bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Factors Controlling the Pumping Time of Oil-well Cements
Authors: Neighbors Glen R. , Cromer Sylvan
Published: June 2014

High subsurface temperatures and pressures are making cementing operationsmore difficult as deeper producing horizons are being sought. Recordedbottom-hole temperatures above 200?F and pressures in excess of 12,000 lb. persq. in., obtained by combining hydrostatic and pump pressures, are notuncommon. Insufficient time is available for proper placement of standardPortland cement, because of the shortened setting time produced by theseexcessive temperatures and pressures, therefore special types of cements havebeen developed to overcome these difficulties. From the standpoint ofplacement, the ideal slurry would be one that would remain fluid long enough tobe placed, then harden rapidly, so that there would be a limited amount ofcontamination and the well could be placed on production in a minimum of time.It is highly desirable, therefore, that some method be devised to measureaccurately the time that any slurry will remain in a fluid state while beingpumped into the well.

To study the effect of elevated temperature and pressure on fluidity, theauthors have developed the pressure-type consistometer (Figs. 1 and 2)described below, and are presenting data obtained with it, using slurries ofboth quick-setting and slow-setting cements. Studies were made over atemperature range from 110? to 270?F., and a pressure range from atmospheric to3000 lb. per sq. inch.

Apparatus

The fluidity of cement slurries at atmospheric pressure is usuallydetermined with the Halliburton consistometer or the Thickening Time Tester.These instruments are similar, in many respects, to an ordinary ice-creamfreezer. The slurry to be tested is placed in a container that is rotated at aconstant speed with an electric motor. Constant temperature is maintained bysurrounding the container with a thermostatically controlled bath. The torqueon the paddles, which is proportional to the force needed to shear the slurry, is indicated on a scale. The Halliburton instrument is calibrated from 0 to 100poises against fluids of known viscosity.

T.P. 1399
Effectiveness of Gravel Screens
Authors: Sage B.H. , Lacey W.N.
Published: June 2014

The results of an extensive experimental program relating to theeffectiveness of gravel screens have been correlated. The factors considered insome detail include gravel size and condition of packing, sand size and sizedistribution, fluid velocity, fluid viscosity, and thickness and arrangement ofgravel screens. Good agreement between calculated values based upon probabilityconsiderations and experimental results relating to the influence of thethickness of the gravel screen was obtained. All of these factors are treatedin the correlation in order that their influence may be taken into account inascertaining the characteristics of an effective gravel screen for a particularset of conditions. The details of the experimental program are not given in thepresent paper but a description of generalized behavior and typicalexperimental results are recorded in graphic form.

Introduction

Gravel screens have been placed in water and oil wells for a number of yearswith the dual objective of increasing the productivity and decreasing theentrance of sand into the well bore. An understanding of the factorscontrolling the effectiveness of gravel screens in this connection is ofindustrial interest because it will lead to the proper selection of gravel.Some of the fundamental considerations involved in the migration of sandthrough a coarser body of porous materials were investigated by Coberly andWagner, and further experimental work has been carried out by Gumpertz.Apparently the pertinent phenomena are somewhat complex and are influenced bymany variables. The present paper deals with the prediction of the behavior ofgravel screens under the conditions encountered in practice but does notattempt to discuss the experimental methods or results that were obtained as abackground and upon which the prediction is based.

Influence of Gravel Screens Upon Productivity

The use of a gravel screen may increase the productivity of a well byincreasing its effective diameter, and this constitutes one of the objectivesof its use. The permeability of most gravels and coarse sands that are employedin practice is so large compared to that of the sand in place that relativelylittle loss in production rate will arise from the use of material fine enoughto cause the desired resistance to sand migration.

T.P. 1325
Calculation of Theoretical Productivity Factor
Authors: Evinger H.H. , Muskat M.
Published: June 2014

A method has been developed whereby one may calculate the productivityfactors of producing formations from a knowledge of the reservoir conditions.Account is taken not only of the heterogeneous character of the gas-oil flowsystem but also of the detailed variations with pressure of the shrinkage andviscosity of the oil, the solubility of the gas in the oil, and even thevariability of the gas viscosity and the deviation of the gas from idealbehavior. Curves are shown giving the results of numerical calculations on theproduction rate as a function of the pressure differential for a highpressureand a low-pressure system, three values of gas-oil ratio being treated in eachcase. Curves are also given showing the variation with distance from the wellof the pressure, oil saturation, and permeability. The effect of connate wateris briefly discussed in relation to the apparently large discrepancies betweenthe calculated and observed productivity-factor values.

Introduction

The significance of the productivity factor as a measure of the capacity ofan oil-bearing formation to produce is well recognized; for it is the compositeand integrated resultant of the physical properties of both the porous mediumand the fluid stream passing through it with respect to the ease with which theparticular petroleum fluids present in the formation can flow through it andinto producing wells.

The most direct method of determining the productivity factor of a wellconsists, as is well known, in the simultaneous measurement ofreservoir-pressure differentials and rates of production and the expression ofthe data in terms of rate of flow per unit pressure drop. Actual measurementscarried out in this manner on producing wells have given factors that generallylie in the range of 0 to 100 bb1. per day per pound pressure drop. This widerange arises not only from variations in permeability but also from the varyingsand thickness of producing formations.

T.P. 1352
Density of Crude Oils Saturated with Natural Gas
Authors: Standing Marshall B. , Katz Donald L.
Published: June 2014

Density data are reported on 15 saturated hydrocarbon liquids in the rangeof 35? to 250?F. and 1000 to 8220 lb. per sq. in. The apparent liquid densitiesof methane and ethane are shown to vary with the density of the system in whichthey are present. A method is proposed whereby the densities of liquidhydrocarbon mixtures containing both methane and ethane in solution may becomputed at elevated temperature and pressures within the accuracy of usualengineering computations. A method of computing the shrinkage of crude oilsbased upon the gas-oil ratio, gas analysis, and crude gravity is outlined.

Introduction

The densities of naturally occurring liquid hydrocarbon mixtures areimportant in many petroleum engineering computations. Calculation of theshrinkage of a subsurface sample of crude oil as the natural gas is evolved isone example of the use of liquid-density data.

Sage, Hicks, and Lacey have presented a method of computing the density ofhydrocarbon liquid mixtures based on partial molal volumes. Katz has indicateda method based on the principle of additive volumes of the components and usingapparent densities for methane and ethane.

T.P. 1397
Calculation of Productivity Factors for Oil-gas-water Systems in the Steady State
Authors: Evinger H.H. , Muskat M.
Published: June 2014

A method of calculating productivity factors for oil, gas, and water systemsin the steady state is presented as an illustration of the quantitativeapplication of the fundamental data on the flow properties of heterogeneousfluid systems. While the numerical results of the calculations cannot beapplied directly to field conditions, because they are based on permeabilitydata for unconsolidated sands and involve specific assumptions regarding thenature of the reservoir fluids, the methods of analysis and interpretationshould have significance in considering certain specific field situations whenthe necessary field and laboratory data become available. Moreover, it is feltthat even under the idealized conditions to which the numerical calculationsrefer they should serve to give at least the orders of magnitude of the effectsof gas-oil ratio and connate water on observed productivity factors. Within theindicated limitations, the computations imply that the foregoing factors canexplain only a part of the apparent discrepancy between the homogeneous fluidproductivity factors and those obtained recently in field measurements on theWest Coast.

Introduction

Sufficient laboratory research has been carried out in the last severalyears on the fundamental features of the flow of heterogeneous fluids throughporous media to call for consideration of what can be done with this type ofinformation. It has, of course, already led to a much clearer generalunderstanding of the mechanics of oil production. However, examples of thequantitative application of the results of such laboratory studies are few inthe literature. Part of the explanation for this fact lies undoubtedly in thelack of sufficient laboratory data relating to practical fluids and sandsystems such as would occur in actual oil reservoirs. However, unless it can beshown that if such data were obtained quantitative applications could be made, serious doubt may be cast upon the desirability of carrying on furtherextensive experimental research work on fluid flow.

The purpose of this paper is to present one approach to the problem ofquantitative application of laboratory data to practical field problems.Because the published results on the basic experiments with three-phase fluidsystems in porous media are limited entirely to unconsolidated sands, thenumerical applications made here will not pertain directly to any actual fieldsituation. However, they should serve to illustrate what could be done withfundamental laboratory data if they were extended to cover the field ofconsolidated sands. From this point of view, it is hoped it will serve toencourage further laboratory research on this problem.

T.P. 1416
The S.P. Dipmeter
Authors: Doll H.G.
Published: June 2014

This paper discusses a method and apparatus for determining the dip offormations traversed by a drill hole, by means of electrical measurements inthe hole. The process consists in recording the Spontaneous Potentials presentalong three oriented generatrices in the hole. By comparison of the threecurves thus obtained, after application of a correction factor to compensatefor any deviations of the hole, the dip angle and the dip direction aredetermined. Excellent accuracy is obtained for dip angles over 10?.

Because the method is simple and the apparatus rugged, the measurements arerapid and reliable; consequently, they can be made at all the levels that areof interest at any time after the well has been drilled. Mechanical cores arenot needed to evaluate the dips.

A convenient, time-saving procedure is to perform the dipmeter survey at thetime the electrical log is taken, using for both operations the same cable andtruck.

Actual examples of results obtained in wells of the Gulf Coast area aregiven.

Introduction

The problem of determining the angle and direction of the dip of the stratatraversed by a drill hole has practical interest, and sometimes vitalimportance, which need not be emphasized to the oil industry. The need for thattype of information has existed ever since wells have been drilled. Certainlyit has not subsided, in spite of the numerous inventions and improvements madein other fields of the art of drill-hole exploration. The few examples given inthis paper are but illustrative of this fact.

In the past, methods have been devised, and used, to solve this problem, butgenerally they have met with limited success, possibly because they failed moreor less to answer the requirements of a modern age for fast yet accuratemeasurements. If accurate, the results were obtained at the cost of verytedious and lengthy operations.

The new S. P. dipmeter service offered to the oil industry is the result ofexhaustive research in this particular field. In 1932 a dipmeter andelectromagnetic teleclinometer service was made available. The apparatusemployed then was of a rather delicate and costly construction, and themeasurements had to be made with precautions sometimes difficult to secure onthe rig. Although the information given by the electromagnetic dipmeter waslimited to the direction of the dip, very interesting results were obtained inCalifornia, Trinidad, Venezuela, Rumania and, most notably, in the NetherlandsEast Indies.

T.P. 1547
Caliper Logging
Authors: Parsons C.P.
Published: June 2014

Caliper logging is a practice of measuring the variations in the diameter ofthe open hole in a well. This information is useful for many purposes, amongwhich are: Determining the volumetric capacity of the portion of open hole tobe cemented; the amount of gravel to be used for gravel-packing a well; thesize and location of seat for a packer to be placed in a well; studying theeffects of nitroglycerin shots; studying the effects of acidizing; studying thecause of drill-pipe failures; studying drilling technique; geologicalcorrelations. This is a new practice in oil fields and is eliminatingconsiderable guesswork.

Introduction

Caliper logging of the open hole in oil wells, recently introduced and nowshowing initial results in many sections of the country, is providinginformation that is filling a long-felt need in oil-well cementing and innumerous other oil-field practices. Briefly, it measures the variations indiameter of the open hole in a well. This direct physical measurement of thestratigraphic profile has considerable value for subsurface interpretations bythe geologist, engineer, driller and others charged with the responsibility ofproperly completing and repairing oil and gas wells.

The caliper shown in Fig. I is run into a well in closed position. The fourarms are released when logging is to start. These arms are independent of eachother. As the calipers are pulled upward through the open hole, the arms arelike nimble fingers feeling the changing profile of the hole. This mechanicalaction is in turn converted into an electrical circuit, which is connected to arecording mechanism at the surface. The recording of the diameter of the holeis directly in inches.

T.P. 1474
Water Influx Into a Reservoir and Its Application to the Equation of Volumetric Balance
Authors: Hurst William
Published: June 2014

This is a presentation of the diffusivity theory for the calculation of thewater drive on an oil reservoir in which the history of reservoir pressure withtime are the essential parameters for the determination of the rate andcumulative water encroachment into a field. The main body of the paper isessentially the application of the principles underlined here to actual fielddata. It consists of the work plots of the radial-flow case, and includes adiscussion of an illustrated problem for which the water-drive calculations aretreated in conjunction with the volumetric-balance equation. The appendix is amathematical treatment of the linear, radial, and spherical cases of waterinflux into a reservoir.

Introduction

The evaluation of oil reserves and the prediction of pressure behavior withdifferent rates of production are related to the volumetric balance of thefluids entering and leaving the space occupied by the oil and gas originallypresent in the formation; that is to say, important information can be gleanedfrom a volumetric study of the oil, gas, and water produced from a formation asit affects the extent of change in volume of oil zone, the gas cap, and theamount of water influx from the adjoining water sands.

It is not the purpose of this paper to enter into a discussion of theequation of volumetric balance, in which such pertinent information assubsurface sampling and the measurement of reservoir pressures play apredominant part, as this has been discussed in detail by others. However, there is an inherent difficulty that has limited the general application ofthis equation to a study of oil reservoirs; that is, the insufficient knowledgeof the analytics for expressing the water drive on a field as a function ofreservoir pressure. This to a large degree has been overcome and it is thepurpose of this paper to present this theory in such form as to be applicablefor reservoir calculations.

T.P. 1473
Asphaltic Substances in Crude Oils
Authors: Precksho G.W. , DeLisle N.G. , Cottrell C.E. , Katz D.L.
Published: June 2014

Most crude oils contain asphaltic substances that may be naturally orartificially precipitated. In the Greeley field, California, this asphalticbitumen is precipitated during the flow of the oil from the reservoir to thestock tank. The mechanism of such precipitation is not well understood. Thispaper presents the progress that has been made by using the electron microscopeas a new tool and by observing the effects of the streaming potential on theformation of bitumen particles.

Crude oils at atmospheric pressure viewed in the electron microscope in verythin films under a vacuum showed no asphaltic particles. A technique ofpreparing slides of thin films by dilution of the oil with benzene and washingin petroleum ether was used at first, and these observations showed that thesolvents caused the formation of the particles, varying from 0.01 to 0.2 micronin diameter.

The electrical effects of fluids flowing through porous solid were studied, with emphasis on the formation of colloidal particles by the streamingpotential. The streaming potential of crude oil flowing through sand wasmeasured and was shown to be responsible for the formation of bitumenparticles. These results bring out a new phenomenon, which may occur when crudeoil flows through the porous oil reservoir.

1. The Electron Microscope as a New Tool

Asphaltic particles have been precipitated from crude oils by a variety ofmechanisms. Asphalt has been the subject of widespread investigation but, owingto the complexity of the substances being considered, progress has been slow.Investigators working primarily with the asphaltic substances have treated thesubject from the colloidal standpoint and have developed theories that picturethe asphaltic particles as surrounded by adsorbed materials. Thedeasphaltization of lubricating oil by the use of solvents treats the subjectprimarily from the standpoint of liquid-liquid equilibria. A completeunderstanding of asphaltic substances would make possible the following of thematerial from its initial state in the crude oil through precipitationprocesses to the final plastic stage, the most common form of which is used inasphaltic pavements.

T.P. 1514
Joule-Thomson Coefficients for Two Natural Gases
Authors: Sage B.H. , Botkin D.F. , Lacey W.N.
Published: June 2014

Joule-Thomson coefficients for two natural gases were determined atpressures up to 600 lb. per sq. in. throughout the temperature interval between70? and 310?F. From these primary data and available information relating tothe isobaric heat capacities of the components at infinite volume, the heatcapacities of these gases were computed throughout the abovementioned range ofpressures and temperatures. The enthalpies of the gases were computed as afunction of state and the results compared with values obtained by severalmethods of prediction currently available.

Introduction

Experimentally determined Joule-Thomson coefficients for natural gasesafford a satisfactory means of checking the accuracy of prediction of theirthermodynamic properties from the behavior of the components in the pure stateand in binary mixtures. Relatively small samples of these natural gases wereavailable, together with their analyses, and the Joule- Thomson coeffi cients were investigated at temperatures from 70? to 310?F. throughout as largea range of pressures as the quantities of gas on hand permitted.

Method and Materials

The Joule-Thomson coefficients were determined by measuring the change intemperature resulting from the passage of the gas through a porous thimble witha known pressure difference and under such conditions that the process wassubstantially isenthalpic. The details of the apparatus employed for thispurpose have been described. It is believed that the changes in temperature andpressure were ascertained with an uncertainty of not more than 0.3 per cent.However, as a result of deviations from steady flow, it is probable thatuncertainties as large as 2 per cent may exist in the measured Joule-Thomsoncoefficient.

The gases utilized in this work were taken from high-pressure separators andwere dried prior to use by passage over calcium chloride at pressures in excessof 300 lb. per sq. in. The gases were subjected to the conventionalfractionation and Orsat analyses. The results are recorded in Table I. Thecomposition is typical of gases from such sources, with the possible exceptionof the presence of significant quantities of carbon dioxide in each of thesamples.

T.P. 1504
Sources, Disposition, and Characteristics of the Capital Employed by Thirty Oil Companies during the Nine-year Period 1934-1942
Authors: Pogue Joseph E. , Coqueron Frederick G.
Published: June 2014

Prior to 1934, published information covering expenditures by oil companiesfor properties, plant, and equipment and the residual investments in thevarious segments of the petroleum industry was not readily available. Thispaper presents an analysis of the funds invested by a selected group of oilcompanies during the years 1934 through 1942, based on an extensive study ofthe individual records of 30 oil companies.

The sources, disposition, and characteristics of the capital employed bythis group of companies are traced through a series of combined statements andappropriate charts, covering financial and operating data. The analysis ofthese statements not only constitutes a record useful for comparative purposesbut also serves as a basis for a number of broad conclusions, as follows:The petroleum industry generates the capital needed for its expansion almostentirely from its own operations and is therefore a singularly self-containedeconomic unit.The long-term debt contained in the financial structure of the industry issmall relative to the total capital employed, is less than the net workingcapital, and has increased but slightly during the period under review.The capital expenditures of the group of 30 oil companies for 9 yearsamounted to 6.1 billion dollars, 58.3 per cent of which went into crude-oilproducing facilities. The trend of this segment of expenditures has beendownward since 1937. In 1942, expenditures for refining facilities increasedsharply and for marketing facilities declined drastically.The net working capital of the group increased 380 million dollars over theperiod, and the industry is in a favorable position of liquidity. The ratio ofcombined current assets to current liabilities was 3.21 at the close of theperiod.The net income of the group displayed an upward trend for the period butwith rather sharp cyclical fluctuations.In 1942, Government funds entered the industry for the first time insubstantial amounts and were utilized for the provision of war facilitiesneeded for emergency use.

C.N. 133
A Study of the Smackover Limestone Formation and the Reservoir Behavior of Its Oil and Condensate Pools
Authors: Bruce W.A.
Published: June 2014

Studies of reservoir behavior of 12 Smackover limestone oil and condensatepools are presented. Buckner, Midway, McKamie, Magnolia, Mt. Holly, Schuler(Reynolds) and Village are treated in considerable detail and subjected toanalysis with an electrical device for analyzing reservoir behavior. Resultsand comparisons of these analyses are presented.

In addition to these reservoir-behavior studies, an attempt is made to assembletransmissibility and storage data on the Smackover limestone formation fromcores and logs taken in dry holes and producers. This together with thebehavior of individual reservoirs leads to a better understanding of theformation as a porous aquifer.

The ultimate purpose of this type of study is to improve predictions concerningthe future behavior of these pools in such a system. Predictions are presentedfor several pools.

Introduction

In 1937 the Phillips Petroleum Co. drilled its J. D. Reynolds No. 1 to the Smackover limestone formation at Snow Hill, Arkansas. This well found oil inthe porous, permeable, upper part of the Smackover thereafter referred to asthe Reynolds lime. Since then, six oil pools and six condensate pools have beendiscovered in the Reynolds lime, and more than 75 dry holes have explored partsof this formation.

By the first of 1943, 44 million barrels of oil and 83 billion cubic feet ofgas had been withdrawn from the various reservoirs. The original reservesestimated by the Arkansas Oil and Gas Commission were 342 million barrels ofoil and 1200 billion cubic feet of gas.

So far all of the production has been from anticlinal structures, most of whichare asymmetric and have their axes roughly perpendicular to the dip of theformation top. This is indicated in Fig. 1, which shows the pools, dry holesdrilled, and contours on top of the Smackover.

These pools are of particular interest for reservoir-behavior studies becausethe production and drilling has been controlled, and in most cases the recordsof reservoir data are complete. In addition to the excellent production andpressure information available, more than one half of the wells drilled werecored and all of them were electrically logged. All of the pools show evidenceof water drive.

While this paper is in a sense a collection of reservoir-behavior studies forseveral different pools, there has been an attempt to go one step further andto show the importance of the formation as a porous continuum or a singleaquifer in which the withdrawals of fluids from any pool has an. importanteffect on the behavior of all of the pools. An effort will be made to show thatthe water drives of these pools are dependent upon a much larger area of theSmackover limestone than that occupied by the petroleum accumulations.

T.P. 1728
Prediction of Reservoir Behavior from Laboratory Data
Authors: Babson E.C.
Published: June 2014

In order to explore the possibility of predicting reservoir performance fromlaboratory data, behavior of a hypothetical low-permeability reservoir has beenestimated by applying data and methods currently available in the literature. Amethod of calculating decline in productivity index is discussed, andrecoveries by internal gas drive, external gas drive and water drive areestimated.

Introduction

During the life of a producing oil property an operator is faced with manyperplexing problems. Any attempt to determine proper well spacing, optimum rateof production, or the desirability of pressure maintenance requires theevaluation not only of a host of economic and practical operating factors butalso of the future performance of the reservoir. Although in some caseseconomic or operating considerations may be of primary importance in planning adevelopment or production program, the anticipated effect on ultimate recoveryis more likely to be the decisive factor.

The soundest basis for evaluating reservoir performance is past experience withoil fields, but pertinent data are difficult to obtain or apply underconditions normally encountered in California fields. Many of these fields arecharacterized by thick sections of alternating sands and shales complicated byfaulting and rapidly changing lithologic conditions. Further complications areintroduced by haphazard development and production practices resulting fromcompetitive conditions, changing demand for oil, and insufficient knowledge ofstructural conditions during early development. Even in the rare cases wheredevelopment has been systematic and adequate, production policy has usuallybeen controlled by economic and competitive factors rather than a desire toobtain information for use in future operations. In other words, comparablereservoirs in which development and production practices have beensystematically varied are seldom found.

In the light of these conditions, conclusions based on experiences usually lackthe certainty required for decisions involving large sums of money. Some othermethod of attacking these problems is needed to supplement and orient fieldexperience. Progress in laboratory investigations of the flow of oil, gas, andwater through sands has been so rapid in recent years that these data mayfurnish such a supplementary approach in the near future. In order to explorethis possibility the author has attempted to predict the behavior of one typeof reservoir by applying published data and methods.

Basic Data and Assumptions

Calculations outlined in this paper are dependant upon a detailed knowledge ofthe properties of oil, gas, and water present in the reservoir and the portionof the total pore space originally filled by each.

T.P. 1664
Fingering and Coning of Water and Gas in Homogeneous Oil Sand
Authors: Arthur M.G.
Published: June 2014

This paper is a theoretical analysis of fingering of water and coning of waterand gas in homogeneous sand. Investigation of this idealized case illustratesthe relative magnitude of the factors involved in actual conditions. The bodyof the report presents equations, example calculations, and charts thatfacilitate solution of such problems. Derivation of the equations introduced inthis paper and a discussion of previously published equations are included inthe appendix.

Introduction

Production of water from oil wells as a result of the pressure gradientsestablished by flow of fluids through oil-producing sands is a commonoccurrence, which influences the cost of oil production, the degree ofdepletion and the efficiency of expulsion of oil from naturally occurringreservoirs. Control of water production and encroachment are important both inprimary and secondary phases of oil-field exploitation in order to produce oiland gas at lowest cost and in order to achieve the greatest ultimate recoveryof the oil in the reservoir. Although many actual oil reservoirs present amultitude of variables that influence fingering and coning of water and gas, aninspection of the relationship and magnitude of the forces involved in the caseof a homogeneous sand may indicate satisfactory methods of controlling waterproduction. Application of equations relating the variables may indicate thegeometric type of drainage that exists in a particular reservoir or in thevicinity of a particular well.

A homogeneous sand body is assumed within the portion of the reservoirinfluenced by the well. Two geometric types of drainage are consideredtheoretically. The first is water fingering into an oil sand that is relativelythin compared with the lateral extent of the sand. This sand may represent theentire oil-producing reservoir or it may represent one interval in an oilreservoir, which is separated from other producing intervals by competentlithologic barriers to flow of fluids. For the condition of completepenetration of a well in such a sand body, it may be assumed that no flowoccurs across bedding planes. A mathematical relation is developed between thelimit of approach of a water finger to the well without being drawn into thewell and the corresponding operating pressure drawdown.

The second condition considered is that of water or gas entry into an oil wellas the result of coning through bedding planes. The theory and graphicalsolution developed by Muskat for the limit of approach of a water or gas coneto a well, without its entry into the well, related to the correspondingmaximum pressure drawdown, is reviewed and amplified. Charts are presented, which facilitate graphical solution of the problem. A method is presented forthe extension of this type of graphical solution to the case where gas andwater coning occurs simultaneously.

T.P. 1723
Measurement of Capillary Pressures in Small Core Samples
Authors: Hassler G.L. , Brunner E.
Published: June 2014

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

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

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

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

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