bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measurement of Capillary Pressures in Small Core Samples
Authors: Hassler G.L. , Brunner E. 
Published: June 2014

Abstract
An apparatus and method is described whereby the relation between saturationand capillary pressure under decreasing saturation can be quickly determinedfor small core samples. The initially saturated core is centrifuged atincreasing rates and the average saturation is measured at each rate with theaid of a stroboscope device. A theory and calculation procedure is givenwhereby the accelerations and saturation values can be converted into a truecurve of capillary pressure versus saturation.
The present work differs from previously described use of the centrifuge toobtain capillary-pressure curves of core samples' in that the core iscentrifuged alone, so that the whole range of saturations required by theproperties of the sample and the radially varying centrifugal force occurswithin the sample. The calculation procedure nevertheless secures correctresults from simply obtained values of the average saturation.
The apparatus described was developed in connection with studies of capillarypressure and wetting of oil-field rocks, and the paper provides the apparatusbackground for a previous publication dealing more fully with the uses andimplications of the data in petroleum engineering. The method is applicable, however, to general combinations of immiscible fluids and porous or comminutedsolids, and may be useful in other fields.

Introduction
The importance of capillary phenomena in determining the behavior of liquids inporous media has long been recognized. The concept of capillary pressure wasearly formulated, and in recent years discussions of the application of thelaws of capillarity to oil field problems have appeared. One reason whyprogress in the application of capillary phenomena to the solution of problemsof reservoir mechanics has not been more rapid has been the lack of asatisfactory technique for measuring the capillary pressures in reservoirrocks. It is the principal purpose of this paper to describe a method by whichthe relation between capillary pressure and saturation can be determined forsmall consolidated core samples which have been extracted andresaturated.

Capillary Diaphragm
Perhaps the most direct way to measure the capillary pressure in a rock is tomake piezometric contact with the wetting liquid through a diaphragm of porousmaterial with high displacement pressure saturated with the liquid in question.The liquid in the diaphragm assumes the pressure of the liquid in the core, which can then be measured with a manometer, while the atmospheric air isprevented by capillarity from entering the diaphragm and affecting the pressuremeasurements as long as the displacement pressure of the diaphragm is notexceeded.
T.P. 1817
An Analysis of Material-balance Calculations
Authors: Woods Rex W. , Muskat Morris 
Published: June 2014

Abstract
A least-square analysis procedure has been developed and applied for the studyof the deviations in estimations of oil in place as given by thematerial-balance equations. The data used were those obtained from fieldobservations on the Jones sand in the Schuler pool, Arkansas, and the Monroedolomite in the Reed City pool, Michigan. Possible effects of water intrusionwere taken into account by expressing the cumulative water influx in terms ofvarious functions previously proposed in the literature. Formulas weredeveloped and values calculated for the minimum deviations and minimalpercentage deviations in the calculated volumes of oil in place from theaverage values, as could be obtained by suitable choice of the waterencroachment and initial gas-cap volume parameters.
The results show that the fluctuations in these calculated volumes are veryinsensitive to the values chosen for the rate of water intrusion and initialgas-cap volume, and hence cannot be safely used in discriminating betweenspurious values for these parameters and such as actually pertain to theproducing reservoirs. Moreover, the exact form of the water-intrusion functionseems to have but little effect on the fluctuations in the computed oil inplace.
Accordingly, it is concluded that the material-balance method does not ofitself provide a satisfactory criterion for determining the basic physicalunknowns of producing reservoirs or in making conclusive decisions regardingthe production mechanism, unless independently established geological controldata are available for eliminating unreasonable values for the reservoirparameters, even though they may still satisfy the material-balance formulas.If, however, from core or logging data the initial oil in place and the gas-capvolume can be established in advance, the material-balance formulas can beinverted to find the water intrusion. Moreover, by determining by suchcalculations the water-intrusion coefficient, the future production performancecan then be predicted by the aid of the material-balance formulas for specifiedoperating conditions. This type of application may be of particular value inpredicting the results of pressure maintenance operations.

Introduction
The evaluation of the forces acting upon an oil reservoir is a problem ofconsiderable interest to the operator as an aid in determining the propermethod of operation for the reservoir to obtain an optimum recovery of oil. Inmany pools, the nature and magnitude of the forces acting upon the reservoirremain unknown until an appreciable amount of ultimate recovery is obtained. Tobe of value to the operator, a reliable interpretation of reservoir performanceshould be available in the early life of the pool to permit an optimum plan ofoperation. Progress has been made in an understanding of reservoir behaviorand. the importance of the different factors involved. The material-balancemethod of estimating oil in place has been proposed as a tool in analyzingreservoir-performance problems.
T.P. 1780
Experimental Determinations of Water Vapor Content of a Natural Gas Up to 2000 Pounds Pressure
Authors: Russell George F. , Thompson Robert , Vance Frank P. , Huntington R.L. 
Published: June 2014

Abstract
With the advent of higher pressures in the operation of natural-gastransmission lines, the removal of water vapor from the gas has becomeincreasingly important in order to prevent condensation or formation of gashydrate from slowing down or stopping the flow of gas. Intelligent design ofthese dehydration or gas-drying plants has been hampered through the lack ofexperimental data on the water vapor content of natural gas at elevatedpressures. In view of this need, this present investigation was sponsored bythe Southern Natural Gas Co. in the Chemical Engineering laboratories at theUniversity of Oklahoma Research Institute. Experimental results were obtainedon the water-vapor content of natural gas up to 2000 lb. per sq. in. atatmospheric temperatures. The water content at 2000 lb. is approximately twothirds as much as it is at 1000 lb. Deviations from the ideal gas laws varydirectly with pressure and indirectly with temperature.

Introduction
The removal of water vapor from natural gas is an important operation inconnection with the production and transportation of this commoditybecause:Liquid water accelerates internal corrosion of a pipe line.Accumulation of water at low points in a pipe line reduces markedly itscapacity.Gas hydrates, icy snowlike growths, form readily under high pressure in thepresence of the lower hydrocarbons and water, often plugging up the pipeline.
In order to design dehydration plants for stripping the gas of its watercontent, it is essential that the engineer have a knowledge of the saturated orequilibrium water vapor content of the gas to be processed. With the gradualincrease of operating pressures around gas-producing wells and pipe lines, itwas observed that the quantity of water recovered from dehydration plants orcondensed in colder lines was considerably greater than had been expected fromcalculated contents, based on vapor-pressure data taken from steamtables.
This observation prompted a number of investigators, for instance, Laulhere, Deaton, and Hammerschmidt to carry out experimental work at pressures up to 600lb. per sq. in. in order to determine quantitatively the water content ofvarious gases. Sage, Lacey, et a1.4?6 have recognized more recently the needfor such data at higher pressures, but their work was done at temperatures of100'F. and higher. Since hydrate formation usually, if not entirely, occurs attemperatures below 100'F., the present investigation was confined to the lowertemperature range at pressures from 600 to 2000 lb. per sq. in. gauge.
T.P. 1792
Laboratory Investigations of Chemical Changes in East Texas Oil-field Water Affecting its Injection into Subsurface Sands
Authors: Plummer F.B. , Walling I.W. 
Published: June 2014

Abstract
Bastin and others have demonstrated the presence of sulphate-reducing bacteriain oil wells producing salt water. Analyses show that at 125?F bacteria alonereduce sulphates in East Texas salt water by only 3 per cent in 30 days, forming principally hydrogen sulphide and sodium or calcium hydroxide. Thehydrogen sulphide reacts with soluble iron compounds to produce iron sulphidein the absence of oxygen, and ferric hydroxide where oxygen and air arepresent. Where iron or other metals and iron sulphide are already in the watercontaining bacteria, 100 per cent reduction of the sulphates is complete in 30days or less; where magnesium is present, reduction is complete in 15 days. Theeffects of changes in temperature, of different bactericides, and ofconcentration of bactericides on sulphate reduction are described in detail andillustrated by tables and curves. The significance of sulphate reduction oncorrosive properties of oil-field water is briefly discussed.
Chemistry of East Texas Oil-Field Water
The chemical composition of the water in the East Texas field salt-waterdisposal pits is shown in Table I.
This salt water corrodes pipes, pumps, and steel tanks excessively, principallybecause of its content of oxygen, hydrogen, sulphide, and carbonic acid. Thecarbonates in the water when exposed to air tend to give up carbon dioxide andto precipitate calcium carbonate in large quantities.
This forms coatings in tanks, settling pits, and ditches, and soon, unlessremoved by acid treatment, will effectively clog an injection well and reducethe flow of water back into the ground. The iron compounds in the water, mostof which are dissolved from tanks and pipes, are in the ferrous form, and whenexposed to the air are oxidized from soluble ferrous carbonate to insolubleferric hydroxide, resulting in the precipitation of a gelatinous precipitatethat will clog oil-field sands effectively.
The sulphates in strong sulphate-bearing water may be attacked by swarms ofsulphate-reducing bacteria and more hydrogen sulphide may be produced. Thehydrogen sulphide reacts with soluble minerals in the water to form blacksludges. A knowledge of the chemistry of each reaction in oil-field water isimportant to the oil-field engineer, since means must be devised to prevent theformation of harmful precipitates that clog injection wells and to preventcorrosion of tanks by harmful products of biochemical processes.
T.P. 2019
Effect of Reservoir Fluid and Rock Characteristics on Production Histories of Gas-drive Reservoirs
Authors: Muskat M. , Taylor M.O. 
Published: June 2014

Abstract
Theoretical calculations have been made on the performance to be expected of gas-drive reservoirs for various characteristics of the oil and gas and the producing rock. Such performance has been expressed graphically as curves for the reservoir pressure and gas-oil ratios of the production as functions of the cumulative oil recovery. The latter has been expressed in terms of percentage of pore space of the reservoir rock. Such curves automatically give values for the ultimate physical recovery, if the latter is interpreted as the recovery obtained when the reservoir pressure has declined to atmospheric, or to any other pressure chosen as defining the state of practical complete depletion.
Calculations of these pressure and gas-oil ratio histories have been made for conditions in which the oil viscosity, the gas solubility and shrinkage, the size of an overlying gas cap, if present, the permeability-saturation characteristics of the rock, and the amount of connate water, have been individually varied. The results serve to show the extent to which the ultimate recoveries are sensitive to the important physical parameters characterizing the oil reservoir. As is to be expected, the ultimate recoveries are found to decrease with increasing oil viscosity. Because of the predominant effect of the oil shrinkage associated with the liberation of the gas in solution, the ultimate recovery will decrease with increasing gas solubility. Increasing gas-cap volumes lead to higher recoveries, although the contribution made by the gas-cap gas is small as compared with the oil expulsion by the equivalent amount of solution gas.
As a whole, the oil recovery when expressed in percentage of the pore space is not very sensitive to the details of the permeability saturation relationship. However, if the rocks possess an equilibrium free-gas saturation, the rise in gas-oil ratio will be retarded, and the ultimate recovery somewhat increased.
The oil shrinkage associated with the liberation of the dissolved gas also leads to the result that as long as the connate water is immobile and the permeability ratio curve for the rock is a function only of the total liquid saturation, the stock-tank oil recovery will be less for a sand containing no connate water than for one with an original water content as high as 30 per cent. The space voidage in the former case will be somewhat greater, but the effect of oil shrinkage will lead to smaller values for the equivalent stock-tank recovery.
These calculations also give data showing how the productivity indexes for the producing wells will vary during the reservoir history. Because of decreasing permeability to the oil and increasing oil viscosity, the productivity index will fall continuously as production proceeds, and may finally reach values as low as 10 per cent of the initial productivity index.

Introduction
In a previous paper was developed the basic theory for the prediction of the production histories of gas-drive reservoirs.
T.P. 1917
The Viscosity of Air, Water, Natural Gas, Crude Oil and Its Associated Gases at Oil Field Temperatures and Pressures
Authors: Beal Carlton 
Published: June 2014

Abstract
This paper presents useful charts for conversion of various viscosimeter unitsinto centipoises and graphically summarizes published investigations of theviscosity of air, water and natural gas at high temperatures and pressures.Where possible, charts and correlations were constructed to cover a range oftemperature (60'F. to 300'F.) and pressure (14.7 lb. per sq. in. abs. to 8000lb. per sq. in. gauge) encountered in oil fields.
Correlation charts, for the purpose of predicting crude oil viscosity andsolubility behavior at oil field temperatures and pressures, were constructedfrom an analysis and correlation of 1332 viscosity and solubility observationsfrom 953 crude oil samples taken from 747 oil fields. Of these fields, 501 arein the United States, including 75 in California. Of the 1332 observations,12I5 were viscosity values, including 786 of gas-free crude oil, 351 of oilsaturated with gas, and 78 undersaturated with gas at pressures above thebubble point.
Results show that crude oil viscosity at various reservoir conditions can bepredicted with average deviations varying from 24.2 per cent for gas-free crudeoil to as little as 2.7 per cent for under saturated crude oil "above thebubble point." The solubility of crude oil may be predicted from oilgravity and saturation pressure with an average deviation of 22.0 per cent fromobserved values. In conclusion, it is shown that the viscosity of a gas andgas-saturated crude oil may be predicted within the accuracy of most reservoircomputations.

Introduction
Viscosity is a measure of flow resistance; common units are in centipoises(cp.). The object of this report is to present conversion charts and simplifiedcorrelation charts showing the viscosity behavior of air, water, gas and crudeoil and gas-saturated crude oil under oil field temperatures and pressures, which have been known to be as high as 300'F. and 8000 lb. per sq. in. gaugeunder subsurface conditions.
The viscosity of a liquid or gas is important because it is a measure of itsfluidity, or its ability to flow through pipe lines or oil sands. Viscosity ofair has become important because it is being used in secondary recoveryprojects. The viscosity of natural gas and water at reservoir conditions isuseful because they are almost universally associated and produced with crudeoil. The viscosity of gas-saturated crude oil at reservoir pressures andtemperatures is of particular value in making estimates of oil reserves andrate of oil recovery from flush pools when production decline data arelimited.
Instruments Used to Measure Viscosity
There are many types of viscosimeters, and the instruments most commonly usedto measure the atmospheric viscosity of liquids at moderate temperatures andtheir practical working ranges have been described in detail.
Precision in Bottom-hole Pressure Measurement
Authors: Brownscombe E.R. , Conlon D.R. 
Published: June 2014

Errors in measurement of reservoir pressure include:gauge errors, andinterpretation errors.
Gauge errors may be reduced by:reading charts with a comparatormicroscope,use of hard metal stylus points to give clear lines,insuring temperature equilibrium, andmaking multiple tests.
Checkcalibrations are equally as important as check well tests. A statisticalanalysis of such check runs shows quantitatively the advantages of astandardized "zero pressure line" and of the use of field calibrationsmade at bottom-hole temperature on the same chart run in the well.
Interpretation errors include:fluid heads, which should be corrected tothe top of the perforations on the basis of well-fluid gravity and from the topof the perforation to the datum level on the basis of reservoir-fluid gravity, andgradients around the well.
Conventional shut-in periods may be entirelyinadequate to overcome these, necessitating a reservoir study based on build-upcurve data, reservoir history, core analysis and any other availableinformation.
Interest in engineering studies of the pressure changes in oil and gasreservoirs is increasing. This type of work yields important information anddoubtless will be greatly extended in the future. One of the factors limitingthe work, however, is the accuracy with which the reservoir pressures can bedetermined; for if the inaccuracies in the pressure measurements represent anappreciable percentage of the pressure changes, the engineer is seriouslyhandicapped, and must delay the reservoir study until the reservoir pressurehas changed a relatively large amount. This delay can greatly reduce thebenefits of such studies, at least from the point of view of aiding theleasing, drilling and completion programs. Thus, from the point of view ofreservoir analysis, it is frequently important to obtain the most accuratepressure data possible early in the history of any field-particularly for thegasdistillate fields now being developed.
This paper deals with improvements in the measurement of bottom-hole pressuresthat permit pressures even as high as 4000 or 5000 lb. per sq. in. to bedetermined with gauge errors of only 1 to 2 lb. per sq. in. Since pressures outin the reservoir rather than in the bottom of the hole concern the reservoiranalyst, differences between bottom-hole pressures and actual reservoirpressures are also considered.
In general, errors in pressure measurement may be divided into:Gauge errors:Errors due to inaccuracies in reading the pressure charts.Errors due to irreproducibility of the pressure element and recordingsystem.Errors caused by failure to allow the gauge to reach temperatureequilibrium.Interpretation errors:Errors caused by a fluid head between the gauge position in tubing and thepressure' at the datum level in the reservoir.Pressure gradients in the reservoir.
T.P. 1942
Possibilities and Problems of Drilling beyond the Continental Shelves
Authors: Gross Henry Emmett 
Published: June 2014

Abstract
A plausible method of drilling beyond the continental shelves is set forth withlimitations of the method. The continental shelves comprise the water-coveredportions of land masses out to 600'Ft. of water, or 100'Fathoms. The problemsand possibilities of drilling beyond this depth are discussed in thispaper.

Introduction
Much attention is being given the problem of developing petroleum beneath theopen sea. Geophysical surveys have been made 26 miles offshore from thecontinental United States, and once offshore ownership is established it islikely that there will be drilling for oil on the continental shelves.
More than two? years ago the author presented the means for drilling in deepwater. at the fall meeting of the Petroleum Division of the AIME at LosAngeles. His concepts then were based on the use of rigid foundations suitablefor drilling in water up to 600'Ft. deep. The present paper suggests a methodfor drilling in deeper water.
Possibilities and Problems of Drilling Beyond the Continental Shelves
It being conceded that because restricted deep-water portions of thehydrosphere might contain oil in commercial quantities, and that at any rate itis pertinent to know more of the nature of the lithosphere beneath thehydrosphere, the possibilities and problems of drilling beyond the continentalshelves should be set forth.
Drilling in open water would offer few if any advantages over drilling on land.These are:The ocean transportation is available to deep-water drilling sites, andextensive pipe lines and roads are unnecessary.Refinery facilities and markets perhaps are established on the near-by shorewhere adjacent fields on land are nearing depletion.There is freedom from jungle pests and tropical diseases.Competitive drilling is less likely.Extensive areas attractive for development are not yet under lease orconcession.
Disadvantages are great and numerous:Storm hazards from wind and wave.Expensive foundations, either rigid or floating.Shutdown times because of weather.Marine Regulations of Federal Bureaus in addition to customary regulationson land.Frequent difficulty in moving men and materials to and from drillingplatforms.Extra precautions required in open sea.
T.P. 2095