bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracturing - Fracture Flow Capacity vs Well Productivity
Authors: van Poollen H.K. , Tinsley John M. , Saunders Calvin D. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 91–95.

Abstract
In the past few years much consideration has been given to the evaluation of the effect of hydraulic fracturing on the productivity of wells. Generally, these studies included the evaluation of fracturing materials, fracture extension and formation damage due to the use of various fracturing fluids. Only little consideration has been given to the characteristics, and in particular the flow capacity, of the fracture itself and its effect on well productivity.
This paper presents the results of laboratory investigations pointed toward the evaluation of the efficiency of various fractures with special emphasis on the flow capacity of these fractures. Data presented in this paper are the results of both an electrical model study and physical testing. Under consideration are (1) effect of overflush, (2) premature production of well after treatment,(3) "tailing-in" with coarse sand near the end of the treatment,(4) effect of propping agent size and concentration, (5) reduction in effective fracture permeability caused by formation caused by formation fines, silt and clays, and (6) effect of various fluids on formation strength and competency.
The results of this investigation indicate that the flow capacity of a fracture is affected by any or all of the various parameters mentioned above. The authors believe that a better understanding and utilization of these factors should result in more efficient formation fracturing.

Introduction
Hydraulic fracturing has become almost a standard practice of many companies for stimulating production from old and new wells. Although most companies utilize this service, techniques of application vary widely between companies and areas.
Probably too often when a well in an area responds favorably to a particular technique all future wells in the same area are treated in a similar manner. Possibly a modification of the technique would result in a further production increase. Variables, of which many are extremely difficult to evaluate from field results, hamper the selection of procedure changes.
Properties of Cementing Compositions at Elevated Temperatures and Pressure
Authors: Carter Greg , Smith Dwight K. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 20–27.

Abstract
Studies have been conducted on the properties of many deep well cementing compositions to determine their strength behavior over curing periods to 180 days at elevated temperatures and 3,000 psi pressure. This pressure results in essentially the same compressive strength as that obtained with much higher pressures in accordance with the findings of an API subcommittee. These different compositions include API Classes A, E, and F cements containing additives such as retarders, bentonite, heavy weight materials and pozzolans. All compositions except mixtures of pozzolans and hydrated lime show from mild to severe degrees of strength loss over a temperature range from 230 to 320°F after setting. Pozzolan-lime compositions actually gain in strength with time at these high temperatures.
Other chemical and physical properties evaluated to observe their interrelationship with strength loss show very little correlation except in permeability. As retrogression in strength Increases, the permeability of set cement increases. X-ray diffraction patterns on the set products indicate the formation of certain compounds having little or no strength value in those cementing compositions where strength loss was more severe.

Introduction
As a result of the growing trend toward deep well completions, a study has been made on the properties of the various cementing slurries presently in use at elevated temperatures and pressure. The strength of these compositions is of prime importance in selecting the most suitable material for use at high temperatures, to determine WOC time and the proper time to perforate with a minimum of shattering. Of primary interest in this investigation was the strength behavior of various compositions currently in use, and the effect of additives on cement after long periods of curing under severe conditions.
Earlier investigators have pointed out that the strength of some cements will increase with increasing curing temperature to about 220 to 240°F, but at higher temperatures a loss in strength occurs at extended time intervals. Studies by the API Mid-Continent District Study Committee on Oil Well Cements outlined a testing procedure whereby field conditions of temperature and pressure could be simulated in the laboratory. It was observed that retarded cements undergo changes at elevated temperatures and some lose as much as 50 per cent of their early strength when cured at high temperatures. The scope of these tests was limited to curing periods of 1 to 28 days; additives were not covered in this study.
Determination of Wettability by Dye Adsorption
Authors: Holbrook O.C. , Bernard George G. 
Published: February 2020

Published in Petroleum Transactions, AIME, Vol. 213, 1958, pages 261–264. Paper presented at 32nd Annual Fall Meeting of Society of Petroleum Engineers in Dallas, Tex., Oct. 6–9, 1957.

Abstract
A method has been developed for determining the relative water wettability (fraction of the surface wet by water) of porous media. This method involves the adsorption of methylene blue dye from an aqueous solution onto the solid surfaces of rock contacted by the injected dye solution. Experiments on Berea sandstone cores have shown that water-wet cores adsorb a large amount of dye from solution. In oil-wet cores, however, the injected aqueous dye solution is prevented from contacting the adsorptive surfaces by a film of oil and virtually no dye is adsorbed.
This method was tested by experiments on mixtures of water-wet and oil-wet sand. Using the dye adsorption method, it was possible to determine quantitatively the fraction of water-wet and oil-wet sand in such mixtures.
The dye adsorption test is readily applied to determining the relative water wettability of fresh oilfield cores. The cores are not extracted before testing. Observed values of the wettability of field cores tested to date have varied from 100 to 6 percent water wet.
Miscible Fluid Displacement in Porous Media
Authors: Lacey James W. , Draper Arthur L. , Binder George G. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 76–79.

Abstract
An experimental investigation of miscible fluid displacement has been made in linear porous media under highly adverse mobility ratio conditions. Various refined oils were displaced at field rates by liquid propane in both horizontal and vertical models 9 to 36 ft in length.
In horizontal tests, mixed zones or transition zones form between the two liquids early in the displacements. Initially, the zones grow rapidly. In 2-in. diameter models, the mixed regions become nearly stable zones from 6- to 20-ft long. From then on these quasi-stable zones apparently grow only by molecular diffusion.
The lengths of the quasi-stable zones appear to be almost independent of the core material in which displacements are made and increase with increasing rates of injection and oil/solvent viscosity ratios. The lengths of the quasi-stable zones measured in 2-in. diameter models at viscosity ratios and injection rates anticipated in the field indicate that essentially piston-like displacements of oil by solvent would occur. However, the mixed zone lengths increase markedly as the model diameter increases.
In vertical displacements controlled by gravity drainage, only short transition zones form. The entire lengths of these zones can be accounted for by molecular diffusion. Therefore, in reservoirs having characteristics allowing a high degree of gravity drainage, nearly complete oil recovery should be attainable by miscible fluid displacement.

Introduction
The oil industry is faced with an ever increasing cost for finding new oil reservoirs. This, coupled with the fact that conventional methods of oil recovery usually leave from 1 to 3 bbl of oil in the ground for every barrel produced, has aroused considerable interest in developing more efficient methods. An integral part of the mechanism of many of these new methods of recovery is a miscible fluid displacement in which oil is displaced by a much less viscous material such as liquid propane. A number of investigators have explored the mechanics of miscible fluid displacement but in the experiments reported many of the important factors have been varied only over a limited range far removed from normal oilfield values.
This paper presents the results of an experimental study of oil displacement by liquid propane at field rates from linear, natural-sandstone models of various sizes. Both horizontal and vertical flow tests were made.
The Deterioration of Miscible Zones in Porous Media
Authors: Sievert John A. , Dew John N. , Conley Francis R. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 228–235.

Abstract
Recent literature shows that pronounced increases in oil recovery can result from the use of miscible systems in recovery operations. This literature also points out certain problems associated with maintaining miscibility, e.g., compositional changes resulting from alterations in pressure and temperature or from zone dilution. The purpose of the work described in this paper was to study miscible zones for possible use in waterflooding operations and examine the manner in which these zones break down. The fluid system selected for study was oil - tertiary-butyl alcohol - water, which, because of its narrow range of miscibility, is ideally suited for investigation in short, linear systems.
The laboratory-observed effects on oil recovery and zone stability of a number of variables are reported. Among the variables investigated were miscible zone size, viscosity ratio, length of travel, and interstitial water saturation.
Results obtained with this system show that interstitial water adversely affects recoveries because of premature phase break. Salinity of the water further aggravates this situation. This effect, although pronounced for this system, would probably occur in any fluid system containing an alcohol. As expected, viscosity ratio has a decided influence on recovery efficiency and zone stability. The results also show that use of a sufficient zone size, even though the system has poor phase characteristics, yields higher oil recoveries than are obtained from straight water floods. Length-of-travel studies showed a square root relationship between zone growth and path length for favorable viscosity ratios. No such clear-cut dependence was observed under unfavorable viscosity conditions.

Introduction
As new oil reserves have become increasingly more difficult and expensive to find and develop, the oil industry has devoted more and more time and money to finding more efficient methods for exploiting known reserves. The increasing number of water floods is one manifestation of this attempt to improve oil recoveries from existing fields. Since considerable quantities of oil are by-passed by the waterflood process, it is only a partial answer to the problem. The search continues.
Miscible Displacements of Reservoir Oil Using Flue Gas
Authors: Koch H.A. , Hutchinson C.A. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 7–10.

Summary
Miscible phase displacement of oil from reservoirs has been emphasized in the past few years. The reason for this emphasis lies in the high oil recovery attainable by this process. Removal of capillary effects in the reservoir leads to recoveries approaching 100 per cent in the area contacted by the miscible phase.
The miscible slug process is one means of obtaining a miscible displacement. Here a band or slug of LPG is injected into the reservoir prior to gas injection. The idea is to maintain the band of LPG "wedged" between the gas and oil phases and thus achieve a miscible phase displacement. A second method for achieving miscibility is through the injection of a gas which is not miscible with the reservoir fluid but which develops a zone of miscibility in the reservoir through mass transfer with the reservoir oil. This mass transfer results in either an enrichment of the lean injected gas by intermediates from the oil or an enrichment of the oil by intermediates from a rich injection gas or one that has been enriched on the surface by LPG addition. We are interested here in discussing the process in which miscibility is developed at the displacement front by the evaporation of intermediates from the oil phase into the gas phase. This process "builds up" its own slug of miscible material at the displacement front and therefore does not require the injection of LPG to obtain miscibility. Each process has its own area of applicability. Generally, the high pressure gas process is applicable only with reservoir fluids which contain a high concentration of intermediates. If the high pressure gas process is technically feasible at pressures less than 4,500 psi, it is probably more desirable economically than the slug process. The slug process has broad applicability in the shallower reservoirs and with reservoir fluids which contain a relatively low concentration of LPG and natural gasoline constituents.
This paper deals with some new concepts of the high pressure gas injection process where it is proposed that flue gas can be substituted for hydrocarbon gas without sacrificing our goal of miscibility.
Fluid Dynamics During an Underground Combustion Process
Authors: Wilson L.A. , Wygal R.J. , Reed D.W. , Gergins R.L. , Henderson J.H. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 146–154.

Abstract
This paper presents a method of predicting the production history of an underground combustion recovery process. A rigorous solution of the thermodynamics and hydrodynamics involved is beyond the scope of this report. However, a practical scheme to appraise combustion recovery performance has been worked out. By prudent assumptions, regarding the attainment of steady-state conditions, a trial-and-error solution, which satisfies both material balance and three-phase relative permeability requirements has been evolved and tested.
As a combustion zone moves through a formation the interstitial water, the water of combustion and a portion of the oil will be vaporized. These vapors will move downstream to a cooler region of the formation where they will condense. Part of the remaining oil will be displaced by the imposed gas drive and what remains behind will be consumed as fuel. The fluids will distribute themselves downstream in a manner which will satisfy the three-phase relative permeability characteristics of the formation. Three distinct zones will exist ahead of the combustion zone:a zone termed a water bank which contains three mobile phases, oil, water and gas;a region containing two mobile phases, oil and gas, called the oil bank; anda zone having the fluid saturation distribution which existed prior to combustion.
The mobile water will impose a water flood on the oil in the region containing three flowing phases. The process can be visualized as a simultaneous water flood and combustion-supported gas drive. It is possible to estimate the saturation distributions in the water bank and oil bank as well as the production history for any combustion temperature if the porosity, three-phase relative permeability characteristics, oil viscosity and initial saturations are known. This has been done for injection pressures ranging from 1 to 100 atm, oil viscosities of 10 to 1,000 cp and porosities from 20 to 40 per cent. Several of these calculations have been checked in the laboratory, with the result indicating rather good agreement between the predicted and observed production histories.
The analytical and experimental techniques are described and the comparison of predicted and observed performance presented.
Extensions of the Muskat Depletion Performance Equation
Authors: West R.D. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 285–291.

Abstract
Muskat's depletion performance equation is here derived considering the expansion behavior of the reservoir hydrocarbon system and a simple fractional-flow equation. This method of derivation leads logically to the two extensions that follow. The first of these is concerned with gravity segregation in a depletion-drive reservoir. The second is concerned with including an empirically determined term for water influx in the performance equation. The more general equation for gravity segregation when there is a primary gas cap and empirically-determined water influx is stated for completeness. These equations have been found useful in reservoir performance calculations in Eastern Venezuela.
A discussion on the methods of solving these equations follows, and considers firstly the effect of taking finite intervals in the numerical integration, and secondly, methods of incorporating the time functions involved in segregation in with the expansion behavior. The paper concludes with a brief general discussion on further extensions to the depletion performance equation.

Introduction
The two fundamental sources of energy by which oil is produced from a reservoir result from pressure depletion inside the boundaries of the reservoir and fluid encroachment across the boundaries of the reservoir. The wells in either case form low pressure outlets through which oil and gas may be produced by the expansive force of the reservoir fluids and associated encroaching fluids.
When the reservoir pressure is higher than the bubble-point pressure of the oil, so that there is no free gas in the reservoir, these expansive forces are the only ones available for the production of oil. However, when the reservoir pressure is less than the bubble-point pressure of the oil, free gas is vaporized as the pressure falls. With both oil and free-gas phases present, the additional forces of gravity and capillarity may operate on the gas-oil system, as they have previously operated on the oil-interstitial water system. Gravity tends to segregate the free gas from the oil due to their density difference. Capillarity opposes and eventually balances gravity as the more extreme free gas and oil saturations are reached, preventing the independent movement of free gas until it is above a certain saturation, and the independent movement of oil when it is below a certain saturation.
Reservoir Analysis for Pressure Maintenance Operations Based on Complete Segregation of Mobile Fluids
Authors: Martin John C. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 220–227.

Abstract
A brief review is presented of the past performance of a number of large, thin, highly permeable reservoirs with low dips in the Bolivar Coastal fields of Venezuela. The performance of these reservoirs indicates that the fluids are segregated vertically within the sand section by gravity. With this assumption, equations are developed which describe the performance under pressure maintenance operations. Methods of solving these equations and results of simple example calculations are presented.
Example calculations indicate that under pressure maintenance conditions injected gas tends to flow preferentially along the top of the sands and that encroaching water has a tendency to flow preferentially along the bottom. The expected performance of segregated fluids is discussed and compared with that of fluids which are uniformly distributed in any sand section.

Introduction
The field performance of a number of reservoirs described herein indicates that the fluids are segregated vertically within the sand section by the force of gravity. Thus, it was felt that any method used to predict the future performance of these reservoirs should consider the effects of segregation in the sand sections. A study of the available information on some of the reservoirs suggests that increased recoveries may be expected if the reservoir pressure is maintained by either crestal gas injection or flank water injection.
To predict future performance of reservoirs under pressure maintenance operations, a method of analysis was needed which would account for segregation of fluids in the sand sections. Several methods of analysis have been developed to take into account the segregation of fluids in the reservoir as a whole. To our knowledge no method considers segregation of the fluids within sand sections in the manner indicated by the past performance of several reservoirs in the Maracaibo Basin. This paper outlines part of the work done in studying some of these reservoirs and contains a description of their performance characteristics. The analysis presented is restricted to pressure maintenance conditions, since space limitations prevent a full discussion of the development of the mathematical relations and the various methods of solving them. Only a sketch of the development of the mathematical relations is given. The various methods of solving these relations are pointed out, but the actual determination of solutions to various problems are omitted except for one example. It is felt that these results may aid in the study of reservoirs outside the Maracaibo Basin.
Calculation of Linear Waterflood Behavior Including the Effects of Capillary Pressure
Authors: Douglas Jim , Blair P.M. , Wagner R.J. 
Published: February 2020

Published in Petroleum Transactions, AIME, Vol. 213, 1958, pages 96–102.Paper presented at 32nd Annual Fall Meeting of SPE in Dallas, Texas, Oct. 6–9, 1957.

ABSTRACT
The calculation of the behavior of an oil reservoir during a water flood has long been an important problem to reservoir engineers. Buckley and Leverett derived the differential equation which describes the displacement of oil from a linear porous medium by an immiscible fluid, but this equation could not be solved by the methods of classic mathematics. Consequently, in order to integrate the equation over the length of the reservoir, they neglected the effects of capillary pressure.
In the present paper, a numerical method has been developed for determining the behavior of a linear water flood with the inclusion of capillary pressure. The differential equation which was derived for the case of incompressible fluids is second order and non-linear. This differential equation was approximated by an implicit form of difference equation which is second order correct in both time and distance. An electronic digital computer was used to perform the numerical solution of the difference equation.

INTRODUCTION
The problem of calculating the flow and distribution of fluids in an oil reservoir subjected to a water flood has long challenged the reservoir engineer. The ability to solve this problem would provide a valuable tool for the design and study of field waterflooding programs. One of the first contributions in this field was made by Buckley and Leverett, who developed a method of calculating waterflood performance in a linear reservoir. Their technique was limited by the practical necessity of excluding quantitative consideration of capillary pressure. It is the purpose of this paper to describe a method for calculating the behavior of a linear water flood with capillary pressure considered. This method, although limited to the linear case, should serve as a step toward the solution of the two- or three-dimensional waterflooding problem which would better describe actual reservoirs.