bluuebunny/crossref_metadata_2025_split huggingface dataset:
Volumetric Behavior of Condensate and Gas From a Louisiana Field - II
Authors: Sage B.H. , Reamer H.H. 
Published: April 2012

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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