bluuebunny/crossref_metadata_2025_split huggingface dataset:
Spacing of Natural Gas Wells
Authors: Craze R.C. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 213–219.

Abstract
The discovery of a new gas reservoir demands that the planning of a sound well-spacing program be initiated early in the development stage. It is the purpose of this discussion to illustrate by actual field examples the application of basic well-spacing principles, previously developed for oil reservoirs, to the problem of well spacing in natural gas fields. These studies are presented for the field use of geologists and engineers who are concerned with the initial planning of the proper development of the newly discovered gas reservoir.

Introduction
The phenomenal growth of a vigorous natural gas industry emphasizes the increasing importance of natural gas as a source of energy, fuel, and raw materials to our nation's economy. Since 1945 marketed production of natural gas for the U.S. has increased 2½ times to a record high of 10.6 trillion cu ft during 1957. As major participants in the gas industry, we share an added interest to develop and produce our natural gas reserves with constantly improved efficiency.
The subject of well spacing is vitally important to the gas industry, for the well itself plays a significant role in the development of the natural gas reservoir and in control of the recovery process. Maximum utilization of wells is an integral part of sound conservation practices.
The discovery of a new gas reservoir demands that careful choice of well location and well spacing be made and that the planning of a sound well spacing program be initiated early on the development stage. With the drilling of the first development well, efforts of the geologist and engineer must be directed toward acquisition of adequate technical evidence upon which a firm recommendation for a spacing program may be based. With this technical appraisal as a foundation, operators and state regulatory agencies jointly can go far in providing a framework for sound development of gas fields to achieve a program of conservation that avoids the unnecessary well.
Generalized Newtonian (Pseudoplastic) Flow in Stationary Pipes and Annuli
Authors: Savins J.G. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 325–332.

Introduction
The first paper in this series outlined practical methods for applying the theory of steady-state flow of an ideal Bingham plastic liquid through a circular pipe and axially through a stationary concentric annulus to the engineering analysis of friction loss problems.
In the present paper the properties of another useful rheological model, the pseudoplastic generalized Newtonian liquid, are considered. The terminology applied to the rheological models is derived from the following classification of rheological models. The term "generalized Newtonian" is a class designation applied to models which do not have yield points but which exhibit a dependence on shear rate. The term "pseudoplastic" applies to a sub-group of models within this class which exhibit a decrease in "viscosity" with increasing shear rate. The term "power model" refers to a mathematical model proposed for describing the behavior of the pseudoplastic liquid. This model is of interest since certain of the salt saturated, oil emulsion, and "low solids" drilling fluids, inverted emulsion- and oil-base drilling fluids, aqueous gels, gelled crudes and blocking agents employed in hydraulic fracturing operations are of this type.
The present treatment considers the equations describing steady-state Poiseuille flow through a circular pipe and a stationary concentric annulus, and Couette flow between concentric rotating cylinders for a particular pseudoplastic model. As in the previous paper it is demonstrated how these equations can be applied to engineering calculations of friction losses. Graphical procedures for recovering the various flow curves and example calculations are included. A method for simplifying turbulent-flow correlations is also proposed.
Laboratory Studies of Five-Spot Waterflood Performance
Authors: Rapoport L.A. , Carpenter C.W. , Leas W.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 113–120.

Abstract
A program of scaled flow model experiments has been undertaken to study the performance of five-spot water floods. The modeling procedures are discussed and the construction and operation of the flow models are described. The tests were specifically designed to investigate the effects of injection rate and of oil-to-water viscosity ratio on oil recovery. The areal sweep of five-spot water floods was also studied, and direct comparisons between five-spot and linear flooding behavior have been established to permit better utilization of core analysis results for purposes of field waterflood evaluations.

Introduction
For a long time reservoir engineering procedures have been confined to the consideration of idealized, one-dimensional or linear systems. However, direct application of the linear waterflood mechanism to the evaluation of actual field performance is justifiable only for the purposes of rough approximation. To obtain a realistic analysis of field behavior, it is necessary to account for reservoir geometry and well distribution, and to take into consideration the configuration of the flow of fluids between injection and producing wells.
In the past it has been attempted to account for the complex nature of the fluid movement in the reservoir by associating each well pattern with a certain "sweep-efficiency constant", e.g., a sweep efficiency of 72 per cent for the conventional five-spot pattern. More recently, methods of waterflood evaluation have been improved by the introduction of variable sweep-efficiency factors, defining the areal coverage as a function of cumulative water injection and viscosity or "mobility" ratio. These variable sweep-efficiency factors, derived from miscible fluid displacement experiments, require the assumption of piston-like displacement of oil by water. This implies that only one fluid, either oil or water, is moving at anyone point of the reservoir at any moment.
A Laboratory Study of Oil Recovery by Solution Gas Drive
Authors: Handy L.L. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 310–315.

Introduction
Many differences can be imagined between gas-oil flow in which the gas is supplied at the face of the core and gas-oil flow in which the flowing gas was originally dissolved in the oil. If capillary pressure characteristics and flow requirements control gas saturation distribution, the gas would be expected to be located at preferred sites within the porous medium as determined by pore sizes. On the other hand, during solution gas drive the gas first appears as bubbles through a nucleation process. Nothing in self-nucleation theory specifies at which sites the first bubbles should be formed. In all probability they will be randomly distributed throughout the porous medium. Furthermore, it is not at all certain that even at low rates of production the gas will redistribute itself after nucleation to the channels normally occupied by gas in simple gas flow.
Stewart, et al, have shown that at least for some limestone samples, oil recoveries could not be predicted for all rates of production using anyone set of relative gas and oil permeabilities. An important factor in controlling recoveries during solution gas drive was the rate of bubble formation, higher rates giving higher recoveries. Stewart, et al, attributed the increase in recovery to a better distribution of the gas phase in heterogeneous limestone samples than is obtained by simple external gas drive. Differences in recovery from these causes were not reported for sandstone cores.
In the experiments to be reported here, oil recovery, pressure and producing GOR history were measured during solution gas drive for a 5-ft sandstone core. The results were compared with predictions from the Muskat method for computing solution gas-drive behavior using external gas-drive relative permeability. The effects of changing the rate of production and oil viscosity were studied.
At high laboratory rates of average pressure decline, two observations were made which would not have been predicted by Muskat's depletion theory:oil recovery increased with increasing rate of production for a given viscosity oil, andoil recovery increased with increasing oil viscosity for a given high rate of production.
Both of these observations are explained as consequences of diffusion control of gas saturations superimposed on the normal gas-oil flow requirements.
Streaming Potential and the SP Log
Authors: Gondouin M. , Scala C. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 170–179.

Abstract
Published laboratory data have established that very significant streaming potentials can exist across mud cakes subjected to pressure differentials such as exist between a mud column and formation fluids. Since shale is similar in kind and in properties to a well-formed mud cake, it appeared possible that streaming potentials might also arise across shales. A practical consequence would be that the streaming potential contribution to the SP would be smaller than might otherwise be assumed since the SP is measured with respect to the "shale base line". The resultant contribution would be the difference between the streaming potential across the shale and that across the mud cake.
In order to investigate this possibility, a laboratory apparatus was devised for measuring streaming potentials under pressure condition normally encountered in wells. Reported data on streaming potentials across mud cakes were verified. More important, appreciable streaming potentials were found across shale samples. As in the case of mud cakes, the shale potentials varied with the concentration and nature of the impregnating electrolyte. Dependence on pressure was in a different relation than that for mud cakes, possibly because of the lower compressibility of shales. The differences in streaming potentials between the shales and mud cakes were generally small, although they might vary considerably in practice depending on the relative electrokinetic properties of the particular shale-mud cake combination. A "poorly effective" shale with a "very effective mud cake" would produce the largest negative addition to the electrochemical component of the SP.Results of field experiments with pressurized wells were considered in the light of the laboratory results.

Introduction
Field experiments wherein the pressure of the mud column in a borehole was varied have often indicated the presence of a streaming potential, but its magnitude was not easily predictable and its sign sometimes changed from one formation to another in the same well. In the interpretation of SP logs from standard surveys, nevertheless, the correct value of Rw is very frequently obtained, within the limits of field accuracy, using only the simple electrochemical expression of the SP provided that proper corrections are made for bed thickness, ion activity, etc.
Departure Curves for the Self-Potential Log
Authors: Worthington A.E. , Meldau R.F. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 11–16.

Abstract
An analog computer study was made of the reduction of the magnitude of the SP by formation geometry and resistivity effects. Practical field situations were studied. The analog data were converted to the form of departure charts. These charts may be used to determine the reduction in the SP due to the above effects with good precision.

Introduction
Quantitative interpretation of the SP log in terms of formation water resistivity is presently based on the premise that the observed SP is equal to the electrochemical potential developed across a shale between the mud filtrate and the formation water. This procedure inherently assumes that, first, no electrokinetic (streaming) potential is present, and, second, that the SP is not reduced by resistivity or geometry effects in the formation.

The Analog Model
The analog model used for this study was the Guyod Analog Computer which originally was designed and built for resistivity log departure curve studies. It consists of a two-dimensional mesh of resistors, with the vertical mesh corresponding linearly to vertical distance along the borehole, and the horizontal mesh corresponding to radial distance from the borehole axis. By proper choice of horizontal resistor values, a three-dimensional, axially symmetric, borehole-formation problem can be modeled with this two-dimensional array. These and other details of the model are contained in a paper by H. Guyod.
The geometry used for the SP studies with the analog is depicted in Fig. 1. This configuration has a horizontal plane of symmetry, and, hence, the model, and the following discussion, need only to be concerned with one quadrant such as shown in Fig. 2. A further simplification arises by considering that both the natural potential sources and those used in the model have fixed internal impedance. Therefore, the current flows produced by these sources can be separated and studied independently (i.e., the superposition theorem can be applied).
The Cutting Carrying Capacity of Air at Pressures Above Atmospheric
Authors: Gray Kenneth E. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 180–185.

Abstract
The turbulent flow drag coefficients, or friction factors, have been experimentally determined for the cuttings normally encountered in drilling operations.
The gas law and average drag coefficients for characteristically flat particles (limestones and shales) and for angular to sub-rounded particles (sandstones) were used to extend Newton's equation to a more useful form. The resulting equations are expressions for the slip velocity of a particle as a function of the particle size and shape, the bottom-hole injection pressure, and the bottom-hole temperature.
The velocities necessary to lift actual rock cuttings as observed in the laboratory were compared with velocities predicted from the derived equations. Results indicate that there is no single correct circulating velocity and that the commonly used 3,000 ft/min linear velocity may be sufficient to lift only very small particles.

Introduction
A promising departure from rotary hydraulic drilling is air or gas drilling. In many instances the rate of penetration and bit life increases resulting from this method have been very substantial. Further the application of air drilling in areas of lost circulation or water sensitive pay zones has been highly successful.

Purpose
For the drilling contractor, the practical question remains, "How much air pressure and volume should I have?" It is necessary to have a reasonable knowledge of the air velocities and pressures required in air drilling operations for the proper design and most advantageous use of surface equipment and for adequate removal of cuttings from the borehole. Based on experience, most operators agree that at least 3,000 ft/min linear velocity is necessary for satisfactory hole cleaning.
It was the purpose of this investigation to evaluate the drag coefficients, or friction factors, for the cuttings normally encountered in drilling operations, i.e., sandstones, limestones and shales, and to utilize the values obtained to develop an expression for the minimum velocities and pressures (hence the volumes) necessary to lift these cuttings.
Use of Chemicals to Maintain Clear Water for Drilling
Authors: Gallus J.P. , Lummus J.L. , Fox J.E. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 70–75.

Abstract
Fresh water or brine drilling fluids may be kept free of suspended drilled solids by the addition of a water soluble acrylamide-carboxylic acid copolymer at the flowline. Addition of from .01 to 0.2 lb/bbl of the polymer solution to drilling fluids containing less than 5 per cent clay solids by weight causes the solids to flocculate and settle rapidly to the bottom of the pits. Solutions of the polymer injected at the pump suction reduce the loss of water to permeable formations without impairing the permeability to oil. The use of drilling fluids clarified with the polymer has resulted in increased drilling rates, extended bit life, and lower drilling fluid costs.

Introduction
Field experience and the results of a number of investigations have established that the accumulation of solids in drilling fluid reduces drilling rate. Drilling with water makes possible higher drilling rates than can be achieved with mud but in many areas drilling with water may not be feasible because of the possibility of encountering high formation pressures or hydratable formations. To combat these conditions, the drilling fluid must possess certain physical properties such as viscosity, density, fluid loss, etc., which require the presence of solids.
The current trend in drilling fluid treatment is to maintain as low a percentage of solids as is possible without harm fully affecting the mud properties needed for drilling. Mechanical separating devices such as wet cyclones and decanting-type centrifuges are proving to be an economical means of controlling the percentage of solids and thereby maintaining low solids muds. Also, special muds have been developed for the purpose of retarding the hydration of drilled solids so that they may be more easily removed by shale shakers or settling pits.
In some areas, such as West Texas, the characteristics of some formations will permit drilling with water. However, because of the dispersion of drilled solids, it is usually not possible to maintain clear water even with the aid of mechanical separators, or by utilizing large settling pits. For this reason the commonly used term "water drilling" is a misnomer since the water usually contains some solids.
Effect of Pressure on Rock Drillability
Authors: Eckel John R. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 1–6.

Abstract
A laboratory drilling rig has been devised and placed in operation which permits the application of hydrostatic, terrastatic, and formation pore pressures to a rock sample for drilling under controlled conditions. Calibrated tests of this equipment indicate qualitative agreement with field results oil the effect of weight on bit, rotary speed, and rate of circulation on drilling rate. Tests under pressure, using water and air as the drilling fluids, indicate that when drilling saturated limestone samples, a pressure differential between hydrostatic and formation pressure is the only pressure which affects drilling rate. A differential in either direction causes a reduction in rate, but the same differential from the wellbore into the formation causes the greater reduction. Also, in limestone, air favorably affected drilling rate only when compared to water at high hydrostatic pressure, all other conditions remaining constant. Large increases in drilling rate with air could be obtained in the laboratory only while drilling a shale, which offered a limited permeability to nitrogen and which could be drilled with a differential from the formation into the wellbore. In general, the magnitude of the changes due to the pressure effect were small coin pared to changes in drilling rate obtainable by changing either bit weight or rotary speed.
In the course of Humble's drilling research program, the desirability of investigating several factors which lend themselves to laboratory rather than field study became obvious. Principal reasons for this are the expense involved in field studies and the difficulty of exercising the required degree of control. Of primary importance are investigations of the effect of fluid properties on drilling rate, the effect of pressure on rock drillability, and a study of the fundamental mechanics of rock failure and chip generation.
Several years ago some work in the laboratory on the effect of mud properties on drilling rate was reported to the API, but the completion of this work and the investigation of the other variables affecting drilling rate required equipment somewhat more elaborate than that used on these earlier tests. This equipment has been assembled to form Humble's Drilling Engineering laboratory.
Comparison Between the Predicted and Actual Production History of a Condensate Reservoir
Authors: Rodgers J.K. , Harrison N.H. , Regier S. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 127–131.

Abstract
This paper presents comparisons of data obtained from a laboratory reservoir study and from a calculated behavior prediction with the actual production history of a condensate reservoir.
A small non-commercial discovery was depleted under closely controlled conditions and the well fluids were sampled at frequent intervals. Data on the reservoir and production variables were accumulated on a fixed schedule. A laboratory reservoir study was made using the initial well fluid samples as charging stock. The production procedures and operating conditions were held constant throughout the study wherever possible and in general paralleled the field work. The well fluid compositions and the cumulative recoveries as a function of the reservoir pressure were also calculated using conventional flash vaporization procedures and equilibrium constants.
Comparisons based on the composition of the well fluid show good agreement, the laboratory study agreeing within experimental accuracy with the field work and the calculated data comparing equally well. The gas-oil ratios are also in good agreement, but with somewhat greater deviations at the higher pressures.
In the over-all picture, it is believed that a model study can predict within experimental accuracy the production history of a condensate reservoir. Better equilibrium constants for the heavier hydrocarbons are needed in order to attain improved composition accuracy by calculation.

Introduction
In Aug., 1955, a gas condensate well was completed in San Juan County, Utah, that was initially thought capable of good commercial production. These conclusions were derived principally from core data and electric logs, which indicated good permeability, porosity and gas content. However, after the usual series of potential tests it was found that the reservoir pressure had declined some 22 per cent, and it was obvious that the zone tapped was but a small pocket or trap.
It became apparent that, with a controlled depletion of a small reservoir, a unique opportunity was available to compare laboratory and calculated studies with an actual field depletion and to further the present knowledge of condensate reservoirs.