bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sonic Logging
Authors: Tixier M.P , Alger R.P. , Doh C.A. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 106–114.

Abstract
The principle, the equipment and field operation of sonic logging are described. The two-receiver system produces logs independent of hole size and mud. Field experience is given and forms the basis for the interpretation of the log. The derivation of porosity values from measured velocities is discussed, according to the type of formations (hard formations, compacted sands, and unconsolidated formations). The time-average equation proposed by M.R.J. Wyllie, A.R. Gregory and L.W. Gardner is used as a basis for the computation of porosity in limestones, cemented sandstones and compacted sands. Variations in the lithologic character of limestones do not seem to change the porosity calibration markedly. The compaction of sands is related to the compaction of shale adjacent to them; and, thus, the shale velocity is used for the establishment of empirical relations for the computation of porosity in unconsolidated formations. Various formulas are tentatively presented to account for shale and fluid content.
Field experience demonstrates that considerable attenuation of sonic energy takes place in unconsolidated formations, particularly when gas bearing, and in fractured formations. Unusually large attenuation produces skipped cycles, a feature easily recognized. The application of sonic logging to structural studies is featured, showing its possible integration with the dipmeter. Correlation and its application to the interpretation of seismic surveys are reviewed.The paper is illustrated with field examples.

Introduction
Sonic logging is the recording of the time required for a sound wave to traverse a definite length of formation. Sonic travel-times are inversely proportional to the speed of sound in the various formations.The speed of sound in subsurface formations depends upon the elastic properties of the rock matrix, the porosity of the formations and their fluid content and pressure. Below the "weathered" or low-velocity layer extending from 50 to 100 ft or so below the surface, sound velocities may range from about 6,000 ft/sec in shallow shales to as much as 24,000 ft/sec in dolomites. In hard formations (well cemented and/or compacted), the sonic log reflects the amount of fluid in the formations; hence, it correlates well with their porosity.
Some Effects of Invasion on the SP Curve
Authors: Segesman F. , Tixier M.P. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 138–146.

Abstract
Explanations based on theory and laboratory tests are offered for certain unusual features of SP logs which may befog their interpretation, namely the "sawtooth" SP and the reduction or increase of SP with time.
The sawtooth SP is frequently seen in SP recordings of thick, very permeable water sands of the Louisiana Gull Coast. Using SP data from a resistor network analog, this anomaly is explained on the basis of a thin shale streak within the sand, under which the invading filtrate accumulates by gravity segregation. The electromotive force then appearing across the shale streak gives rise to the anomalous SP.
Reduction of the SP on successive logging runs has often been observed in very permeable sands when, as indicated by the resistivity curves, the invasion depth has been reduced to practically zero. Laboratory results verify that this phenomenon may be due to the presence of an electromotive force across the mud cake when the fluids on either side differ in activity.
Also, there is, in some cases, an increase of SP deflection on successive logging runs, because the emf initially present across the mud cake disappears as the somewhat saline water just behind the mud cake is progressively flushed out by the invading filtrate. Field examples and laboratory data are presented.

Introduction
Some unusual features are frequently observed on certain SP logs which make interpretation difficult. The purpose of this paper is to offer explanations of several cases of interest. All of these are related to the conditions of invasion. The cases to be discussed are as follows.
(1)The sawtooth SP anomaly which is frequently seen within the thick, highly permeable saltwater sands of the Louisiana Gulf Coast.
(2)Reduction of the SP deflection from the usual sand line in very permeable sections when the depth of invasion is practically nil. As will be explained, such a reduction is attributable to a membrane electromotive force across the mud cake.
(3) An increase of the SP with time just after the formation is drilled as a result of progressive flushing of the invaded zone.
Fosterton Field - An Unusual Problem of Bottom Water Coning and Volumetric Water Invasion Efficiency
Authors: Elkins Lincoln F. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 130–137.

Abstract
Water coning into wells with bottom water present in the Fosterton field, when their oil recovery was only 0.1 to 1.5 per cent of oil in place below the lowest perforation, confirms lack of shale barriers to vertical flow which also are not apparent in cores and electric logs. Low contrast of vertical and horizontal permeability, high mobility ratio between oil and water zone and possible rate effects due to gravity combine to prevent easy analysis of water invasion pattern and efficiency by analogy or intuition. Theoretical analysis of performance including these factors using a new direct numerical solution of potential distribution in a network led to unanticipated indications that water would underrun the entire oil reservoir with low volumetric coverage if supplied through natural influx or peripheral water injection below the oil-water contact. An unusual pattern of water injection is to be adopted in this recently unitized pool to provide more uniform water flooding in that two-thirds of the oil reservoir not underlain by bottom water.

Introduction
The Fosterton field, Southwestern Saskatchewan, Canada, was discovered in Jan., 1952. It produces at a depth of 3,100 ft from a pinch-out of the Roseray sand at the Lower Cretaceous-Jurassic unconformity. The field, covering 2,500 acres, contains 54 wells on 40-acre spacing. Development was essentially complete in June, 1954, but significant production did not start until May, 1955, when a pipeline outlet became available. Within one year rapid increases in gas-oil ratio and early encroachment of water created operating problems in the down-structure eastern half of the field and raised serious questions about reservoir performance and ultimate recovery. This paper describes the unusual behavior Of water encroachment on both well and reservoir base and the analyses made to interpret it. The field was unitized July 1, 1958, for water flooding.
A Generalized Water-Drive Analysis
Authors: Hutchinson T.S. , Sikora V.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 169–178.

Abstract
This paper presents a method for making a water-drive analysis without prior knowledge of aquifer geometry and uniformity using a standard desk calculator. Although it is necessary to know the initial oil in place to use this method, this is a minor limitation to the scope of the method since in most reservoirs it is possible to obtain reasonably accurate volumetric oil-in-place estimates.
An equation is developed which relates pressure at the water-oil contact to the water influx rate as a function of time by a factor called the resistance function. The resistance function introduces the composite effect of the aquifer geometry and flow resistance distribution. It is pointed out that the characteristic shape of this function makes it possible to start with an approximation of the function and successively improve the approximation until the correct resistance function curve is obtained. In this fashion water-drive estimates can be made without the limitation of assuming simplified aquifer shapes and flow distributions. This is the novel feature of this development. Methods are given for extrapolating the final curve to calculate future aquifer behavior.
Equations are developed for adjusting the pressures and water influx rates where it appears that possible errors in these quantities make it difficult or impossible to obtain a useable resistance function curve without this adjustment. Application of the pressure build-up analysis technique to estimate some of the aquifer properties is also presented.

Introduction
A great many oil pools are the result of oil accumulation in some type of trap in an otherwise large and continuous porous stratum. The void space of this stratum outside of the oil pool itself is filled with water or brine. In analyzing performance of the oil pool surrounded by this water aquifer, it is quite necessary, in most cases, to include behavior of the water. When the pressure at any point in a fluid system is lowered, such as by opening a well in an oil sand, fluids in the immediate neighborhood of this point will begin flowing towards this lower pressure sink.
Nonlinear Behavior of Elastic Porous Media
Authors: van der Knaap W. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 179–187.

Abstract
A theoretical and experimental analysis is given of the change in volume of a porous medium due to changes in external and internal pressures. The results enable one to deduce directly the effect of large increments in stresses.
It is shown that the three-dimensional representation of the volume of a nonlinear porous system is a cylindrical ruled surface, the generating lines of which have a slope according to the solid rock compressibility. Analytical expression for such a surface is very simple. It follows that the bulk and pore compressibilities depend only on the difference between pore fluid and external hydrostatic pressure, i.e., the effective rock frame pressure. From measurements on a number of sandstones as well as limestones it can be concluded that for practical values of this effective frame pressure the pore compressibility falls in the range between the compressibility of water and that of undersaturated crude oil.
In general, pore compressibility is found to be higher the lower the porosity. For a particular limestone reservoir pore compressibility and porosity could be related by means of a simple empirical formula. Results from the described study find a direct application in material balance calculations and in problems of liquid flow through porous media. Since the elastic constants of the rock bulk material enter into equations for velocity of acoustic waves, the results are also of importance for calculating rates of wave propagation in these media. It is shown for sandstones with 15 to 30 per cent porosity that laboratory measured porosities may differ from those under reservoir conditions by about 1 per cent of their value. The difference for low porosity limestones can be of the order of 10 per cent. The subsidence caused by elastic deformation of reservoir rock is shown to be very small.

Introduction
General formulas relating pore and bulk volume to external and internal pressure can be derived, as has been shown by Biot, Gassmann and Geertsma. Their theories describe the differential change in volume caused by a variation in pore fluid tension and external hydrostatic tension.
Transient Heat Conduction During Radial Movement of a Cylindrical Heat Source - Applications to the Thermal Recovery Process
Authors: Ramey H.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 115–122.

Abstract
A general solution is presented for the transient temperature distribution caused by radial movement of a cylindrical heat source through a homogeneous medium of infinite extent. This problem represents a highly simplified model of the movement of a combustion front during the thermal recovery of oil. Numerical solutions are presented for a heat source moving at a constant velocity, and a velocity inversely proportional to the radial location of the heat source.
Numerical solutions are presented for both finite and infinite vertical thickness of the heat source, i.e., with and without vertical heat losses. The numerical solutions are used to estimate the fuel concentration needed to maintain a combustion front during the thermal recovery of oil. The sensible heat carried to the combustion front by the injected gas stream is discussed in regard to the fuel concentration. Numerical solutions for a heat source (combustion front) of finite vertical thickness indicate the field conditions that may be necessary to sustain the temperature of a combustion front above the ignition temperature of the fuel over considerable distances from an injection well. The results also have implications in regard to the quantity of heat required during ignition.
The results of this computation apply to a highly idealized model of a thermal recovery process. But the results may be used as a guide in engineering consideration of the thermal recovery process.

Introduction
The thermal recovery of crude oil has received considerable attention since the publication by Kuhn and Koch of laboratory and field tests of this method of oil recovery. Other publications since that time have dealt with various features of the thermal recovery of oil and have illustrated the extremely complex nature of this process. Vogel and Krueger described an electric analog computer designed to solve a moving heat source problem which was analogous to movement of a combustion front during the thermal recovery of oil. The heat source was maintained at constant temperature and was a cylindrical source of infinite height (no vertical heat loss) moving radially at either constant velocity, or at a velocity inversely proportional to the radial location of the heat source.
Improved High Pressure Capillary Tube Viscometer
Authors: Eakin B.E. , Ellington R.T. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 85–91.

Abstract
An apparatus and a procedure for determining the viscosity behavior of hydrocarbons at pressures up to 10,000 psia and temperatures between 77 and 400°F are described. The equipment is suitable for measuring viscosity of either the liquid or vapor phases or the fluid above the two-phase envelope for systems exhibiting retrograde phenomena, according to the phase state of the system within these ranges of temperature and pressure. Equations are developed for calculation of viscosity from the experimental measurements, and new data for the viscosities of ethane and propane at 77°F are reported.

Introduction
With the advent of higher pressures and temperatures in industrial processes and deep petroleum and natural gas reservoirs, demand has increased for accurate values of physical properties of hydrocarbons under these conditions. Proportionately, more frequent occurrence of natural gas and condensate-type fluids is encountered as fluid hydrocarbons are discovered at greater depths. This increases the importance, to the reservoir engineer, of being able to predict accurately the physical properties of light hydrocarbon systems in the dense-gas and light-liquid phase states.
Reliable gas viscosity data are limited primarily to measurements made on pure components near ambient temperature and at low pressures. Few investigations have been reported for high pressures, and except for methane, data on light hydrocarbons are subject to question. This is demonstrated by the large discrepancy between sets of data on the same component reported by different investigators. For mixtures in the dense gas and light liquid regions and for fluids exhibiting retrograde behavior there are very few published experimental data.
Viscosity data for methane have been reported by Bicher and Katz, Sage and Lacey, Comings, et al, Golubev, and Carr, with good agreement among the last three sets of data. Comings, Golubev and Carr utilized capillary tube instruments for which the theory of fluid flow is well established. The theory permits calculation of the viscosity directly from the experimental data and dimensions of the instrument alone.
Observations Relating to the Wettability of Porous Rock
Authors: Amott Earl 
Published: February 2020

Published in Petroleum Transactions, AIME, Vol. 216, 1959, pages 156–162.Paper presented at Fall Meeting of Los Angeles Basin Section in Los Angeles, Calif., Oct. 16–17, 1958.

Abstract
A test is described in which the wettability of porous rock is measured as a function of the displacement properties of the rock-water-oil system. Four displacement operations are carried out:spontaneous displacement of water by oil,forced displacement of water by oil in the same system using a centrifuging procedure,spontaneous displacement of oil by water, andforced displacement of oil by water.
Ratios of the spontaneous displacement volumes to the total displacement volumes are used as wettability indices.Cores having clean mineral surfaces (strongly preferentially water-wet) show displacement-by-water ratios approaching 1.00 and displacement-by-oil ratios of zero. Cores which are strongly preferentially oil-wet give the reverse results. Neutral wettability cores show zero values for both ratios. Fresh cores from different oil reservoirs have shown wettabilities in this test covering almost the complete range of the test. However, most of the fresh California cores tested were slightly preferentially water-wet. The changes in core wettabilities, as indicated by this test, resulting from various core handling procedures were observed. In some cases the wettabilities of fresh cores were changed by drying or by extracting with toluene or dioxane; in other cases they were not changed. Contact of cores with filtrates from water-base drilling muds caused little change in wettability while contact with filtrates from oil-base muds decreased the preference of the cores for water. Using this test to evaluate wettability, a study was made of the correlation of wettability with waterflood oil recovery for outcrop Ohio sandstone and for Alundum. Results indicate that no single correlation between these factors applies to different porous rock systems. It is thought that differences in pore geometry result in differences in this correlation.
Acoustic Velocity in Porous Media
Authors: Berry James E. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 262–270.

Abstract
An evaluation is made of the acoustic velocity log for measurement of formation porosity. Plots of field-observed velocities vs core-measured porosities of sandstones and limestones with intergranular porosity show that the velocity log gives a useful measure of porosity, in agreement with published data. A new method of plotting electrical and velocity log data makes it easier to recognize hydrocarbon-water contacts from log data and to make semi-quantitative estimates of hydrocarbon saturation. Two examples of this interpretation technique are given. This paper also discusses the various factors that affect acoustic velocity and shows how corrections can be made for some of these factors.

Introduction
Although the continuous velocity log was developed primarily as an aid to seismic interpretation, it is finding widespread use for measurement of porosity. The purpose of this paper is to evaluate this use of the log. Results are presented for the velocity-porosity relationship in many sandstones and one limestone. Practical applications of porosity values derived from the velocity log to improve interpretation of electrical surveys are presented.
Various parameters which affect velocity in porous media are considered. Porosity, composition, cementation, pressure difference (overburden pressure minus fluid pressure), fluid saturation, and wettability are discussed. Some of the ideas are opinions based on general considerations of well logging problems while others are supported by published data and our own observations. Major conclusions from these studies are given in the body of the paper and detailed discussions of some of the various factors affecting porosity are given in the Appendix.

Porosity

Sandstones
The primary factor affecting the velocity of sound in porous media is porosity. Wyllie, et al, have reported a time average equation for the relationship between velocity and porosity. This has found considerable acceptance in the industry. Other relationships between velocity and porosity have been proposed, none of which are entirely satisfactory. It is doubtful that any one relationship will completely describe all situations.
Reservoir Heating by Hot Fluid Injection
Authors: Marx J.W. , Langenheim R.H. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 312–315.

Abstract
The injection of heat-bearing fluid may offer a wider application to secondary and tertiary recovery from conventional oil reservoirs than underground combustion since the process is more easily controlled and the reservoir requirements, in general, are less critical. In all cases, conduction heat losses to overburden and underburden will impose an economic limit upon the size of the area which can be swept out from any one injection point for any given set of conditions.
The present report describes a method for estimating thermal invasion rates, cumulative heated area, and theoretical economic limits for sustained hot-fluid injection at a constant rate into an idealized reservoir. Full allowance is made for non-productive reservoir heat losses.
Required solutions can be obtained directly from the numerical tables given here, as soon as all operating conditions are specified, without extensive mathematical manipulation on the part of the user.

Introduction
The injection of a heat-bearing fluid into a reservoir is frequently proposed as a means of secondary or tertiary oil production. This form of thermal recovery may offer a wider application to conventional oil reservoirs than underground combustion since the process is more easily controlled and the reservoir requirements, in general, are less critical. Because of its large gross heat capacity, steam appears to be the most efficient heat injection medium, although mixtures of steam and other gases, hot water, hot oil and hot non-condensable gases also have been employed.
Whatever the nature of the injection medium, economic evaluation of such thermal recovery processes will depend upon thermal invasion rates, or rates of productive reservoir heating, at any given time after the start of heat injection. In all cases, conduction heat losses to overburden and underburden will impose an economic limit upon the size of the area which can be swept out from any one injection point, for a given set of reservoir conditions, at any given heat injection rate.
The present report describes a method for estimating thermal invasion rates, cumulative heated area and theoretical economic limits for sustained heat injection at a constant rate into an idealized reservoir, making full allowance for non-productive reservoir heat losses. Required solutions can be obtained directly from the numerical tables given here, as soon as all operating conditions are specified, without extensive mathematical manipulation.