bluuebunny/crossref_metadata_2025 huggingface dataset:
A Series of Enthalpy-entropy Charts for Natural Gases
Authors: Granger George
Published: June 2014

Enthalpy-entropy diagrams are presented for natural gasses of 0.6, 0.7, 0.8,0.9, and 1.0 gravity over the pressure range of 5 to 10,000 lb. per sq. in. andtemperature range of 32 degrees to 700 degrees Fahrenheit. The charts indicatedirectly the work requirement and temperature rise for adiabatic compression ortemperature change for free expansion of natural gases.

Computation and Uses of Charts

The Mollier diagram in which the enthalpy (heat content) is plotted against theentropy with lines of constant temperature, pressure, and in some cases volume, has been found most convenient when dealing with the compression, expansion, and flow of fluids. In dealing with the flow of fluids, the sum of the increasein the enthalpy plus the increase in kinetic energy plus the increase inpotential energy of the fluid in flow, is equal to the sum of the heat and workadded to the fluid while flowing between the entrance and exit of the flowsystem.

In cases where there is no significant change in potential energy or in kineticenergy (velocity), it follows that the increase in enthalpy is equal to thetotal energy supplied to the fluid. Under such conditions the changes in theproperty of the fluid as it flows through a throttling valve, choke, or anyother similar arrangement, may be read directly from the enthalpy-entropydiagram by following a horizontal line between the known pressures.

When compression or expanding a gas by which means of a compressor or engine inwhich no heat is added to or subtracted from the gas, but only work done, thechanges in the properties of the gas may be determined along a vertical line ofconstant entropy between the entering and exit pressures. The power requiredfor the compression of the gas may be readily determined by converting theincrease in enthalpy into the desired units.

The enthalpy-entropy diagram for natural gases is to the gas engineer what thesteam diagram is to the steam-power engineer. For this reason it would beextremely convenient of a reasonably satisfactory enthalpy-entropy diagramcould be prepared as a function of the gravity of the gas. A careful study ofthe known properties of natural gas indicates that this is possible.

The effect of temperature upon the enthalpy at consistent pressure is expressedas the ?heat capacity? or ‘specific heat’ of the gas. The best available datafor natural and petroleum refinery gases indicates the relationship shown. Fromthis it is clear that the specific heat of natural gases is a function only ofthe gas gravity and the temperature at atmospheric pressure. The effect ofpressure on the enthalpy of natural gases is dependent upon the pressure-volume-temperature relationships.

T.P. 1747
An Introductory Discussion of the Reservoir Performance of Limestone Formations
Authors: Bulnes A.C. , Fitting R.U.
Published: June 2014

Field experience with limestone and sandstone production indicates theexistence of wide differences between the reservoir behavior of these two typesof formation. Little attention appears to have been given to the separate studyof the flow of fluids and the retention of fluids in limestones. This paperpresents data and arguments to demonstrate the existence of a difference?between the two types of formation, and urges the separate intensiveinvestigation of limestone reservoirs. All experimental data presented pertainto dolomitic limestone formations in West Texas and New Mexico.

Two kinds of porous media are recognized intergranular and intermediate.Intergranular rocks are those in which the porosity and permeability aredetermined by the geometrical properties and the sorting of the sedimentaryunits; intermediate rocks, those in which there is no direct relationshipbetween grain properties and the porosity and permeability. Limestones ingeneral are intermediate media. The partial relationship between porosity andpermeability of any class of porous media is represented by an area of finiteextent and definite shape on the permeability-porosity plane.

The horizontal and vertical variations of porosity and of permeability inlimestone and sandstone formations are discussed and compared.

Comparisons are made of connate-water content,. the relativepermeability-saturation relationship, and. capillary phenomena in the two kindsof rocks.

A number of tentative conclusions are drawn relative to the reservoirproperties of limestones; in particular,dolomitic limestones are oilbearing and apparently are oil productive in zones of permeability less than0.1 millidarcy, andprimary depletion (by gas expansion) oil saturationsmay be lower in dolomitic limestones than in sandstones.

Introduction

It is well known that the reservoir performance of limestones displays numerousirregularities when compared with that of sandstones, and that the departuresfrom "normal" behavior of limestones are more frequent and generallymore marked than in sandstones. This is particularly true of fracturedlimestones and those that have undergone considerable development of secondaryporosity.

A review of the literature of production research published during the past ISyears reveals a startling absence of theoretical and experimentalinvestigations directed specifically toward explaining and predicting theperformance of limestone reservoirs, even though such problems as theprediction of 'water encroachment and the estimation of ultimate recoveriescontinue at the. "inspired guess" stage. By far the greater part of theexperimental data reported pertain to measurements on sandstone core samples, while the theoretical studies, almost without exception, are developed from theassumption of an ideal porous medium and therefore seldom are applicable tolimestone formations.

T.P. 1791
Core Analysis Based on Vacuum Distillation
Authors: Beeson Carrol M. , Johnston Norris
Published: June 2014

The gravimetric-vacuum distillation method was developed to permit rapid andaccurate determinations of the oil-water ratios of small samples or sandscontaining little oil. In addition, the samples usually are so well cleaned andso little altered by the distillation at reduced pressure that rapidestimations of other physical properties may be made with the evacuatedcores.

Requiring only elementary glass-blowing technique, the distilling tubes andtraps used in determining oil-water ratios were easily fashioned from the usualglassware. A sketch and description are given of the necessary apparatus, including the cylindrical electrical heaters. The procedure, requiring about 40min., consists in raising the temperature and maintaining it between 6750 and725?F. for at least 10 min. while the pressure is held between 1 and 2 mm. Hg.The fluids condensed in the trap (cooled by a mixture of kerosine and solidcarbon dioxide) are separated in a centrifuge and the volume of water isrecorded. Determination of changes in weight with an analytical balance of allparts of the apparatus permits computation of weight of oil distilled and totalweight of oil recovered.

Introduction

In determining the oil-water ratios of core samples, distillation atatmospheric pressure has proved to be sufficiently reliable for samplescontaining moderate quantities of oil. Since small samples and sands withlittle oil are encountered, however, it appeared advisable to develop a methodthat would be applicable under these circumstances.

The gravimetric-extraction procedure" 6–9 undoubtedly is very reliable andcould be used in all tests, but the time consumed in the determination wouldoften delay field operations. This would be especially true when dealing withtight sands or viscous oils, both of which retard the extraction process.

Accordingly, the gravimetric-vacuum distillation method was developed in orderto combine the good features of both of the older methods; that is, accuracyand speed. By reducing the pressure, it was found possible to perform thedistillation at a temperature that permits the use of glass apparatus, allparts of which can be weighed on an analytical balance. Thus, the fluids may beremoved quickly from the core, the water is readily trapped and measured, andthe loss in weight of the core is easily determined. In addition, the totalweight of material condensed in the distilling tube and in the trap provides amethod of determining the oil-water ratio that is practically independent ofthe one involving the loss in weight of the sample.

The use of vacuum not only permits as much accuracy as does the gravimetricextraction process, but it actually allows an increase in speed over theatmosphericdistillation method, because of the time required to cool the metalpots from about 1200'F between runs.

T.P. 2017
Effect of Arsenates on the Viscosity of Drilling Muds
Authors: Craft B.C. , Moncrief C.M.
Published: June 2014

A bentonite-clay drilling mud when treated with tetrasodium pyroarsenateunderwent substantially the same reduction in viscosity and water loss as whentreated with the complex phosphates. The complex arsenate showed a slightlyhigher reversion after heating; the other arsenates showed poorviscosity-reducing properties.

Introduction

During the past 10 years the chemical control of drilling mud has become ofmajor importance in affecting the successful drilling and working over ofwells. The desired properties of drilling mud have been well established, andin obtaining these characteristics there has developed a large market forviscosity-reducing chemicals.

Viscosity reduction produced by humic acid, tannic acid, sodium silicate, sodium tannate, Calgon, and the complex phosphates has been described byLoomis, Ford, and Fidiam. The effects of treatment with complex phosphates andammonium polyphosphates on the rheological properties of muds were investigatedby Fancher and the alkali vanadates have been described by Williams.

Laboratory Investigations

It is the purpose of this paper to point out the effects of arsenates incontrolling the viscosity and gelling characteristics of a drilling mud.Viscosities and gel strengths were measured at room temperatures with a Stormerviscosimeter calibrated in centipoises and operated at 600 r.p.m. Water losswas determined at 80'F with the Baroid low-pressure wall-building tester at apressure of 100 lb. per sq. in. for 30 min. The hydrogen-ion concentration wasmeasured with a glass electrode. The bentonite-clay suspensions were preparedin the laboratory and allowed to age several days before testing.

T.P. 1944
Method for Determining Minimum Waiting-on-cement Time
Authors: Farris R. Floyd
Published: June 2014

A method is presented for determining minimum waiting-on-cement time, whichtakes into account the differences that exist between types and brands ofcements and such individual well conditions as depth, temperature, andpressure.

The basis for the method was determined by laboratory tests. Being a laboratorydevelopment, several steps were required to prove its merit. The first stepconsisted of laboratory tests designed to determine the minimum cement strengthrequired in wells. Basis was found for setting a minimum value of 8 lb. per sq.in. tensile strength. Next, it was shown by laboratory tests that the time to 8lb. per sq. in. tensile strength may be expressed as a function ofconsistometer stirring time to 100 "poises," the approximate relationbeing "the time to 8 lb. per sq. in. tensile strength equals the time to100 ‘poises’ times three." Next, it was shown that the time of maximumtemperature development in cement slurries, due to heat of hydration, is alsorelated to consistometer stirring time to 100 poises, but only by a factor ofapproximately two. It was shown also that the shut-in casing pressure willbuild up after cement is placed and register a maximum pressure atapproximately the same time the slurry down the hole attains maximumtemperature. From this and the relationships listed above, the general rule wasestablished that minimum waiting-on-cement time (time to 8 lb. per sq. in.)after casing cement jobs in any well is equal to the time when the shut-incasing pressure reaches a maximum, as measured from the initial mixing ofcement, times a factor of 1.5.

Cement plugs drilled in the field at the time prescribed by this formula werefound to drill "firm to hard," thus confirming the laboratorytests.

These tests prove that many of the present regulations for waiting on cementrequire a longer time than is absolutely necessary. Use of the method hereinproposed offers the possibili ty of a saving of $ 1200 per well.

Intoroduction

The length of time allowed for cement to set after casing is determined eitherby state-wide rules, field rules, or self-imposed rules written into drillingcontracts. In general, the time is dictated by experience and common practice.However, owing to differences in opinion and in experience of the variousgroups involved, waiting-on-cement time often varies from one area to the next.For example, an operator in an area where no rules exist may drill out ofsurface pipe at 24 to 36 hr., while another operator in another area may wait48 hr. or more to comply with state or field rules, although the depth of thewell, hole size, type of cement, and other data are identical. An even greaterdifference in practices will be found by making similar comparisons withrespect to oilstring cement jobs. Differences in waiting-on-cement times of 36to 48 hr. are common.

Further complicating the picture is the rather common practice of allowing morewaiting time for cement to set at the greater depths than is allowed at theshallow depths.

T.P. 1968
A New Method for Measurement of Oil Saturation in Cores
Authors: Boyer R.L. , Morgan F. , Muskat M.
Published: June 2014

This paper describes a new method for measuring the oil saturation of coresduring the course of fluid-flow experimentation. The method depends upon theaddition to the oil of a soluble tracer material that is the primary absorberof the X-rays incident upon the core. The paper includes a description of theX-ray equipment and intensity-measuring apparatus, calibration data for twocores, and results obtained with additional cores for various conditions of oiland water-flooding. The data and results are presented to show thepotentialities of the X-ray method at this stage of development rather than toestablish particular concepts pertaining to fluid-displacement mechanisms ofpermeable media. Further development of this method will include adequatepressure and flow-rate control in the liquid and gas-flow systems,.as well asadditional stabilization of the X-ray power supply.

Introduction

In the last several years a type of application of the' fundamentalpermeability saturation relationships has been developed which others greatpromise in the interpretation of general reservoir performance. In thesedevelopments no attempt is made to solve the detailed flow dynamics in actualoil and gas-producing systems. That problem still remains unsolved. But thepermeability-saturation phenomena are incorporated in the analysis of oilproducing reservoirs in a manner such as to reflect the true role they play incontrolling the gross reservoir behavior. In particular, they are introduced insuch a manner as to determine the gas-oil ratio of the production at any stageof depletion and, when combined explicitly with the so-called material-balanceprinciples in differential form, one can obtain a differential equationdescribing completely the average pressure and gas-oil-ratio history ofoil-producing reservoirs. While thus far they have been applied directly onlyto gas-drive reservoirs, they are susceptible of extension to partialwater-drive systems, and qualitatively the same principles are of value in thestudy of complete water-drive reservoirs. Moreover, in addition to giving ameans for computing the variation of the reservoir pressure and gas-oil ratiosvs. the cumulative production, they automatically lead to predictions of thegross ultimate recovery under natural depletion-and when properly extended theyprovide means for predicting the ultimate recovery under gas or waterinjection.

The data required for such applications are the initial fluid distribution inthe producing section, the pressure-volumetemperature data on the gas andliquid phases, and the permeability-saturation relationship for theoil-saturated zone. The former can be obtained with reasonable accuracy bymethods that are well established and available throughout the industry. Thepermeability-saturation data, however, involve techniques that are not at allstandardized.

T.P. 2124
Evaluation of Pressure Maintenance by Internal Gas Injection in Volumetrically Controlled Reservoirs
Authors: Patton E. Charles
Published: June 2014

A comprehensive discussion is presented of a proposed method for utilizing thedeterminable basic physical facts about tight, volumetric-type reservoirs andtheir contained fluids, to arrive at the feasibility of injecting gas thereinand to estimate the minimum about the profit to be derived there from. A methodis introduced for correlating laboratory relative permeability data with fieldperformance history, and a method of relating the one to the other so as toenable predictions to be made of future performance based on past performance.This incorporates the substitution into the material-balance equations of afactor designed partially to take into account deviations from ideal behaviorresulting from nonhomogeneity of the reservoir rock, the importance of thisfactor to the reliability of such predictions is not to be minimized.

A theoretical interpretation of the most dearly correct method of applyingflash and differential laboratory data in their appropriate places in thematerial-balance equations, and a set of symbols to accommodate the distinctionbetween these two different types of data is developed.

A set of equations for converting material-balance predictions directly to atime basis is given; a method of predicting the time at which the fieldeconomic limit will be reached, and a tentative method for predicting relativenumber of wells on the pump at any time under pressure maintenance as comparedwith primary performance have been described. These three concepts areprerequisites for the accurate evaluation of the economic benefits of pressuremaintenance.

The equations and methods described may also be utilized to predict therelationship between gas-production rate and time to serve as a basis fordesign of proper size gasoline or compressor plant to accommodate an entire oilfield, or to predict the most economically advantageous time to begin agas-injection project.

The sale of residue gas in connection with the operation of a reservoir bynatural depletion under some circumstances may prove economically superior topressure maintenance y gas injection in spite of the expected increases inultimate oil recovery by the latter type of operation. A situation such as thismay arise from the interrelationship of the many physical and economicvariables involved.

T.P. 2098
Volumetric Behavior of Oil and Gas from Several San Joaquin Valley Fields
Authors: Sage B.H. , Olds R.H.
Published: June 2014

The formation volume and volume of the liquid phase of oil and gas obtainedfrom four fields in the San Joaquin Valley have been investigated at pressures, temperature, and gas-oil ratios comparable to those encountered in underground?reservoirs. All the fields covered in this investigation yielded a product of agas-oil ratio in excess of 5000 cu ft per barrel and the gravity of the tankoil for the four fields in question varied between 52' and 63' API. The resultsof the investigation, together with analytical data concerning the compositionof the oil and gas, are submitted in tabular form. Rough correlations of theformation volume as a function of pressure, temperature, and gas-oil ratio andof the retrograde dew-point pressure as a function of gas-oil ratio, temperature, and gravity of tank oil are presented. It was not found feasibleto correlate simply the formation volume of the liquid phase as a function ofthe applicable variable. It is desired to emphasize that these correlations areconsidered applicable only to the range of conditions covered in thisinvestigation and for systems of similar nature and composition.

Introduction

Information concerning the physical properties of mixtures of oil and gas fromparticular fields have often been employed in predicting the situationsobtaining in underground reservoirs. One of the earlier studies of this naturewas the work of Beecher and Parkhurst, while a more recent study of theDominguez Field presented detailed volumetric data in the two-phase as well asin the single-phase regions. Although these studies were confined to individualfields, their results proved of value in application to other fields. It hasrecently been shown 3,4 that it is possible in the region of low gas-oilratios' to correlate the? volumetric behavior of naturally occurringhydrocarbon mixtures from a single geographical area with sufficient accuracyto be of industrial value. For this reason it is considered of interest tosubmit information concerning the volumetric behavior of oil and gas mixturesfrom four different fields in the San Joaquin Valley and, in combination withsimilar published data concerning mixtures of oil and gas from the Paloma fieldin the same area, to show rough correlations between the composition and thebehavior of materials from these fields.

T.P. 2153
A New Well-completion Technique
Authors: West Thomas S.
Published: June 2014

Completion and production data presented for three wells in the Oakville areaof Live Oak County, Texas, which were completed near the gas-oil or water-oilcontact, indicate that coning may not be as prevalent a cause of failure insuch cases as is commonly assumed. Failure in the cases discussed is indicatedto be due instead to:erosion of the formation,flowing out of mudfilter cake, orfailure of the cement.

An open-hole gravel-pack type ofcompletion procedure is proposed for preventing failures of this kind bypreventing movement of all solid material in the space in which completion ismade. Various combinations of layers of gravel, sand, and cement are utilizedfor this purpose.

Experimental results and theoretical discussion as to the applicability ofgravel pack completion are included.

Introduction

This paper is primarily a study of the reasons for failure of oil-wellcompletions near the gas-oil or oil-water contact, and suggests a procedure forincreasing the efficiency of this type of completion.

The value of improvement in completion effectiveness near the gas or water zoneis not confined, however, to wells of relatively thin oil columns. Thick oilcolumns become thin as depletion progresses. It would seem to follow that theminimum distance from the gas or water zone at which completion can be made ina new well indicates the limit to which depletion may be carried in a wellhaving an oil column of any initial magnitude.

Only four ways can be postulated in which high gas-oil or water-oil ratio caninitially occur if the zone exposed for production is within the oilcolumn:Failure of the cementing material.Vertical coning.Failure along the boundary between the cement and the wall of thewell.Failure of the formation comprising the wall of the well.

Cementing materials such as portland cement and plastics have reached a highstage of development. Failures of this type are probably due almost always toextraneous causes such as mud contamination rather than to faulty cementingmaterial.

Vertical coning can and obviously does occur. However, the usual occurrence ofthin impermeable streaks in sand sections and the success with which open-holedrill-stem tests can be made near the gas-oil contact suggest that over-alleffective vertical permeability, and in turn vertical coning, is less prevalentthan frequently is assumed.

Much has been written on failure by flowing out of the mud filter cake betweencementing material and the formation. A filter cake is always present if, priorto cementing, mud has come in contact with a permeable formation at pressuresexceeding the pressure head of the fluid it contains.

T.P. 2094
Potentiometric-model Studies of Fluid Flow in Petroleum Reservoirs
Authors: Lee B.D.
Published: June 2014

A simplification of the method of Hurst and McCarty for conductingpotentiometric model studies by the single probe method is presented along withexperimentally determined invasion patterns for certain idealized flowproblems. The analytical solution for one class of these problems is given.Finally, a general description is given of a newly developed instrument whichpermits direct mapping of flow lines and determination of transit times inpotentiometric-model studies.

Introduction

The object of this paper is to present:A simplification of the method of Hurst and McCarty for conductingpotentiometric-model studies of oil and gas reservoirs by the single probemethod.Results of a series of studies of certain idealized flow problems and thegeneral conclusions to be drawn therefrom.A description of a dew instrument, the Chronocartograph, which greatlyreduces the labor and time required for conducting potentiometric-modelstudies. Certain general conclusions may be drawn as results of theinvestigation of the idealized flow problems.

They are:Injection and extraction areas should be separated by as great a distance asconditions permit since, in general the recovery prior to first breakthroughtends to vary as the square of this distance.Little advantage is to be gained by use of more than eight injection wellsor groups of injection wells for the case of circular productive limits.Elongated shapes if productive limits are best exploited by injection on theextended major axis only, with a line of extraction wells lying on the majoraxis.The use of peripheral injection wells for elongated shapes is permissible, if necessary, but requires extension of the lines of extraction wells.

The exploitation of an oil or gas field is effected either by the expansion ofthe gas and oil, or by their displacement by another fluid. Both methods may beused simultaneously. When the displacement of the oil or gas is the controllingfactor there arises the problem of mapping the progress of the boundary betweenthe fluid in place and the displacing fluid. This problem is of particularinterest in the operation of a cycling project in a gas-condensate field, wherethe wet gas is produced from one or more wells, commonly called ?extractionwells?. This wet gas is taken into a processing plant where the condensate isremoved. The remaining "dry" gas is injected back into the field through one ormore wells, the gas for future use and also to maintain the pressure in thefield.

T.P. 2262
Some Theoretical Aspects of Well Drainage and Economic Ultimate Recovery
Authors: Moyer Vaughn
Published: June 2014

A method for incorporating well drawdown effect into reservoir calculations ispresented in detail, together with examples of its use for widely divergentconditions that could be normally encountered in oil reservoir sands. Tentativeconclusions as to the effect such factors as permeability, producing interval, well spacing, or well damage caused by completion or repair practice could haveupon economic ultimate recovery are reached. It is carefully pointed out thatthe conclusions reached are subject to limitations indicated in the text, andplaced upon all calculations made in the paper.

Introduction

Papers have been presented I-a in which theoretical depletion histories forreservoirs under equilibrium conditions and no appreciable well-bore drawdownpressure are determined. However, except for a limited number of cases, appreciable drawdown pressures in a well bore exist, and pressure andsaturation gradients consequently vary throughout a reservoir.

This paper is an attempt to incorporate well-pressure drawdown into reservoirhistory, and to analyze certain factors, such as those involving recovery, wellspacing, and productivity index, from the standpoint of permeability anddrainage radius. By incorporation? of drawdown into reservoir history, it isbelieved that theoretical considerations will more closely approximate actualreservoir behavior experienced in an oil field. For purposes of simplification, a solution gas-drive typefield, without primary gas cap, has been selected.

Basic Data and Assumptions

Details of equilibrium saturation conditions for no drawdown production forvarious pressures in a reservoir are determinable by methods described byseveral authors permitting the construction of a curve of oil saturation vs.pressure for any selected combination of initial interstitial water andhydrocarbon saturation (Fig I). This curve is then a description of equilibriumsaturation conditions at any given pressure in a reservoir.

Developing the above, details of saturation and flow permeability may thus bedetermined for any increment or portion of a well drainage area or reservoir, In this manner the effect of pressure differential (draw down) may beincorporated into reservoir and well drainage considerations.

It is pointed out that this method thus makes use of no-drawdown equilibriumproduction data, superimposing a drawdown effect upon them. It also assumesthat net flow conditions in any considered increment of reservoir are notmaterially altered by the entrance of fluids from other increments into them, but approach equilibrium for the existing pressure and saturation (i.e., eachincrement behaves in more or less independent fashion, dependent largely uponthe equilibrium considerations mentioned above).

T.P. 2201
Radioactive Markers in Oil-field Practice
Authors: Doll H.G. , Schwede H.F.
Published: June 2014

This paper describes a method to provide identification of particular depths ina borehole through the use of radioactive markers. The correlation of a marker, placed in the wall of a borehole, with known points of the electrical log andwith the casing collars in the cased hole permits accurate positioning of toolswith respect to a formation, regardless of absolute depth. Such a process isparticularly useful in gun perforation of a casing in a well. Technique andequipment are discussed and illustrated. Examples are given of practicalapplication in the field.

Introduction

During the past decade the search for petroleum has increased the importance oftesting zones at depths in wells which have become progressively deeper. Thedevelopment of new techniques, such as electrical logging, has permitted theidentification of producing formations which consist of comparatively thinstrata. When thin beds are to be produced at great depths, the problem ofpositioning tools accurately to place the well in production becomesacute.

Continuous consideration is being given in the petroleum industry towards theimprovement of depth measurements in a borehole. The accuracy in absolute depthmeasurements, whether made in an open or cased hole, whether determined by a cable or a drill pipe, depends upon a number of factors, such as tension, temperature, and calibration.

For example, the effects of tension from the weight of 10,000'Ft of drill pipeand the thermal expansion of this length of pipe, where its average temperaturehas increased 50'F, will produce an elongation as much as 8 ft. The effects ofsuch factors can be minimized through the use of care in depth measurements, the application of corrections based on experience, and continuous calibrationor checking.

The fact that different methods and different tools are used to determine thedepths of formations in wells will sometimes give rise to a difference betweenmeasurements. It is evident that an important requirement in a well is theability to locate at will any subsurface point. While absolute depthmeasurements have improved in recent years, it is reassuring to have othermeans to verify, for example, that a casing is perforated at a particular placewith reference to a zone within a formation. Such a check on measurements maybe had by placing a reference marker at a point known with respect to theelectrical log of the borehole. That point is usually chosen to be in proximityto the zone to be perforated. Thus, only short relative depth measurements aremade and any inaccuracy becomes very small and of minor importance.

T.P. 2261
Preventing Corrosion in Gas-condensate Wells
Authors: Menaul P.L. , Spafford P.P.
Published: June 2014

This paper discusses the most dangerous form of corrosion encountered incondensate well oil production, the discovery of the agent causing thiscorrosion and the remedial chemical treatment proved effective by field use.The injection of ammonium hydroxide, even as little as one quart per day, hasproved effective in preventing gas-condensate well corrosion. The injection of"Bone oil" is applied to wells producing brines containing calcium andmagnesium salts.

Introduction

The severe corrosion of equipment in high pressure gas condensate wells hasbeen a problem for several years and numerous papers have been presented on thesubject.

The term ?gas condensate? or ?distillate well? is applied to a distinctvarieties of hydrocarbon producing well, the characteristics of these wellsbeing high bottom-hole (formation) pressures and temperatures and high gasproduction. These wells usually produce about 40 gal of water per million cubicfeet of gas and the gas contains from 0.1 pct to 2 pct carbon dioxide. In theoperation of this type of well, the operators soon noted severe internalcorrosion of the pipe carrying the production. In some instances the welltubing has been found to be corroded to perforation in eight months. The highwell head pressure of 2500 to 8000 psi makes any weakening of the wellequipment by corrosion extremely hazardous. Bursting of the wells equipmentresults in very expensive repair operations and may result in the loss of thecostly well, or even loss of life.

In November 1944, a gas-condensate well in a Gulf Coast field producing from9500'Ft showed a tubing leak. The well was ?killed? by filling it with mudthrough the tubing, and then the tubing was pulled. Corrosion was found to havecaused several perforations in the tubing, Fig. 1. While the mud was beingcirculated to kill the well, a high pressure jet from the corroded hole in thetubing perforated the casing and damaged the well to the extent that the costof repairs amounted to $75,000.

In November 1944, another gas-condensate well in a Gulf Coast field producingfrom 11,400'Ft. showed tubing failure. This well had been producing an averageof 2,500,000 cu ft of gas daily for two years. In the workover of this well, itwas found that a hole one inch in diameter had corroded though the tubing andthat corrosion had reduced the wall of the tubing to less than half thestandard thickness over large areas of the interior of the tubing. It was foundthat corrosion had also caused two leaks in the casing. After four months spentin an attempted workover failed to make the well safe for further production, the well was plugged and abandoned at a total low or $300,000.00.

T.P. 2229
Well Flowmeter for Logging Producing Ability of Gas Sands
Authors: Vincent R.P. , Leibrock R.M. , Ziemer C.W.
Published: June 2014

The Stanolind flowmeter, which employs a hot-wire anemometer connected in aWheatstone bridge circuit, has proved useful for determining the relativeproductive ability of individual sand members of gas wells. The operation ofthis instrument in measuring gas velocities in the well bore above eachproducing member has provided both a direct and accurate means of analyzingreservoir performance.

Results of tests conducted with the well flowmeter in the Hugoton gas field ofwestern Kansas have indicated some rather unusual production characteristics.In two cases it was found that all or the greater part of the total gasproduced was coming from one section in wells where four "pay" sectionshad been perforated individually. These actual measurements contradict in manyinstances the indications of data obtained from electric logs and from coreanalysis; the fact that these latter sources often give incorrect results, demonstrates the necessity of a method, such as is provided by the wellflowmeter, for accurately determining the amount of gas coming from eachproducing member.

Introduction

In any gas well where a number of pay sections have been perforatedindividually and are producing to a common outlet, the question arises as tothe relative amounts of gas being passed through each set of perforations. Inthe past it has been the policy to depend on core analysis to estimate relativeproductivities, or, where the sections were not cored, to obtain some idea ofproduction characteristics from electric log studies. The weaknesses in thesemethods are readily apparent and indicate the need for more reliable means ofmeasuring gas flow from each zone. The Stanolind flowmeter was developed forthis purpose.

Preliminary tests were made with the instrument in the Katy gas field nearHouston; however, the bulk of the routine work with the well flowmeter has beenconfined to the Hugoton gas field in western Kansas, where results obtainedhave been encouraging.

A description of the instrument, the field technique employed in testing, and afew of the results obtained in the Hugoton area are discussed in thispaper.

Description of Instrument

The well flowmeter is 1 ? in. od and 7 ft long; it is entirely self-contained, can be run through tubing as small as 2 in. id in wells with high pressure(4500 psi) and temperature (210'F) and is lowered on a wire line commonly usedfor other instruments of the bottom-hole type at falling rates up to 500'Ft perminute. It will detect gas flow as low as 10'Ft per minute linear velocity, andyet withstand and record velocities of 1000'Ft per minute without damage to thedetecting element. Killing the well is not required nor desirable for running aproduction profile when using the instrument and it is necessary to stop flowfor only a short time.

T.P. 2263
Engineering Characteristics of the Gulf Coast Continental Shelf
Authors: Willey M.B.
Published: June 2014

The Louisiana Continental Shelf is a submarine area extending offshore asmuch as one hundred miles. The Gulf bottom in this region varies considerablyin extent, profile and composition and consists largely of sedimentarydeposits, predominantly those of the Mississippi River. It is very young in ageological sense.

Up to the present time few major structures have been erected offshore inthe Gulf and no comprehensive preliminary tests have been carried out. Resultsof pile-driving tests are of little value as actual bearing capacities farexceed the dynamic resistance to driving as measured by conventional formulas.Soils encountered are, with few exceptions, cohesive and piling consequentlydevelop their supporting power through surface friction.

Because of the time required and relatively high costs, no complete loadtests have been made. The results of those tests which have been made, andinformation obtained from pulling piling in one structure, indicate that designloadings could be considerably increased, and it is contended thatcomprehensive preliminary investigations including an actual load test, combined with borings and examination of materials encountered by competentsoil experts, would effect economies in design far in excess of their cost.

The Louisiana Continental Shelf - General

The Louisiana continental shelf is a submarine area which extends seawardfor as great a distance as one hundred miles off the present shoreline. TheGulf bottom in this region is characterized by low slopes and its outer marginis outlined by the fifty fathom (300'Ft.) contour. South of the margin of theshelf the slopes steepen abruptly in the continental slope zone and plunge intothe deeps of the Gulf of Mexico.

The engineer who is called upon to design a structure on this shelf isconcerned only with the uppermost portion to a depth generally not to exceed100 to 15? ft. This layer is very young in a geological sense, and it has thecharacteristics usually associated with infancy. A few of these are lack ofstrength, lack of uniformity, and high water content. It consists of thesedimentary deposits of the various rivers and streams entering the Gulf. Thesestreams are all heavily burdened in quantities sufficient to fill the areas attheir mouths, were it not for the fact that continual subsidence, equal orgreater in amount and acting directly opposite, prevail over the sedimentaryworkings of the streams. This subsidence has been estimated by geologists to beat the rate of at least one foot per century.

Influence of Mississippi River

The Mississippi River, which has been the predominant factor in theformation of practically all the Louisiana continental shelf, is one of tworivers flowing into the Gulf that have been able to build protruding deltas.The Mississippi has done so because of its enormous size and load. It depositssediments in amounts sufficient to replace and actually gain on the amount ofsubsidence.

T.P. 2323
Oil-Shale Resources of Colorado, Utah and Wyoming
Authors: Belser Carl
Published: June 2014

This paper summarizes the data on the oil-shale deposits of westernColorado, Utah and Wyoming. It is based on published reports by the U. S.Geological Survey, on the results of core drilling and sampling by the Bureauof Mines, on the drill cuttings from the General Petroleum well, on a recentunpublished report by the Geological Survey on the geology of Naval Oil-ShaleReserves No. I and No.2, and from information supplied by geologists of privatecompanies who have investigated the Green River formation. The paper alsocontains a revised estimate of the grade and tonnage of minable thicknesses ofoil shale of western Colorado.

Introduction

The oil shales of the Green River formation of Colorado, Utah and Wyomingcomprise an important natural resource for the production of synthetic liquidfuels. The oil shale in western Colorado generally is more amenable toexploitation, apparently richer, and probably more persistent than in Utah orWyoming.

Work is now being done by the Bureau of Mines near Rifle, Colo. to ascertainthe best procedures for mining the oil shale, producing shale oil from the oilshale, and converting the oil into more salable products. As a part of thisprogram, holes were drilled and cores were taken of the oil shale on NavalOil-Shale Reserve No. 1. In addition, drill cuttings were obtained from a welldrilled through the Green River formation by the General Petroleum Co. about 18miles northerly of the Naval Oil-Shale Reserve.

Geology

During middle Eocene time a broad, shallow body of water, now called UintaLake, covered northwestern Colorado and east-central Utah; a similar lake, known as Gosiute Lake, was in southwestern Wyoming. Each of these contemporarylakes was bounded by high hills; the drainage was to the south. The Green Riverformation was laid down as sediments in the bottoms of these lakes.

T.P. 2358
Some Results of Gas and Water Drives on a Long Core
Authors: Holmgren C.R.
Published: June 2014

A large consolidated sand core was used in this investigation. Four groupsof experiments inc1uding gas drives, water drives, and water drives combinedwith gas injection, were made.

The results of the gas-drive experiments indicate that greater ultimaterecovery may be obtained by higher pressure gradients. However, otherconsiderations challenge the absolute veracity of this conclusion. Resultsindicate that with connate water present and a low pressure gradient during agas drive, less gas is required to produce a given amount of oil. Thesaturation gradient determined during a gas drive is presented.

Results of the water-drive experiments indicate that the recovery of oil isnot a function of either gradient or input rate. The presence of initial gassaturation resulted in a slightly lower final oil saturation. Injection ofsufficient gas to maintain the initial gas saturation during a water driveresulted in lower final oil saturation.

Introduction

With the demand for petroleum products reaching an all-time record high andthe location and exploitation of new reserves becoming more difficult andexpensive, the oil industry must look to more thorough and efficient methods ofproducing the petroleum already located.

Much of the previous work along these lines is exploratory and suggests amore complete investigation. For example, a great amount of laboratory work hasbeen done on flooding sands initially saturated 100 pct with oil. Since sandssaturated 100 pct with oil rarely, if ever, exist in nature, and because thewater content is a vital factor in the ultimate recovery from the sand, laboratory investigations on cores without water must be supplemented bycomparable work on cores with water present.

Other investigators have done a considerable amount of laboratory work usinggas and water drives. Krutter and Day have reported results of investigationsusing cores saturated 100 pct with oil and have concluded that "theultimate recovery obtained, using air drive, from a completely oil-saturatedcore depends on the pressure gradients used. The higher the pressure gradient, the greater will be the recovery until a certain pressure range is reachedabove which the reward of increased recovery is much smaller for similarincrements in pressure."

T.P. 2403
Core Analysis of Fractured Dolomite in the Permian Basin
Authors: Atkinson Burton , Johnston David
Published: June 2014

Evaluation of Ellenburger reservoirs in West Texas has beep an uncertainmatter at best because of the lack of cores and suitable core-analysis method.Large amounts of oil are produced from sections from which sample cuttings areobtained that contain little porosity and no oil saturation. It has long beenrealized that the formation in some areas contained numerous fractures andsolution cavities that probably contained the major part of the oil present butthe magnitude of the porous system containing oil has been unknown.

Diamond coring equipment, used in the mining industry for many years, hasbeen developed for oil-field use to obtain high core recovery in fractureddolomite that is not possible with conventional coring equipment.

A 36-ft section of the core recovered from a fractured Ellenburger reservoirwas analyzed by a unique but simple method to obtain the first definiteevaluation of one section of the producing formation. The cores and the methodof analysis used are described and the results are discussed in somedetail.

Discussion

The first successful known analyses of cores recovered from the Ellenburgerformation in the Permian Basin area were made on cores recovered with the useof diamond core heads. Conventional coring methods previously used have had lowcore recovery and standard methods of analysis have proved to be inadequate forevaluation of those cores that were recovered.

Core Description

The Ellenburger formation to be discussed was cored using diamond core headsand oil-base drilling fluid. Of the total 103 ft cored to a depth of 8893 ft inthe Ellenburger, 99 ft or 96 pct was recovered.

The dolomite cores were described as gray to white, crystalline to coarselycrystalline, with chert and calcite inclusions. Occasional shale partings 1/8to 1/4 in. in width were noted. A small amount of green clay was found in someof the coarsely crystalline material. No intergranular porosity was found byinspection in any of the cores.

The core was highly fractured over most of its length with not more than twocontinuous feet that failed to contain fractures. The fractures were nearlyvertical and varied in width from those barely visible to as much as onemillimeter.

T.P. 2432