bluuebunny/crossref_metadata_2025 huggingface dataset:
Further Developments in the Laboratory Determination of Relative Permeability
Authors: Caudle B.H. , Slobod R.L. , Brownscombe E.R.
Published: April 2012

An earlier publication has discussed three methods for obtaining relativepermeability data on small core samples and the apparatus and technique for thecapillary pressure displacement method. This paper describes the apparatus andtechnique for the solution gas and the dynamic displacement methods andpresents a routine procedure for obtaining oil-gas and water-oil relativepermeability data.

Theoretical and experimental considerations are presented to show that theend effect commonly associated with the dynamic flow mechanism is extremelysmall where constant rates are employed in the flowing phase. An effect of flowrate on relative permeabilities obtained by the dynamic system is found onlywhen gas is one of the flowing phases and this effect is ascribed to a form ofchanneling in the capillary system.

The apparatus and procedures used to obtain relative permeability data withthree phases flowing are described and some preliminary results of the use ofthis method are shown.

Introduction

In a previous publication from this laboratory there appeared a briefdiscussion of the concepts behind three basic methods for obtaining relativepermeability data. These three methods were called the capillary pressuredisplacement method, the solution gas displacement method, and the dynamicdisplacement method - the names being suggestive of the type of process usedfor obtaining the desired saturation prior to making the permeabilitymeasurements. In the same publication, the apparatus and technique for thecapillary pressure displacement method were described and some typical resultsobtained by this method were presented. This paper will present:The routine procedure used to obtain permeability data on small coresamples flowing;The experimental techniques for the solution gas and dynamic displacementmethods for obtaining relative permeability data;The results of some studies on the mechanism of fluid flow throughconsolidated porous media; and,The preliminary results on the determination of relative permeability for asystem in which three phases are flowing.

T.P. 3056
Steady Flow of Two-Phase Single-Component Fluids Through Porous Media
Authors: Miller Frank G.
Published: April 2012

This report presents developments of fundamental equations for describingthe flow and thermodynamic behavior of two-phase single-component fluids movingunder steady conditions through porous media. Many of the theoreticalconsiderations upon which these equations are premised have received little orno attention in oil-reservoir fluid-flow research. The significance of theunderlying flow theory in oil-producing operations is indicated.

In particular, the theoretical analysis pertains to the steady, adiabatic, macroscopically linear, two-phase flow of a single-component fluid through ahorizontal column of porous medium. It is considered that the test fluid entersthe upstream end of the column while entirely in the liquid state, movesdownstream an appreciable distance, begins to vaporize, and then moves throughthe remainder of the column as a gas-liquid mixture. The problem posed is tofind the total weight rate of flow and the pressure distribution along thecolumn for a given inlet pressure and temperature, a given exit pressure ortemperature and given characteristics of the test fluid and porous medium.

In developing the theory, gas-liquid interfacial phenomena are treated, phase equilibrium is assumed and previous theoretical work of otherinvestigators of the problem is modified.

Laboratory experiments performed with specially designed apparatus, in whichpropane is used as the test fluid, substantiate the theory. The apparatus, materials and experimental procedure are described. Comparative experimentaland theoretical results are presented and discussed.

It is believed that the research findings contributed in this paper shouldnot only lead to a better understanding of oil-reservoir behavior, but alsoshould be suggestive in regard to future research in this field of study.

Introduction

In recent years much time and effort has been consumed in both theoreticaland experimental studies of the static and dynamic behavior of oil-reservoirfluids in porous rocks. Although lack of sufficient basic oil-field data, principally concerning the properties and characteristics of reservoir rocksand fluids, largely precludes quantitative application of research results tooil-field problems, qualitative application has become common practice. Ineffect, oil-reservoir engineering research is serving as a firm foundation foroil-field development and production practices leading to increased economicrecoveries of petroleum. This province of research, however, still poses manyperplexing problems.

T.P. 3079
Phase Equilibria in Hydrocarbon-Water Systems III - The Solubility of Methane in Water at Pressures to 10,000 PSIA
Authors: Culberson O.L. , McKetta J.J.
Published: April 2012

Experimental and smoothed data are presented for the solubility of methanein water for temperature, of 77, 100, 160, 220, 280, and 340'F at pressures to10,000 psia.

The minimum solubility phenomenon exists within this temperature range topressures of 10,000 psia.

Introduction

The study of hydrocarbon-water systems has been extended to thedetermination of the solubility of methane in water at pressures to 10,000psia. The experimental apparatus and the technique, are the same as thatpreviously reported.

In the determination of the solubility of methane in water, only two phaseswere present at temperatures between 100 and 340'F, these being the vapor phaseand the water-rich liquid phase. The determinations involved the agitation ofmethane and water in an equilibrium cell, withdrawal of a sample from theliquid phase, and the analysis of the sample. The experimental valuesdetermined in this manner are presented in Table I and in Fig. 1.

Since experimental and analytical techniques have improved since the initialexperiments with this equipment, it was decided to repeat the 77?F isothermdeterminations. Fig. 1 shows that the individual results for this isotherm aremuch more nearly consistent than the data previously reported.

T.P. 3082
Surface Indicating Pressure, Temperature and Flow Equipment
Authors: Riordan M.B.
Published: April 2012

A surface indicating pressure, temperature and flow instrument that employsvariable frequency sensing elements has proved useful in evaluating flowcharacteristics of wells. Relative productivity of individual oil and gas sandsin a given well can be analyzed at several back pressures.

The variable frequency sensing elements are an improvement in sensitivityand accuracy and make possible observation of temperature and pressurevariations that have not been possible heretofore. The surface indicatingfeature results in a more direct approach to solving problems and eliminatesmany assumptions.

All three subsurface factors are evaluated, and correlation between themresults in a direct means of analyzing reservoir and well conditions.

Surveys have been used to evaluate well performance, locate gas entry inhigh ratio wells and to investigate gas injection and water floodingconditions.

Introduction

In a flowing well that is open to a multiple number of producing sands withvarying characteristics, it is valuable to know which sands are producing fluidat a given back pressure and in what relative quantity. Core studies couldqualify an interval as productive, and reserves would be computed on thisbasis. Unless the well is produced so that the interval does contribute, irreparable damage to the interval can occur. It is generally accepted that theoptimum condition of production of oil in an oil well will be, if the objectiveis to produce the largest amount of oil at the least cost, to produce oil atsuch rates of flow that the decline of production and the intrusion of edgewater should be uniform as between all portions of the producing horizonsproducing into the well. An indirect approach to this problem does not alwaysresult in a timely practical answer. To insure a correct answer, the conditionshould be measured as directly as possible, while the well is being produced.The PTF equipment was developed with this objective. Measurements of allvariable factors that can be associated with fluid movement, to a high degreeof dependability and accuracy, was a design requirement.

Initial field use has indicated that sufficient data can be obtained withthe instrument to answer the questioned conditions in a reasonable length oftime and at a reasonable cost.

A description of the instrument, the principals of operation, and the fieldexperience are discussed herein.

T.P. 3080
An Experimental and Theoretical Investigation of Gravity Drainage Performance
Authors: Terwilliger P.L. , Wilsey L.E. , Hall Howard N. , Bridges P.M. , Morse R.A.
Published: April 2012

Theoretical and experimental investigations of a constant pressure gravitydrainage system are reported. Experimental data are presented to show thatrecovery to gas breakthrough by gravity drainage is inversely proportional torate. The gravity drainage reference rate, which is numerically equal to theso-called "maximum theoretical rate of gravity drainage" is shown tohave no particular significance from a recovery standpoint. Before this ratecan be used as a basis of comparison for recoveries, it is necessary that therelative permeability and capillary pressure characteristics and displacingfluid viscosities be identical for the systems compared.

A method is presented by which accurate prediction of the performance of agravity drainage system can be made. Close agreement between experimental andcalculated drainage performance shows that steady state relative permeabilityand static capillary pressure data can be used to describe fluid displacementbehavior. The very wide range of liquid recoveries before gas breakthroughwhich result from production rate variation alone demonstrates the importanceof this factor in planning depletion of a gravity drainage reservoir.Calculated results are presented which show that little additional recovery canbe expected from a high pressure gravity drainage system between the times ofgas breakthrough and attainment of such high gas/liquid ratios as to makefurther pressure maintenance impractical.

Introduction

It has been recognized for some time that gravity forces play an importantpart in the recovery of oil from some types of reservoirs. Field experience hasshown that under certain conditions, gravity drainage can result in very highoil recoveries. Qualitative reasoning has led most engineers to the generalconclusions that:Where gravity drainage is important, the reservoir pressure should bemaintained by gas injection at the crest of the structure to prevent shrinkageof the oil in place and to keep a low viscosity so the oil can drain at thefastest possible rate.Recovery by gravity drainage is rate sensitive.

A survey of the literature indicates that while considerable work has beendone on the effects of gravity in oil production problems, no satisfactorymethod of calculating the performance of gravity drainage reservoirs has beenreported. In the absence of any proven method of calculating reservoirperformance, the level at which pressure should be maintained and the rate ofproduction for most efficient operation has been open to debate.

T.P. 3199
Porosity-Measurement Comparisons by Five Laboratories
Authors: Dotson B.J. , Slobod R.L. , McCreery P.N. , Spurlock James W.
Published: April 2012

A core sample porosity-check program is described. A number of laboratoriesparticipated in the investigation, which comprised measuring the porosities often selected natural and synthetic core samples. Each laboratory employed itsown method (or methods) of measurement. These included Boyle's Law, water-saturation, and organic liquid-saturation methods. Brief descriptions ofeach method employed are given. In general, the measured values of porositywere in reasonably good agreement. The average deviation of porosity from themean or average values for the group of samples was ?0.5 porosity per cent. Theresults of these measurements are compiled and presented in graphical form.

Introduction

The total bulk volume of a porous sample is derived from the sum of twovolumes, the void or pore volume and the solid or grain volume. The porosityfraction of the sample is defined as the ratio of the void volume to the bulkvolume. Multiplication of this ratio by 100 converts it to per centporosity.

Distinction is made here between total porosity and effective porosity. Theformer includes all void space, both interconnected and isolated, while thelatter includes only those voids which are interconnected. This investigationdeals only with the effective porosity.

Numerous cases had been noticed in which there appeared to be appreciablediscrepancies in the results of porosity determinations on core samples.Differences of as much as 10 to 15 porosity per cent had been reported fromdifferent sources for the same sample.

T.P. 3231
The Calculation of Water Resistivities From Chemical Analyses
Authors: Dunlap H.F. , Hawthorne R.R.
Published: April 2012

A method of calculating formation water resistivities from chemical analysesis presented which is somewhat faster and more accurate than previouslydescribed methods. For 26 formation water samples taken from wells in the TexasGulf Coast, the average deviation of calculated from measured waterresistivities was 3.3 per cent, with an average bias of + 1.1 per cent in thecalculated values. This compares with average deviations of 4.6 per cent and7.8 per cent, with corresponding average biases of +3.2 per cent and -6.3 percent, for the two methods previously described in the literature. All threemethods are sufficiently accurate for most purposes; the main advantage of themethod presented is its speed and convenience.

Discussion

It is frequently desirable to calculate the formation water resistivity fromthe chemical analysis of the water, as for example, in electric loginterpretation. Two methods have previously been given in the literature foraccomplishing this. Both methods require that the chemical analysis be given inthe Palmer system, as primary and secondary alkalinity and salinity. Thisconversion of the values of the ppm of the various ions to primary andsecondary salinity and alkalinity is time consuming, and many laboratoriesreport only the concentrations of the various ions in parts per million.However, all laboratories report the individual ionic concentrations, whetheror not the Palmer system of reporting is also used. Hence it was thought that amethod that would permit resistivity calculations directly from these datawould be useful.

In the method developed, the various ions reported in the chemical analysisare converted to an equivalent amount of NaCl. The sum of the variouscontributions to the NaCl (actual or equivalent) can then be used inconjunction with a plot of NaCl concentration versus resistivity to obtain theresistivity of the solution in question.

T.N. 67
Theoretical Note on Linear Absorption Methods of Determination of Fluid Saturation in Porous Media
Authors: Lipson Leonard B.
Published: April 2012

Boyer, Morgan and Muskat, with improvements by Morgan, McDowell, and Doty, and Laird and Putnam, have described a scheme for the determination of fluidsaturation porous media by measuring the x-ray linear absorbing power ofparticular fluids in the media. This method is one of several which depend onthe linear absorbing power of the fluids in the porous medium. Other examplesof linear absorption methods involve measurement of dielectric constant, gammaray absorption, and ultrasonic attenuation. It is the purpose of this note todemonstrate by theoretical considerations that the absorption versus saturationcurve for a linear absorption method is not necessarily a single valuedfunction of the saturation. Such non-unique behavior must be considered andevaluated before suitable saturation determinations can be made by a linearabsorption method.

To illustrate the discussion, examples will be given only for the simplestcases of combinations of two different dielectrics. The dielectric constantmethod was chosen for illustration because it was thought to demonstrate mostgraphically the point in question.

According to Argue and Maass, the resultant dielectric constant of acombination of two different dielectrics depends on the orientation of thedielectrics in the electric field of the test condenser used to measure thedielectric constant. One case involves alternate slabs of dielectrics E1 and E2perpendicular to the electric field of the test condenser, as shown in Fig.1A.

T.N. 83
Volumetric Behavior of Condensate and Gas From a Louisiana Field - II
Authors: Sage B.H. , Reamer H.H.
Published: April 2012

The formation volume and the relative volume of the liquid phase of mixturesof condensate and gas from five different parts of a field in the Louisianaarea have been established experimentally. These studies includedgas-condensate ratios as high as 25,000 cu ft/bbl at pressures up to 5,000 psi.The gravities of the tank condensates were between 53.9' and 63.9' API.

The compositions of the condensate and gas samples investigated arepresented in tabular form. The formation volume, the relative volume of theliquid phase, and the specific volume of the mixtures are available. A roughcorrelation of the formation volume as a function of pressure, temperature, andgas-condensate ratio has been presented. This correlation is consideredapplicable only to the range of conditions covered in this investigation forsystems of similar nature and composition.

Introduction

Often a knowledge of the influence of temperature, pressure, and relativequantities of condensate and gas upon the volumetric behavior of fluids from agiven field has been employed in estimating the conditions existing in thereservoir. The early work of Beecher and Parkhurst and the more recent studiesof the Dominguez and San Joaquin Valley Fields are examples of experimentalstudies of this character. Correlation of the volumetric behavior of naturallyoccurring hydrocarbon mixtures has proved to be feasible at low gas-condensateratios for fluids from a single geographic area. Progress is being made in theprediction of the volumetric behavior of distillate systems at highgas-condensate ratios and pressures. However, the estimation of the retrogradedew-point pressure still remains uncertain and probably can best be establishedby experiment. For this reason it appears of interest to make availableexperimental information about the volumetric behavior of mixtures ofcondensate and gas from five different parts of a single field. This materialshows a rough similarity to data for mixtures of condensate and gas from SanJoaquin Valley Fields.

In the present paper, no attempt has been made to coordinate the availableinformation on the volumetric behavior of fluids from condensate fields. Itappears hopeful that progress can be realized by the utilization of recentlydeveloped equations of state. However, the primary problem in any suchcorrelation is the proper identification of the components and constituents ofnaturally occurring systems.

T.P. 3233
Drilling Fluid Filter Loss at High Temperatures and Pressures
Authors: Schremp F.W. , Johnson V.L.
Published: April 2012

This paper discusses the results obtained from high temperature, highpressure filter loss studies in which field samples of clay-water emulsion andoil base fluids were used. High temperature-high pressure tests of some premiumpriced emulsion and oil base drilling fluids show filter loss peculiaritiesthat are not predicted by standard API tests. It is recommended that hightemperature-high pressure filter loss tests be used to evaluate the performanceof such fluids.

Apparatus is described which proved to be satisfactory for evaluating filterloss behavior over a wide range of temperatures and pressures.

Introduction

The petroleum industry spends large sums of money each year on chemicaltreating agents for lowering filter loss and on premium-priced low filter lossdrilling fluids.

While it is an accepted fact that low filter loss is advantageous duringdrilling operations, it is questionable whether the present standard method ofdetermining filter loss gives a reliable indication of the loss to be expectedunder bottom hole conditions. The purpose of this paper is to show that hightemperature, high pressure filter loss tests should be used to evaluate filterloss behavior of fluids for deep drilling.

Concern over possible effects of filter loss on oil well drilling and wellproductivity dates back to the early 1920's. During the years 1922 to 1924, filtration studies were reported by Knapp, Anderson and Kirwan. These studieswere the first to be reported in the literature on this subject. No furtherinformation was published on the subject until 1932 when Rubel presented apaper in which he discussed the effect of drilling fluids on oil wellproductivity.

In 1935, Jones and Babson constructed the first laboratory tester designedto study the effects of temperature and pressure on the filter loss behavior ofclay-water drilling fluids. In a discussion of their investigations, Jones andBabson stated. "Performance characteristics of a mud can be evaluated withconsiderable reliability by a single test at 2,000 psi and 200'F. Exactcorrelation between the results of performance tests made under theseconditions and the behavior of muds in actual drilling operations is of courseimpossible." Jones and Babson apparently were well aware that at bestlaboratory tests can give only qualitative answers to the question of what isthe actual behavior of a drilling fluid when subjected to deep drillingconditions. Jones presented a paper in 1937 in which he described a staticfilter loss tester to be used for routine filter loss tests. This instrumentsubsequently was adopted as the standard API filter loss tester.

T.P. 3323
Use of Activated Charcoal in Cement To Combat Effects of Contamination by Drilling Muds
Authors: Morgan B.E. , Dumbauld G.K.
Published: April 2012

Results of laboratory investigations of the effects of drilling muds on oilwell cements are presented which show that relatively large quantities ofuntreated muds do not seriously interfere with the setting of cement slurries, but that relatively small quantities of treated muds seriously retard thesetting of cement slurries. Laboratory results also indicate that the harmfuleffects of contamination with treated muds can be counteracted by the additionof activated charcoal to cements. Also described is the successful use ofcement containing activated charcoal for the placement of plugs in open holeafter previous attempts with ordinary cement had been unsuccessful.

Introduction

The contamination of cement slurry by dilution with drilling mud has longbeen considered a cause of failure in oil well cementing. The cement slurrymust displace the drilling mud from the annulus between the casing and thewalls of the borehole, and it is probable that some mixing of the slurry andthe mud occurs even under the most nearly ideal displacement conditions. Holeenlargement, failure to center the casing in the hole, and formation of gelstructure in the drilling mud increase the probability of contamination. Insome cementing operations, such as the placement of a cement plug in open hole, considerable mixing of the mud and slurry is likely. Many cement failures whichcan be attributed logically to no cause other than contamination of the cementslurry by the mud attest the need of a better understanding of thisproblem.

Considerable attention was given to the problem of mud contamination ofcements about 20 years ago. The effects of field mud upon cement slurriesprepared with different amounts of mix water were investigated thoroughly, andthe data obtained were invaluable in determining the causes of the highpercentage of failure in oil-well cementing at that time and in bringing aboutimproved cementing results. Since then, many aspects of the problem havechanged, due primarily to advancements in cement and drilling mud technology.Today, several types of portland cement are used in well cementing and numerouschemical additives are used in drilling muds. An excellent report on theeffects of drilling mud additives on oil-well cements was issued during 1951 bythe American Petroleum Institute. Data in the report revealed that many mudadditives, notably organic materials in relatively small amounts, produce amarked effect on the properties of cements. Prior to this time, littleinformation has been available on the effects of chemicals commonly used in thetreatment of drilling muds upon the properties of cements. Another aspect ofthe problem of mud contamination of cements, which has received no attentionheretofore, is the possibility of producing a cement having propertiesunaffected by a reasonable amount of mud contamination.

T.P. 3396
Natural Gas in the Province of Alberta, Canada
Authors: Dougherty J.F. , Folger Anthony , Lowe Howard R. , Meyer Joffre , Trostel E.G.
Published: April 2012

The status of the natural gas industry in Alberta, Canada, is described withparticular reference to the current extent of natural gas reserves andpossibilities for additional development. Certain major fields are discussed asrepresentative of the types of gas accumulations within various broadgeographical divisions of the provinces. The estimation of the futureperformance of a gas reservoir is discussed as the basis for an estimate of thefuture availability of natural gas from presently known reserves. The futureavailability of the provincial reserves and the estimated future demand for gaswithin the province are described.

Introduction

This paper is a condensation of a detailed study of the natural gas reservesand the future availability of pipeline gas in the province of Alberta asprepared for Trans-Canada Pipe Lines Limited and presented in public hearingsat Edmonton and Calgary before the Petroleum and Natural Gas Conservation Boardof the Province of Alberta. The study began in October, 1950, and resulted inthe preparation of five volumes of data at the expenditure of more than 20,000man-hours. This paper is designed to afford a broad picture with detail limitedto a type example of both natural gas accumulation and future availability ofgas supply.

The province of Alberta has an area of 255,285 square miles which, for sakeof comparison, is 8,359 square miles smaller than the state of Texas. Naturalgas was first discovered in 1883 at the now abandoned Alderson well locatedsome 20 miles southeast of the town of Princess. The first gas in commercialquantities was found at Medicine Hat in 1890. During the last 68 years, 187localities have been discovered which are capable of gas production, and 73 percent of these have been found since 1945. Sixty fields currently are producinggas, including 22 non-associated gas accumulations.

Location of the oil and gas fields and prospects in the province of Albertais shown in Fig. 1, together with a list of the localities of measurable gas, Fig. 1A.

The estimated total provincial gas reserve as of Jan. 1, 1952, for the 10'Fields estimated, is 11.7 trillion cu ft proved and probable, and for the 187known areas capable of production is in excess of 16 trillion cu ft on a totalproved, probable, and possible basis. Five fields (Pincher Creek, Leduc-Woodbend, Viking-Kinsella, Cessford and Medicine Hat) are estimated tohave recoverable reserves of more than one trillion cu ft each. A sixth field, Turner Valley, was initially in this group, but its reserves have been depletedsubstantially. Twenty-four fields, of which the above mentioned six fields area part, have estimated gas reserves (including the possible category) in excessof 100 billion cu ft. These 24 fields account for 79 per cent of the totalprovincial reserves.

T.P. 3398
A Study of the Permanence of Production Increases Due to Hydraulic Fracture Treatments
Authors: Fast C.R.
Published: April 2012

In order to evaluate the ability of a Hydrafrac treatment to effect asustained increase in well production, data were accumulated on the first 65wells in 26 fields treated by Stanolind. Since these data were obtained fromsuch a large number of fields, it is felt that individual well or reservoircharacteristics do not affect the overall picture, as might be the case if thestudy were made in one field or one group of wells in a field. These data aretabulated in Table I and plotted on Figs. 1 and 2.

An analysis of Fig. 1 shows that at the end of six months, 75 per cent, or45, of 60 wells on which data were available showed a sustained productionincrease. At the end of two years, data were available on 25 wells. Of these,15 wells, or 60 per cent, showed a sustained production increase. At the end ofthree years, 55 per cent, or 10, of 18 wells had a production rate greater atthat time than before Hydrafrac treatment. The lack of information onadditional wells at the end of the third year is primarily a result of thesmall number of treatments conducted in the early stages of field applicationof this process. Production data on wells treated more than three years ago arelimited to so few wells that they were not considered.

Fig. 2 contains two plots of the production data from the wells surveyed, expressed as per cent of pretreatment production plotted against time in yearsafter treatment. Only the wells showing a sustained increase in production wereconsidered in the upper plot, while all wells on which data were available wereconsidered in the lower plot. The upper curve shows that two years aftertreatment, the production from these wells was 200 per cent greater than beforetreatment. Even after three years, these wells were producing at a rate thatwas 134 per cent of the pre-Hydrafrac production rate. When considering all ofthe wells treated from which data were available, it may be seen from the lowercurve that after two years over 150 per cent of pre-Hydrafrac production wasbeing maintained. The production from these wells did not decline to thepretreatment level until approximately two and three-fourths years aftertreatment.

The increased production shown on Fig. 2 is all net increased production, since the cost of Hydrafrac treatment of all wells was paid out during thefirst six months of production not shown on this graph.

T.N. 108
Measurement of the Permeability of Set Cement
Authors: Morgan B.E. , Dumbauld G.K.
Published: April 2012

Introduction

A satisfactory well-cementing composition must retain its fluidity longenough to be pumped into place; then it must develop within a reasonable lengthof time sufficient strength and impermeability to anchor the casing in positionand to form an effective seal between the casing and the formations. Theseproperties may be evaluated by pump ability, strength (compressive or tensile), and permeability tests.

Laboratory test procedures for the determination of pumpability time andstrength development have been outlined previously and are readily available, but a satisfactory and convenient laboratory procedure for the measurement ofthe permeability of set cement has not been developed heretofore.

Some permeability data have been obtained previously by passing air throughdried cement specimens. Such a procedure is unsatisfactory because the dryingof set cement alters its physical and chemical properties and subjects it toconditions dissimilar to well conditions. A more realistic method would be onewherein the cement remains water-saturated during the aging period and thepermeability is measured with water. Such a procedure, outlined below, has beenused by the authors for the past four years to evaluate well-cementingcompositions.

Permeability Test Procedure

The brass mold, shown in the upper left-hand corner of Fig. 1, is cleansedwith emery polishing paper and placed on a flat plate and the test slurry ispoured into the mold. The slurry is puddled several times with a stirring rodand levelled off with a spatula. Another flat plate is placed on top of themold to complete the enclosure before the mold is placed under water at thedesired curing temperature. After the cement slurry has aged for the desiredlength of time, the mold containing the set cement is taken from the waterbath, the cover plates are removed, and the specimen is cooled under water toroom temperature. The faces of the set cement (in the mold) are brushed under astream of water to remove the glazed surface and foreign matter.

T.N. 120
Errors in Calculation of Gas Injection Performance From Laboratory Data
Authors: Craig Forrest F.
Published: April 2012

Both early and more recent laboratory measurements of gas-oil relativepermeabilities were made by subjecting oil-saturated cores to external gasdrives. In these runs it was generally assumed that the flowing gas/oil ratiowas constant at every point throughout the core. Using this assumption, theresulting equation for the gas-oil relative permeability ratio becomes

(Equation 1)

where Q is the flow rate at the producing end of the system. This relativepermeability was then specified for the average saturation of the core. Theassumption and resulting equation fail to recognize that in an external drive, the oil flow rate varies from zero at the injection end to a maximum at theproducing end. The assumption also fails to consider the existence of asaturation gradient during an external drive. This saturation gradient is duesolely to non-steady-state flow.

Some authors have used this erroneous method of calculating relativepermeability ratios from external drives. Other authors have used relativepermeability ratios in calculating expected field performance by externaldrive, using Equation (1) and making the incorrect assumption that thesaturation is uniform within the driven portion of the reservoir.

To find the correct relation between the relative permeability ratio at theaverage saturation and the produced gas/oil ratio, the insertion in Equation (1) of a factor, F, to adjust it for oil velocity gradient has been considered.The equation then takes the form

(Equation 2)

Assuming that the oil velocity is directly proportional to the distance fromthe injection point leads to the conclusion that, for a linear system, theaverage oil velocity is one-half that at the producing end. Thus, the averagegas/oil ratio is twice the produced gas/oil ratio, and Equation (2) istransformed into

(Equation 2a)

However, here again the existence of a saturation gradient is notrecognized.

The produced gas/oil ratio is related to the relative permeability ratio atthe saturation of the outlet end of the system.

T.N. 126
Ionic Double-Layer Conductivity in Reservoir Rock
Authors: Winsauer W.O. , McCardell W.M.
Published: April 2012

The abnormal conductivity found in shaly reservoir rocks containing anelectrolyte is shown to be a consequence of the electrical double layer in thesolution adjacent to charged clay surfaces. This increased conductivity resultsfrom a higher concentration of ions in the double layer than in the solution inequilibrium with the double layer. It is shown that the magnitude of theincreased conductivity of a shaly reservoir material is influenced by theconcentration and type of ions in the equilibrium solution as well as by thecolloidal nature of the rock.

Introduction

An important factor in the quantitative interpretation of the electric logis the resistivity factor of reservoir rock. The resistivity factor is definedas the resistivity of the rock when completely saturated with an electrolytedivided by the resistivity of the electrolyte itself. In the normal case, theresistivity factor for a particular rock sample is independent of theresistivity of the electrolyte and reflects the pore geometry of the rock.

In 1949, Patnode and Wyllie showed that in some cases the resistivity factoris not constant, but instead varies with the resistivity of the electrolyticsolution. It was shown that clean sands behave normally - i.e., that theresistivity factor does not vary with resistivity of the electrolyte - but thatsands con taining shale and clay may exhibit abnormally low resistivity factors when thesolution used to saturate them is of fairly high resistivity. At lowresistivities of the electrolyte, the resistivity factor for a shaly sandappeared to approach a normal behavior. It is evident that the resistivityfactor of a shaly sand is dependent upon factors other than pore geometry whenthe solution used to saturate it is of high resistivity.

Patnode and Wyllie, and later de Witte, assumed that the conductivity of ashaly sand saturated with an electrolyte could be represented as the sum of twoquantities. One of these was assumed, in effect, to be the conductivity whichwould be expected if the sample were a clean sand, and the other was assumed tobe a conductivity inherent in the sample itself. The latter was supposed to beconstant for a given rock sample regardless of the solution used to saturateit. The source of this added conductivity was ascribed to "conductivesolids."

In actual practice, the effect of the abnormal behavior of shaly sands is ofminor importance except when the resistivity of a formation such as a sand ishigh. Thus the effect is more important when the sand is saturated with adilute brine than when it contains a more concentrated electrolyte. The effectis also more important when the sample contains oil or gas than when itcontains only saline water.

T.P. 3565
Some Theoretical Considerations of Tilted Water Tables
Authors: Yuster S.T.
Published: April 2012

An analysis has been made of the factors responsible for tilted fluidcontacts in petroleum reservoirs. The factors are static and dynamic with theformer being controlled by those variables responsible for the capillary riseof fluids, and the latter include rate of formation tilt and hydrauliccirculation. The explanation that rate of formation tilt may be responsible fortilted contacts appears untenable. The role of some of these factors in themigration, fractionation, accumulation, and possibly the prospecting for oil isindicated.

Introduction

While it is generally considered that the segregation of gas, oil, and waterin a petroleum reservoir results in approximately horizontal planes separatingthese phases, there are factors which modify this simplified picture to a verygreat extent. Some of these factors are static, and the departure of the fluidinterfaces from horizontal may represent a static equilibrium. Some of thesefactors may be dynamic and the interface positions may be non-equilibrium andrepresent a steady state condition. Of course combinations of these twosituations may also exist. The reasons most commonly given for this behaviorare hydraulic circulation of fluids, change in character of the formation, anda rate of tilt of the formations more rapid than the rate at which the fluidsmay re-establish an equilibrium. Russell's Principles of Petroleum Geologycontains an extensive discussion of tilted fluid interfaces and theirimportance in the migration and accumulation of petroleum. Russell citesexamples of tilted water tables at Lance Creek, Wyo.; Rock River, Wyo.; CutBank, Mont.; Cushing, Okla.; and Graham, Okla. Also given was the Wasson Fieldof West Texas which has saucer shaped oil-water and gas-oil interfaces with thesaucer being deeper in the case of the oil-water contact. The Bradford Field inPennsylvania has a tilted water table. San Ardo, Coalinga Nose and some otherCalifornia fields have tilted contacts. A recent paper by King Hubbertdiscusses the effect of hydraulic circulation of the water underlying the oilin a given stratum and its implications in the accumulation of and drilling forthe oil.

The foregoing would indicate that tilted fluid interfaces are not uncommonand that it would be of importance to understand the forces which areresponsible. Further, it would be of interest to examine certain idealizedmodels of situations which may cause tilting with the thought in mind ofderiving relationships between the important variables. These relationships mayonly hold exactly for the models assumed but the results may applysemi-quantitatively to actual formations and at least indicate trends. Thediscussion will be divided into the effect of static factors and the effect ofdynamic factors.

T.P. 3564
The Estimation of Water Injection Profiles From Temperature Surveys
Authors: Nowak T.J.
Published: April 2012

The heat flow processes determining the injection and shut-in temperaturelogs in a water injection well have been analyzed and the theoretical basis fordetermining the water injectivity profiles from the temperature logs has beenpresented. Both the injection and the subsequent shut-in logs are necessary toresolve the injection interval into relative water intake strata; the former, to provide an accurate estimation of the thicknesses of the strata, and the latter to indicate themajor and minor intake rates into the strata. A procedure is described forestimating the injectivity profile from the temperature logs and is applied toseveral temperature logs. For a water injection well, a comparison is made ofthe injectivity profiles obtained from the core analysis, the spinner survey, and the temperature logs.

Introduction

In secondary recovery of oil by water flooding, the injectivity profile isneeded to obtain diagnostic evaluation of water intake distribution over theinjection interval. If the distribution is unfavorable among the variousstrata, corrective measures can be taken to provide better control.

Numerous methods have been developed for determining the injectivity profilefrom water velocity measurements in well bores. Often, dependence is placedupon core analyses and/or electric logs for estimating the relative waterintakes over the injection interval. In many cases, the temperature log methoddescribed herein will give results more diagnostic than those obtained throughuse of the other available methods inasmuch as it is based upon the study oftemperature disturbances in and around the well bore as a function of waterflow in the well bore and in the formation.

This method is the result of analyses of a number of temperature surveysmade in water injection wells to determine the point of entry of the water intothe formation. The material in this paper is presented in two sections: thefirst deals with the theoretical study of temperature survey data, and thesecond deals with the field application.

T.P. 3637
Performance Predictions Incorporating Gravity Drainage and Gas Cap Pressure Maintenance - LL-370 Area, Bolivar Coastal Field
Authors: McCord D.R.
Published: April 2012

Data of a known statistical quality has been successfully used in a systemof conventional fluid mechanics equations essentially free of empirical"conformance" factors to predict early detailed field GOR's in areservoir where gravity drainage is important and oil and rock properties varyconsiderably. The system is useful where comparative recovery predictions forone or more cases of natural depletion and gas cap pressure maintenance areneeded and the reservoir is not too heterogeneous.

Introduction

Many authors, have examined various facets of the gravity drainage-gas cappressure maintenance problem over the last several years. Two of them, Burtchaell and Elkins, have published practical studies. In the case describedin the present paper the best development and operating plan for one of theimportant reservoirs of the Bolivar Coastal Field in Western Venezuela wasurgently needed. It was requested that sound comparative economics be presentedalong with an engineering evaluation of no additional drilling, maximumdrilling, several cases of gas pressure maintenance, of water flooding andcombination cases. A rapid analysis of the effect on recovery of the range ofcrude and rock properties indicated that none of the published methods usingaverage properties would yield adequate comparative predictions. This papercovers the predictive system developed to deal with natural depletion and gascap pressure maintenance.

The large amount of data available for this field permitted statisticallyreliable correlations to be made of most rock and oil properties, and theevident smooth areal variations of these properties encouraged the constructionof a lineal mathematical model of material balance and fluid flow equations, which could be manipulated by a modified iterative procedure. The manipulationis much more adaptable to computing machines than manually operated calculatorsand subsequent studies have been prepared for the IBM Card Program Calculator.A matrix as opposed to linear model has been tentatively worked out by othermembers of our group to deal with more heterogeneous reservoirs. It is moreadaptable to computers such as IBM-701 or the Remington-Rand Univac. In 1950, when the system reported below was developed, no rapid computing machines wereavailable to the author. Their existence and promise encouraged an initialapproach by hand.

Some details of oil and rock property correlation are included because thereare a surprisingly large number of medium-sized reservoirs in the world thatshow systematic property variations which are significant for a rigorousanalysis. All large reservoirs (over half a billion barrels recovery) withwhich the author is familiar contain at minimum a significant temperaturevariation.

T.P. 3653
PTSD-8: A Short PTSD Inventory
Authors: Hansen Maj , Andersen Tonny Elmose , Armour Cherie , Elklit Ask , Palic Sabina , Mackrill Thomas
Published: April 2012

Traumatic events pose great challenges on mental health services in scarcity of specialist trauma clinicians and services. Simple short screening instruments for detecting adverse psychological responses are needed. Several brief screening instruments have been developed. However, some are limited, especially in relation to reflecting the posttraumatic stress disorder (PTSD) diagnosis. Recently, several studies have challenged pre-existing ideas about PTSD’s latent structure. Factor analytic research currently supports two four factor models. One particular model contains a dysphoria factor which has been associated with depression and anxiety. The symptoms in this factor have been hailed as less specific to PTSD. The scope of this article is therefore to present a short screening instrument, based on this research; Posttraumatic Stress Disorder (PTSD) – 8 items. The PTSD-8 is shown to have good psychometric properties in three independent samples of whiplash patients (n=1710), rape victims (n=305), and disaster victims (n=516). Good test-rest reliability is also shown in a pilot study of young adults from families with alcohol problems (n=56).
Locus of Control in Nursing Students on a Problem-Based Learning Program: A Longitudinal Examination
Authors: Mert Hatice , Kizilci Sevgi , Uğur Özlem , Küçükgüçlü Özlem , Sezgin Dilek
Published: April 2012

In this survey carried out over a 4-year period we explored the changes perceived in the locus of control (LOC) of 58 nursing students enrolled in a baccalaureate nursing education program with an integrated problem-based learning curriculum. The results suggested that there was a statistically
significant difference in LOC between the first and second years. A significant difference was found in the mean scores of the students according to year in personal control, fatalism, and belief in an unfair world. But, when analyzed further, there were no significant differences according
to year in personal control and belief in an unfair world. However, a statistically significant difference was found in fatalism between the first- and third-year students. Implications for nursing training programs and curriculum development are discussed.