bluuebunny/crossref_metadata_2025_split huggingface dataset:
Plastic Flow Properties of Drilling Fluids - Measurement and Application
Authors: Melrose J.C. , Lilienthal W.B. 
Published: April 2012

Abstract
The application of Bingham's law to the behavior of drilling fluids in arotational viscometer permits the expression of viscometric data in terms ofplastic viscosity and yield value, the flow properties of a plastic fluid. Acommercially available rotational viscometer is described, and when modified toa multispeed type viscometer, is shown to provide a simple and convenientinstrument for the measurement of these properties both in the laboratory andin the field. The data obtained are shown to be useful in defining andunderstanding mud control problems relating to chemical treatment and to thehydrodynamic behavior of muds.

Introduction
The highly complex drilling fluids which are required for deep drillingoften give rise to new and unusual mud control problems. Rapid and economicsolutions to these problems may require, on the one hand, better understandingof the changes which contaminants and chemical treating agents produce in thecolloidal and inert solids of the mud, or, on the other hand, closer control ofthe hydrodynamic behavior of the mud. The latter objective obviously can beachieved only if a correct rheological analysis of the flow behavior ofdrilling muds is available and if this is accompanied by the appropriaterheological measurements. The purpose of this paper is to describe suchmeasurements in the field, and to show how the resulting data can be of valuein solving difficult mud control problems.
It is now generally recognized that Bingham's law of plastic flow can beutilized in describing the hydrodynamic behavior of drilling fluids in thenon-turbulent flow range. Beck, Nuss, and Dunn have recently applied this lawto the flow of mud in small pipes, and Rogers has reviewed the rather extensiveliterature on this subject. So far, however, the use of Bingham's law has beenrestricted to the analysis of mud flow in pipes or capillary tubes, and it hasnot been directly applied to the flow in rotational viscometers. In the work tobe reported, the Reiner-Riwlin equation for the flow of a plastic fluid in arotational viscometer has been utilized to permit the expression of multispeedviscometric data in terms of plastic viscosity and yield value, the twoabsolute flow properties of a plastic fluid.
T.P. 3061
Relative Permeability Studies
Authors: Fatt I. , Dykstra H. 
Published: April 2012

Abstract
Relative wetting phase permeabilities calculated from capillarypressure-saturation data are compared with measured relative permeability data.The equation relating relative permeability to capillary pressure-saturationdata is derived by assuming that a porous medium is analogous to a bundle ofcapillary tubes. The equation includes a term to correct for the differencebetween fluid path length and length of core. Relative oil permeability data inthe water-oil-gas system are presented, and it is shown that if the water isconsidered part of the rock matrix, the relative oil permeability curve istypical of a wetting phase relative permeability curve. Apparatus for measuringtwo and three-phase relative permeabilities are described.

Introduction
The difficulty in measuring relative permeability of cores has made itdesirable to have a correlation between relative permeability and some moreeasily measured property of porous media. Such an easily measured property isthe capillary pressure-saturation relation.
In the past there has been a tendency to separate the capillary pressureconcept from the very complex pore geometry and to consider that the capillarypressure-saturation curve gives only some characteristic distribution ofinterfacial curvature between two fluids. Recently, however, it has beenrealized that if capillary pressure data are to yield information concerningpore size distribution and fluid flow in porous media, the pore must be assumedto have a simple shape such as a cylinder or a sphere.
Childs and George showed that relative water permeability could becalculated from the capillary pressure-water saturation curve by assuming thatthe pores are cylinders in which the fluid flowing obeys Poiseuille's Law, andthat the capillary pressure curve indicated the size and number of pores.Purcell derived an equation relating the permeability of a porous medium to thecapillary pressure curve by assuming the porous medium to be analogous to abundle of capillary tubes. Gates and Lietz calculated relative permeability byan equation derived from Purcell's equation.
In this paper an equation is derived giving the relative water permeability asa function of water saturation by assuming that the core sample can berepresented by a bundle of capillary tubes in which the fluid path length isnot the same as the bulk length, and in which the fluid path length varies withsaturation.
T.P. 3078
Phase Equilibria In Hydrocarbon-Water Systems IV - Vapor-Liquid Equilibrium Constants in the Methane-Water and Ethane-Water Systems
Authors: Culberson O.L. , McKetta J.J. 
Published: April 2012

Introduction
The equilibrium constants for methane and for water, and for ethane andwater have been calculated from experimental data for the two binary systems.These constants are for the two-phase systems for the temperature range of 100?to 340'F and the pressure range of 200 to 10,000 psia.
The constants for ethane are greater than those for methane. Equilibriumconstants for a natural gas from a natural gas-water system are about the sameas those for methane. Equilibrium constants for water in all three systems arevery nearly the same over the greater part of the range of temperatures andpressures studied.
In ideal solutions, the vapor-liquid equilibrium constants for a componentshould be the same in all such solutions at a given temperature and pressure.Few solutions are ideal, and consequently the use of generalized constantsoften leads to error in situations where they do not actually apply. Indecidedly non-ideal systems, it is desirable to have equilibrium constant datafor the specific system.
Vaporization equilibrium constants may be calculated either by thermodynamicmethods or from experimental vapor-liquid equilibrium data.
(Equation 1)
Equilibrium constants calculated from Equation (1) have been found to haveonly limited agreement with experimental values, even though the solutions forwhich they were calculated approached ideality. If the more volatile componentis at a temperature above its critical, the accuracy of the equilibriumconstant for the component is made more doubtful by the use of the vaporpressure term under such conditions. In order to make the thermodynamiccalculation on a component above its critical temperature, one must resort toone of the empirical methods of extrapolation of the vapor pressure toconditions above its critical point. Application of the thermodynamicequilibrium constant then to the methane-water or the ethane-water systemswould be risky since the systems are non-ideal, and the methane and ethane areabove their critical in most petroleum operations.
T.P. 3201
Measuring the Water Vapor Content of Gases Dehydrated by Triethylene Glycol
Authors: Politziner Irwin , Townsend F.M. , Reid L.S. 
Published: April 2012

Abstract
Recently published data indicate that the water vapor content of a gas, asdetermined by dew point measurement, is inaccurate when the gas has beendehydrated with diethylene glycol. Water vapor contents and dew pointmeasurements of gases dehydrated with triethylene glycol have been obtained inthis investigation in order to determine the magnitude of a similar error, ifone exists.
Experimental data show a very low concentration of triethylene glycol vaporin gases dehydrated at atmospheric temperatures and pressures ranging from 500to 2,500 psia, and that the accuracy of dew point measurements is not impairedby the presence of triethylene glycol vapor.

Introduction
Nearly all natural gas transported by pipe line to northern and easternmarkets must be dehydrated to a low residual moisture content in order toassure maximum transmission efficiency and continuous delivery under peak loadconditions. Without dehydration, water vapor often condenses in pipe lines inquantities sufficient to restrict the flow and, under low atmospherictemperature conditions, gas hydrates may form and plug gathering, transmissionand distribution facilities.
Gas may be dehydrated to pipe line specifications by a number of methods.The most widely used methods areadsorption of water vapor on a soliddessicant such as activated bauxite, alumina or silica gel,by absorptionof water vapor by either diethylene or triethylene glycol-water solutions ofhigh glycol concentration, andby simultaneous expansion-refrigeration ofvery high pressure gas in which gas hydrates are purposely formed and thenquickly decomposed.
Of these three fundamental methods, the adsorption andabsorption processes provide the bulk of the dehydrated gas moving to market atthe present time. The expansion-refrigeration process, a relatively newdevelopment, is gaining in favor because of its simplicity but is sharplylimited in its application by available differentials between source andgathering system pressures.
T.P. 3200
A New Technique for the Measurement of the Formation Factors and Resistivity Indices of Porous Media
Authors: Morgan F. , Wyllie M.R.J. , Fulton P.F. 
Published: April 2012

The importance of formation factor, F, not only in electric logging but as afundamental rock parameter has recently been stressed. The desirability ofinvestigating the range of variation of the resistivity index exponent, n, inthe relationship I = Sw-n, where I is the resistivity index and Sw the watersaturation as a fraction of the void volume of a porous medium, has also beenurged. The magnitude and variation of n with saturation and rock texture is asubject not only of theoretical interest but also one of prime importance inthe interpretation of electric logs.
A simple technique has recently been developed which enables both F and n tobe measured with high accuracy and which may also find acceptance as aconvenient method for the determination of irreducible saturation attainment inthe restored state method of core analysis.
Experience has taught that reproducible measurements of F are possible onlyif the resistance measuring electrodes are so arranged with respect to a planeface on a porous medium that they are able to make electrical contact withsubstantially all entry pores in that plane. In practice this may be achievedby using a platinized-platinum gauze electrode backed by some absorbentmaterial (such as felt) which has been saturated with a fluid identical withthat used to saturate the porous medium. Application of pressure to theelectrode and absorbent material then forces the gauze against the plane faceof the porous medium and simultaneously squeezes saline solution through themeshes of the gauze. By this means the electrode is in continuous aqueouscontact with all pores and satisfactory and reproducible low resistance contactwith the porous medium is achieved.
Clearly this method, although satisfactory for measurements of F, cannot beapplied to the making of continuous resistance measurements on a porous mediumwhile capillary pressure desaturation is being carried out. However, acceptingthe principle that for satisfactory results electrical contact must be madebetween a measuring electrode and all pores adjacent to that electrode, methodsof bringing electrodes into intimate contact with the surfaces of porous mediawere investigated.
T.N. 65
A Note on the Interrelationship Between Wetting and Nonwetting Phase Relative Permeability
Authors: Wyllie M.R.J. 
Published: April 2012

In a recent publication wetting phase relative permeability was expressedas:
(Equation 1)
and it was stated that a similar expression applied, mutatis mutandis, tonon-wetting phase relative permeability; i.e.,
(Equation 2)
In Equations (1) and (2), Sw and So are respectively the wetting andnon-wetting phase saturations as a fraction of the pore volume; Pc is thecapillary pressure; I, the wetting phase electrical resistivity index; IN, theanalogous non-wetting phase electrical resistivity index and Krw and Krnw, thewetting and non-wetting phase relative permeabilities.
Equation (3) is interesting because it expresses the nonwetting phaserelative permeability of a porous medium at any saturation as a function of thewetting phase relative permeability at that saturation, the saturation itselfand parameters which bear directly on the distribution within the pores of thenon-wetting and wetting phase fluid networks. It is thus inherentlyplausible.
Equation (3) is not readily checked against experimental data since fewreliable relative permeability figures have appeared in the literature; also nopublished information exists on the probable relationship between IN and So.However, if the Krw and Krnw figures of Leverett for unconsolidated sands areused in conjunction with the relationship I = Sw-2 for sands of this type, itis possible for Equation (3) to compute IN as a function of So. The results areshown in the accompanying figure and it will be seen that IN = So-1.72. Asynthetic sandstone for which Muskat quotes relative permeability data, alsogives a straight line plot between IN and So if I = Sw-1.8 is assumed. (Aresistivity index exponent of 1.8 appears to be the best average forconsolidated porous media.)
T.N. 93
The Quantitative Aspects of Electric Log Interpretation
Authors: Walstrom J.E. 
Published: April 2012

Abstract
While intensive research continues to promote a more complete understandingof the potential and resistivity measurements that comprise the electric log, it is believed that consideration should also be given to translating thesenumerous and often widely separated findings into a coordinated and readablebody of fundamental facts designed specifically for the petroleum engineer andgeologist. Although provision is made through publication for a ready exchangeof new theoretical concepts, it is also desirable to provide reviews andappraisals of the more established techniques and methods from the operatingstandpoint so that an economic and practical application may be realizedconcurrently with the theoretical progress. With these basic premises as aguide the author reviews the present state of electric log interpretation.
The paper is directed not so much to the logging or research specialist asto the petroleum engineer and geologist to whom the electric log is only one ofthe many tools which he employs. Frequently, these persons do not have the timeto follow in detail the many specialized contributions that appear and, as aconsequence, are not in a position to place these contributions in properrelation to each other, or to the art as a whole.
The paper reviews the basic steps in making quantitative determinations fromthe electric log of the amount of oil or gas present in subsurface formationsand also discusses the degree of reliability of these determinations undervarious conditions. The paper also indicates the trend of future developmentsin electric logging systems and methods of interpretation.

Introduction
The electric log has been used about 20 years as a means for studying theformations penetrated by a well bore. The first half of this period ischaracterized by the development of suitable logging techniques and equipment.Although progress in this direction is continuing at a satisfactory rate, thelast ten years are characterized more by an increasing interest in methods ofelectric log interpretation. During this period, a large number of fundamentalpapers have been published, expounding various logging techniques andparticular phases of the interpretation problem. Many of these papers representimportant contributions, and a few are classic.
T.P. 3280
Equilibrium Vaporization Ratios for Nitrogen, Methane, Carbon Dioxide, Ethane and Hydrogen Sulfide in Absorber Oil-Natural Gas and Crude Oil-Natural Gas Systems
Authors: Jacoby R.H. , Rzasa M.J. 
Published: April 2012

Abstract
Experimental equilibrium vaporization ratios (K values) were obtained fornitrogen, methane, carbon dioxide, ethane and hydrogen sulfide in two naturalgas-absorber oil mixtures and in two natural gas-Elk Basin crude oil mixtures.For each mixture of constant over-all composition, data were obtained at 100?,150? and 200'F and at various pressures in the range 200 to 5,000 psia. Someeffects of composition on the K values were obtained to serve as a guide inchoosing K's for engineering calculations on other mixtures.
The pressure cell used to obtain the data is a new type and is described herefor the first time.

Introduction
The phase equilibria of complex hydrocarbon mixtures such as natural gases, crude oils and their mixtures have been studied previously for the purpose offinding equilibrium vaporization ratios for the hydrocarbon constituents. In afew cases, such non-hydrocarbons as nitrogen, carbon dioxide, and hydrogensulfide were included in the mixtures studied because they occur in the fluidsobtained from petroleum reservoirs.
The increasing occurrence of these non-hydrocarbons and their growingeconomic importance, make it necessary to account for them more accurately inengineering calculations than is now possible using the meager publisheddata.
The available data for non-hydrocarbons may be classified into two groups:namely, binary mixtures of a hydrocarbon and a non-hydrocarbon, and mixturescontaining three or more components, only one of which is a non-hydrocarbon.Among the former, phase analyses are available for two nitrogen-HC mixtures, five carbon dioxide-HC mixtures and three hydrogen sulfide-HC mixtures. Datafor more complex mixtures are available as follows: Nitrogen-Methane-Pentane;Nitrogen-Methane-Hexane; Nitrogen-Methane-Heptane; Carbon dioxide-NaturalGas-Natural Gasoline; Carbon dioxide-Natural Gas-Crude Oil.
These data have been used generally for engineering calculations, often withlittle regard for their precise applicability because data for thenon-hydrocarbons in the complex mixtures being dealt with were not available.The use of K values from binary data for calculations involving complexmixtures is open to criticism because such K's are not a function ofcomposition and very often show large differences from the K's for the samecomponents in a complex mixture.
T.P. 3312
Analysis of Pressure Build-Up Data
Authors: Thomas G.B. 
Published: April 2012

Abstract
Several methods of analyzing pressure build-up data in wells have beenpresented by various authors. This paper reviews the theory and method of D. R.Horner and presents example calculations performed on data obtained by testingseveral different types of wells. These calculations include,graphicalestimation of final static pressure,determination of the productivecapacity of the pay away from the well bore and,the degree to which theformation adjacent to the well bore has been damaged by completion or othercauses.
The methods of testing and precautions which should be taken to assurethe best data possible are discussed. Limitations and reliability of calculatedresults are also treated.

Introduction
Pressure testing of wells is generally limited to the determination ofproducing and static mean formation pressures. The so-called "static" pressure determinations, along with PVT, electric log and production data, enable the reservoir engineer to determine, within reasonable limits, the drivemechanism of the reservoir and in some cases, the amount of edge waterencroachment. Producing pressure tests enable calculation of productivityindices and allow the engineer to plan the systematic production of a poolfor optimum conservation of subsurface energy.
The radial flow formula advanced by Muskat has been based on the assumptionof incompressible radial fluid flow. It has been known that reservoir fluids donot behave in an ideally incompressible manner. For example, incompressibleflow theory indicates a simple logarithmic relationship between the differenceof the instantaneous and static well pressures when plotted against time. Thelatter stages of this type of plot of pressure build-up data generally show amarked deviation from the earlier straight line trend, which deviation may beshown to be due to the compressible flow of fluids toward the well bore.Shut-in times of 24, 48, 72, or at most 96 hours are currently in wide use fordetermining so-called "static" reservoir pressure. Due to thecontinuation of compressible flow of fluids into the well bore long after thisarbitrarily taken shut-in time, the determination of static pressures hasalmost invariably resulted in lower than equilibrium values. Materials balancecalculations made early in the life of a reservoir often result in a calculatedreserve which later observations prove to be too low. Failure to obtainreliable "static" reservoir pressures within the prescribed 24 or48-hour build-up period has undoubtedly been a major factor in obtaining theselow estimates. Comparison of theoretical and actual productivity performance has indicated that formation damage and not being able to attaintrue static pressures have been partially responsible for the observeddiscrepancies.
T.P. 3542
Recent Laboratory Investigations of Water Flooding in California
Authors: Johnston Norris , Van Wingen N. 
Published: April 2012

Abstract
Laboratory flood pot testing of California sands has progressed to aconsiderable extent in the past 18 months. Flood evaluations have been carriedout on over 200 large core samples. Many of these were heavy oil sands of highpermeability and completely unconsolidated in nature. The oil frequently formeda bank, though some of the oil was recovered in the subordinate phase of theflood, by viscous drag. Flood pot recoveries as high as 1400 bbl/ acre ft havebeen recorded. Reservoir analysis suggests a conformance factor of 0.4 toreduce laboratory recovery to probable field practice. Oils with viscosities upto 1800 cp have been successfully handled in flood pot evaluations. Theshallow, loose sands are not well adapted to the application of high pressuresto offset the high viscosities.

Introduction
Secondary recovery may be said to have started 60 years ago when accidentalfloods occurred in the Bradford sand in Pennsylvania; About 1921 artificiallyconducted water drives came into extensive use and since that time the greatBradford field has been almost completely subjected to water flooding. Duringthe last 30 years, most of the known medium and deeper production in Californiahas been discovered and is being exploited by primary recovery methodssupplemented in some instances by high pressure gas injection. The Californiaarea is just beginning to feel the need for secondary recovery in view of anunprecedented market demand and the rapidly rising cost of new pooldiscoveries.
With the presently recognized desirability of secondary recovery inCalifornia, there must also be appreciated a number of serious differencesbetween the water flooding problems here as compared to the territory east ofthe Rockies. California sands are generally thicker, and are frequently softand argillaceous. The oils are often heavier and asphaltic. Much of the oil isbelow 15?API, occurs at shallow depth, is cool and free from appreciabledissolved gas, which results in relatively high reservoir oil viscosity.Secondary recovery is particularly beneficial where primary recovery has beenpoor and where no natural water drive exists. These conditions applyparticularly to the heavy, shallow, clean production from soft, oftenargillaceous California sands so abundantly found at depths less than 1500feet. Often, too, there is a totally insufficient supply of water ofsatisfactory quality to inject at a reasonable cost. Also, the crude oils arepriced far below the premium Bradford crude.
T.P. 3640