. Analysis of these data and comparison with field tests show that streaming potential corrections must be made to obtain an accurate estimate of the electrochemical potential for use in the determination of formation water resistivity.

Introduction
The self-potential curve is related to formation water resistivity, and considerable effort within the oil industry has been directed toward clarifying this relationship. The Schlumbergers and Leonardon recognized that two types of potentials, electrochemical and electrokinetic, resulted in the net potential variation in the borehole. Most of the later papers have dealt with the electrochemical component and its controlling parameters.
The investigations of Wyllie, Salisch, and Moore provide the most extensive sources of data on streaming potentials across mud cakes. These authors observed streaming potentials of sufficient magnitude to be of critical importance in SP interpretation, if it is assumed that streaming potentials develop only opposite permeable beds.
Streaming potentials across shales have been reported by Schenck and by Gondouin, et al. Since SP magnitude is the difference in potential opposite shale and sand beds, these authors suggested that the net streaming potential component may be negligible.
The present investigation was initiated to evaluate empirically some of the parameters controlling the magnitude of the net borehole streaming potential and to determine whether useful relations between mud properties and net streaming potential could be established.

Methods and Apparatus

MUD PROPERTIES
Field muds were used in this investigation. These muds were characterized by the amount and type of chemical treatment utilized for five days before sampling. Filter loss, mud resistivity, mud density and filtrate resistivity were determined for each mud with conventional methods and apparatus. Mud filtrate pH was estimated with Hydrion pH paper for the appropriate range.

STREAMING POTENTIALS ACROSS MUD CAKES
Commercial calomel-saturated KCl electrodes are subject to potential changes attributed to contamination of the very small fiber-tip bridge by particles of clay from the drilling mud. To minimize this difficulty, a large diameter bridge (Fig. 1) was constructed with saturated KC1-agar gel and a filter disc of microporous porcelain.
The Effect of Gypsum on Core Analysis Results
Authors: Hurd B.G. , Fitch J.L. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 221–224.

Abstract
The presence of gypsum in samples subjected to standard core analysis introduces serious errors in the measurement of water saturation and porosity. The magnitude of these errors, depending upon the type of analysis procedure used, has been evaluated experimentally and theoretically. Water-saturated pore volumes determined by vacuum distillation or retort procedures may be too high by as much as 48 per cent of the volume of gypsum present. The maximum error in this value determined by Dean-Stark extraction with toluene is 36 per cent of the gypsum volume. If pore space is measured by a Boyle's law type porosimeter the maximum error due to gypsum is 38 per cent of the original gypsum volume present.
The conscientious core analyst may eliminate the errors caused by gypsum by either of two methods. He may apply suitable corrections for the water of crystallization removed from gypsum, or take special precautions to prevent dehydration of gypsum during core cleaning and analysis procedures. These alternatives are discussed and methods for obtaining reliable core analysis data are proposed.

Introduction
Gypsum (CaSO42H2O) occurs as a common mineral in many of the world's sedimentary basins. In addition to its presence as primary bedded evaporitic deposits, it is often found as secondary replacement zones and pore-fillings in host rocks. That it may cause false indications in porosity, both on neutron logs and in standard core analysis, has been generally recognized. False porosity interpretations from neutron logs result because the chemically bound water in gypsum attenuates neutrons as effectively as free water. Errors in core analysis result when gypsum is dehydrated prior to or during the analysis.
Vacuum retort procedures used by many laboratories to determine fluid saturation and porosity effect a complete removal of water of crystallization from gypsum. The crystal water, distilled and collected with free water from the sample, is counted as water-saturated pore space.
The Effect of Particle Size Distribution and Exchange Cation on Gel Properties of Fractionated Bentonite Suspensions
Authors: Jessen F.W. , Mungan Necmettin 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 455–459.

Introduction
The plastic flow characteristics of clay water suspensions were first recognized by Bingham 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. When dealing with systems which contain a major portion of particles below 1-micron size, slit ultramicroscopy, centrifuge methods of Svedberg, Beams, and McBain, 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.
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.
Calculation of the Stabilized Performance Coefficient of Low Permeability Natural Gas Wells
Authors: Poettman Fred H. , Schilson Robert E. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 240–246.

Abstract
The direct determination of the stabilized performance behavior of low capacity, slowly stabilizing gas wells is extremely time-consuming and wasteful of gas. From both field experience and theoretical considerations, a test procedure has been evolved by which the stabilized back pressure behavior of such gas wells can be predicted without having to revert to long time flow tests.
The method consists of using the isochronal test procedure to establish the slope of the back pressure curve, "n", and the short time variation of the performance coefficient, "C", with time.
From this short time transient flow data and theoretical considerations, the value of C at large times can be established. By assuming the radius of drainage of a well to be half the distance between wells, one can calculate the stabilization time for various well spacing patterns. Once the stabilization time for a given spacing has been determined, the value of C can be calculated and the stabilized back-pressure curve can be established.
The calculated performance coefficient as a function of time was compared to the experimentally measured values for a number of gas wells. The deviation of the calculated from the experimental results vary depending on the set of short time experimental points used to evaluate the parameters of the equation. The longer the time for the flow test data used in the calculations, the better was the agreement with the experimental results. The time necessary to obtain this data from well tests varies considerably, depending on the physical nature of the reservoir under consideration.

Introduction
For many years, the U. S. Bureau of Mines Monograph 7 has served as a guide for testing and evaluating the performance of gas wells by means of the back-pressure method.
Simplified Equations of Flow in Gas Drive Reservoirs and the Theoretical Foundation of Multiphase Pressure Buildup Analyses
Authors: Martin John C. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 321–323.

Abstract
Simplified equations are developed for the flow of fluids in gas drive reservoirs in which the effects of gravity can be neglected. The results show that the pressure distribution is governed by a nonlinear heat flow type of equation, and the saturation distributions are related to the pressure by the same equations as those developed by Muskat for the average pressure and saturations in gas drive reservoirs.
Under certain conditions the equation for the pressure can be approximated by the linear form of the heat flow equation. This equation is analogous to the equation for the pressure in single-phase compressible flow. The analysis reveals that the equation for the pressure in multiphase flows can be obtained directly from the equation for the pressure in single-phase flows by simply replacing the single-phase compressibility by the total compressibility and the single-phase mobility by the sum of the mobilities of all the fluids present. Perrine's method of pressure buildup analysis for multiphase flows is based on these same substitutions. Thus, the development presented in this paper constitutes a theoretical justification for Perrine's method of pressure buildup analysis.

Introduction
One of the most difficult problems associated with the production of oil is the determination of the flow of the fluids within the reservoirs. One purpose of this paper is to present the development of simplified equations for the flow in gas drive reservoirs. The other purpose is to present some of the needed theoretical foundation for the methods currently being used in the analysis of multiphase pressure buildup data. The analysis presented in this paper makes use of a partial linearization of the equations governing multiphase flows. It is felt that the process of linearizing or partially linearizing the nonlinear equations of multiphase flows can lead to useful results since this process has proved extremely valuable in the study of other fields of science and engineering where nonlinear equations are encountered.
Influence of Propping Sand Wettability on Productivity of Hydraulically Fractured Oil Wells
Authors: Graham John W. , Monaghan P.H. , Osoba J.S. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 324–329.

Abstract
Of the many factors which affect the productivity of hydraulically fractured wells, the wettability of the propping sand has received little attention in the past. This paper shows that the wettability of the propping sand is an important factor which should not be overlooked.
An analysis of relative permeability data shows that fractures packed with water-wet sand should be more permeable to oil than are fractures packed with oil-wet sand. Laboratory results verify this conclusion. Calculations show that higher permeability to oil in the fracture should provide higher well productivity.
A method is presented which ensures that the propping sand in an induced fracture is water-wet even though oil is used as the fracturing fluid. The method has been used in more than 150 field jobs; the field results are discussed briefly.
The fluidized nature oil water-wet sand in oil has given unexpected benefits. This characteristic of water-wet sand and how it has been used advantageously in field operations are discussed.

Introduction
Hydraulic fracturing of subsurface strata to increase the productivity of oil and gas wells has been practiced for about 10 years. Today, fracturing is used more often than any other method of well stimulation. Basically, the process consists of breaking down (fracturing) a subsurface formation with pressure applied by means of a carrier fluid, usually oil or water, and propping the induced fractures apart by means of an agent, usually sand, suspended in the carrier fluid. Currently about 68 per cent of all fracturing is done with a simple mixture of refined oil or lease crude oil and sand.
The research of other investigators has suggested that dry sand is rendered oil-wet when it is contracted with certain types of crude or refined oils. Hence, it may be expected that some fracturing operations employing an oil as the carrier for sand leave fractures packed with oil-wet sand. Conversely, those operations which employ water as the carrier for the sand probably leave the fractures packed with water-wet sand. Since the permeability of a sand-packed fracture to a mixture of oil and water is dependent upon the wettability of the fracturing (frac) sand, research was undertaken to determine to what extent the wettability condition (water-wet or oil-wet) controls fracture permeability which, in turn, affects well productivity. Additional research was directed toward the development of a method for obtaining the desired fracture wettability.
Correlation of kg/ko Data with Sandstone Core Characteristics
Authors: Felsenthal Martin 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 258–261.

Introduction
Engineers are frequently faced with the problem of having to predict oil recovery from a solution gas drive reservoir in the early life of a field. This is often the time when actual laboratory or field-derived gas-oil permeability (kg/ko) data are not yet available. Although excellent collections of kg/ko data for various types of rocks may be found in the literature, a need exists for a more detailed correlation of k2/k, data with core properties such as porosity, permeability, clay content or pore-size distribution. It is the purpose of this article to present this type of correlation for sandstone material. The correlation is based on laboratory tests performed on over 300 core samples from 19 reservoirs in the United States and Canada.

Experimental
Cores were analyzed by routine procedures, using samples of conventional size (7/8-in. diameter, 7/8-in long) cut parallel to the bedding planes. Air permeability was measured at 1.67 atm mean pressure in a Hassler-type apparatus. Porosity was determined with the aid of a Ruska bulk volume meter and a Boyle's Law rock volume meter. An evaporation method was used to evaluate irreducible water saturations.
Core samples were saturated with 25,000 ppm NaCl brine. The brine was reduced to the irreducible saturation, and the remainder of the pore space was filled with kerosene. This was followed by multiphase flow tests using the so-called "dispersed feed" technique. In this technique, gas and oil (kerosene and kerosene-saturated air) were dispersed with the aid of a porous Alundum feed head, the face of which contained a waffle-shaped system of Lucite-lined grooves. Oil entered the back side of the feed head and emerged at the raised areas of the front face. Gas was introduced directly into the system of grooves at the front face. The gas-oil mixture then entered the test core which was kept in capillary contact with the feed head. Permeabilities were determined from rate and pressure measurements and saturations from weights. All determinations were performed at equilibrium or steady-state conditions. Pore-size distributions were determined on selected samples by a mercury injection technique.