Because of unfavorable wetting conditions much residual oil is left when a porous material is flushed by water. Methods suggested to change reservoir wetting to improve oil displacement efficiency are generally expensive. The present laboratory study was undertaken to gain all understanding of the factors which determine reservoir wettability, and to find out if oil displacement efficiency might be improved by a wettability change accomplished at low cost in an oil reservoir.
Contact angle measurements were made on mineral surfaces using several sets of reservoir oil and water samples. Results of the contact angle studies suggest that reservoir wettability may be primarily determined by natural surface-active substances present in the reservoir fluids. The effect of changing salinity and pH of the water phase was studied. The results suggest that gross changes in preferential wettability might be accomplished by injection of water containing simple chemicals to alter pH or salinity in the reservoir. Such treatment could be much less expensive than injection of commercial surface-active agents.
Waterflood tests have also been made using synthetic cores and oil and water having wetting characteristics similar to those of reservoir fluids. Cores initially oil-wet were flooded in such a way that they were made preferentially water-wet by the advancing flood water. This reversal in preferential wettability achieved greater oil displacement efficiency than when either oil-wet or waterwet conditions were maintained throughout the flood. For the systems studied, the higher the oil viscosity the greater the percentage improvement obtained over conventional waterflood recovery. This suggests that a flooding process making use of wettability-reversal may extend the oil viscosity range over which water flooding is attractive.
Because a precise adjustment of reservoir wettability does not seem to be required, and because altering the pH or salinity in some reservoirs may be inexpensive, it appears that a waterflooding process employing wettability- reversal could find successful field application.
This paper presents the results obtained after calculating matches of the observed pressure performance of five fields completed in a common aquifer. A general description of the Central Basin Platform area in West Texas in which the five fields, Andector, Embar, Martin, TXL, and Wheeler, are located is contained in the paper. The method of utilizing the electric analyzer to calculate simultaneously matches of the observed pressure performance of the five fields is outlined. The determination of boundaries of pressure communication is discussed and the extent of pressure interference between fields consistent with the configuration of the area aquifer is shown graphically.
Anomalies in the pressure performance of the Andector Ellenburger Field resulted in an investigation of pressure interference between several Ellenburger fields located on the Central Basin Platform in West Texas. Four fields, Embar, Martin, TXL, and Wheeler, were found to contribute significantly to the pressure drawdown at Andector.
An initial investigation of the pressure performance of the Andector Ellenburger Field revealed that the reservoir pressure could not be matched by the calculation technique usually applied to water drive reservoirs. In the past, many have advanced the opinion that fracturing in the Ellenburger was a local condition restricted to the immediate uplifted area around the field, in which case each field would in all probability be surrounded by its own relatively small aquifer. Following several unsuccessful attempts to account for the pressure performance at Andector, a system assuming a common aquifer involving several fields in the immediate vicinity of Andector was placed on the electric analyzer and the effect of inter field interference was noted. A refinement of the initial analyzer calculations involved the determination of the approximate boundaries of the aquifer, the calculation of detailed matches of the pressure performance of the interfering fields, and an evaluation of the degree of communication between fields.
Geology and Development
The fields considered in this work are located in the Central Basin Platform, a north.south trending structural feature in West Texas lying between the Delaware Basin to the west and the Midland Basin to the east. The locations of various individual Ellenburger fields in this general are shown in Fig. 1 with the five major fields which appear to be definitely intercommunicating colored in black and located in the circled portion of the figure.
The various factors considered in recommending the initiation of a gas injection project in the southern portion of the Cedar Lake Field are discussed. Performance history under gas injection operations is reviewed and these data are analyzed, utilizing both the material balance method and the fractional flow and frontal advance expressions.
Results of the analysis of the performance data indicate that the injected gas has contacted and affected at least 60 per cent of the reservoir and a substantial increase in ultimate recovery can reasonably be expected. By holding the reservoir pressure appreciably above the bubble point, the well productive capacities have been maintained substantially above the level predicted for primary operations.
The analysis of the Cedar Lake project suggests that in certain limestone reservoirs, at least, the probable success of gas injection cannot be predicted simply from observation of permeability distribution throughout the pay section, as indicated by core analysis data, on either one or a number of wells. Further, the performance of this particular project fails to indicate any basis for classifying carbonate reservoirs in general as being inherently unsuited to a dispersed type gas injection program, thus indicating that each reservoir should be considered on its own merits, regardless of the composition of the reservoir rock.
Early in the life of the Cedar Lake Field, an extensive data gathering program was initiated to provide an accurate record of reservoir performance characteristics. From the study of these data it was apparent that there was a critical need for supplementing the natural reservoir energy in order to maintain well productivities and obtain the maximum ultimate oil recovery. Accordingly, detailed engineering studies were made of the various methods of secondary recovery which might be applicable. As a result of these investigations, the decision was made to initiate a gas injection program of sufficient intensity to maintain reservoir pressure at approximately 600 psia, or some 274 lb above the bubble point pressure of 326 psia.
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.
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.
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.
This paper discusses methods used in the estimation of natural gas reservesand the general conditions under which the various methods are applicable. Thefactors used in estimating natural gas reserves are reviewed. Errors which havebeen found to occur frequently are listed.
The estimation of natural gas reserves has become of paramount interestbecause of the increasing importance of gas in the nation's economy. Gas is amost desirable fuel, a fact substantiated by the continued rise in the marketdemand. In addition, new uses for gas are being developed by the chemical,plastic, and associated industries, and plants are being built to make gasolinefrom natural gas. These are a few of the factors contributing to the importanceof the nation's natural gas reserves.
With the increased importance of gas there is an increase in the need forreliable estimates of the magnitude and availability of natural gas reserves.These estimates are being used currently: (I) to determine which fields containsufficient available reserves to justify the construction of pipe-line outletsto serve particular markets; (2) to design pipe lines necessary to serve thosefields adequately; (3) to determine the location of industrial and chemicalplants; (4) to finance the development of gas properties, and theconstruction
of gas pipe lines; (5) to determine fair and adequate depletion allowances anddepreciation rates; (6) to justify applications for gas pipe lines beforevarious regulatory bodies; (7) to determine the number of wells required toexploit the reserves most economically; (8) to aid in establishing values forthe purchase or sale of gas properties, and for purposes of inheritance taxes;(9) to determine equities under unitized operations; (IO) to provide a basisfor calculating the economics of gas-cycling operations.
History of Estimation of Natural Gas Reserves
The natural gas industry in the United States had its beginning during 1826when natural gas was used for lighting the city of Fredonia, N.Y. The firstnatural gas pipe line was a 25-mile wooden line constructed from hollowed logs,connecting West Bloomfield and Rochester, N.Y. There is no record of an attemptto estimate the gas reserve at West Bloomfield but an attempt was made todetermine the capacity of the well by measuring the time required to fill alarge balloon.
One of the earlier publications concerning estimation of natural gasreserves is the "Manual for the Oil and Gas Industry," published by theTreasury Department, United States Internal Revenue, in 1919.
In October 1945. R. F. Farris, in an AIME paper entitled "Method ForDetermining Minimum Waiting on Cement Time," presented a method forcalculating the minimum WOC* time required in oil well cementing operations.Briefly, this method consisted of shutting in a well after the cement had beenplaced, and noting the time required for the wellhead pressure to reach amaximum. This time was then multiplied by a factor of 1.5 to determine when thecement had reached sufficient strength to support the weight of thecasing.
As a result of this work, a number of areas have reduced their WOC timerequirements with the subsequent saving of considerable rig time.
The tests conducted by Farris were for the most part, conducted under cementingtemperatures in excess of 70?F. This was done because in the overwhelmingmajority of cases, cementing temperatures are in excess of 70?F (only in thenorthern part of the country, primarily in the Rocky Mountain area, incementing surface casing are temperatures below 70?F. encountered, and suchtemperatures occur only during the winter months). The Stanolind ResearchLaboratory since that time has performed a number of tests both in thelaboratory and in the field to evaluate this WOC factor when cementingtemperatures are lower than 70? F. The results of these tests indicated theneed for greater WOC time in areas affected by abnormally low cementingtemperatures. These tests indicated that a WOC factor of 2 (Time from start tomix cement to maximum wellhead pressure x 2 = Time to drill plug) will allowsufficient time for the cement to develop adequate strength.
A field test under abnormally low cementing temperatures (surface temperature35?F, mud discharge temperature <70?F, and cementing depth 500 ft.) in theRangely Field, Colorado, using the WOC factor of 2, indicated the time to drillthe plug as 45 hours. Well conditions preventing getting back into the welluntil a 48-hour WOC time had elapsed. At this time, the plug drilled firm tohard indicating that the cement had reached its final set.
It is contemplated that during next winter additional field tests will beperformed to further check the results of the laboratory and field testsconducted to date.
*WOC, abbreviation for ?waiting on cement?, indicates the time from when thecement is mixed to the time when sufficient strength has been obtained to allowthe drilling of the plug.
The term oil shale is defined. Foreign oil shale developments are outlinedbriefly. The richest and most extensive oil-shale deposits in the United Stateslie in western Colorado. The Bureau of Mines is opening two adjacent areas forunderground mining in western Colorado. From the first area the oil shale ismined selectively as required by the retorting plant. The second area is beingdeveloped as a unit of a full scale oil-shale mine to ascertain the mostpractical methods of mining oil shale and to determine costs. In both of thesemining areas, research will be carried on to develop new and improved practicesfor mining oil shale.
Oil shale is a sedimentary rock containing a solid mineraloid of indefinitecomposition known as kerogen. On heating oil shale, the kerogen undergoesthermal decomposition and some of the vapor products of the decomposition canbe condensed as shale oil. Oil from shale can be a major source of liquid fuelssince extensive deposits of oil shale are known to exist throughout the world.The United States considers the establishment of an oil-shale industry onlywhen doubt exists of the adequacy of the domestic supply of crudepetroleum.
On the other hand, oil shale is not strange to foreign oil men. The industryis an old one in other parts of the world. The French industry has been inexistence since 1838, the Scottish since 1859, the Australian since 1860, theEstonian and Swedish industries since World War I, and the Manchurian industrysince 1929.
The most highly exploited oil-shale deposits are the Carboniferous shales ofScotland. About 20 seams ranging from 4 to 12 ft in thickness are worked. Theyield during recent years in Scotland has been 18 to 25 gal of shale oil perton, from 3,000,000 tons per year. The French and Swedish oil-shale depositsare of lower grade than the Scottish. The Estonian oil shale deposits are 7 ftthick, and the oil yield averages 50 gal per ton. Over 1,000,000 tons are minedeach year, half of which is used directly as fuel to substitute for coal andthe other half is used for the production of oil.
A general theory has been developed for the effect of permeabilitystratification on the efficiency of the gas-injection phase of cyclingoperations. It has been applied to three special types of permeabilityvariation; namely, exponential, probability, and linear. In the case of theexponential permeability distribution the effect of areal pattern sweepefficiency was also taken into account.
The exponential permeability distribution can be characterized by the ratioof the maximum to minimum permeability, which has been termed thestratification constant. Curves were calculated for the variation in total wetgas recovery and total gas throughflow, to give that recovery to variousabandonment limits of the wet gas content in the produced gas, as a function ofthe stratification constant. The cumulative wet gas recovery decreasesmonotonically as the stratification constant increases and is generally higherat the lower values of the wet gas content abandonment limits. The total gasthroughflow first rises to a maximum as the stratification increases, and thenultimately declines. The effect of the areal sweep pattern efficiency isrelatively minor as compared to that of the stratification constant, except inthe region of low values of the latter where the formation is substantiallyuniform.
The probability distribution can be characterized by a "variation"parameter varying from O to I as the formation changes from strict uniformityto extreme variability. The curves of total wet gas recovery and total gasthroughflow to different abandonment limits of wet gas content versus thevariation parameter have the same general characteristics as for theexponential permeability distribution.
In the linear permeability distribution the ratio of maximum to minimumpermeability also serves as a stratification constant index defining thedistribution. The curves of total wet gas recovery and gas throughflow to fixedabandonment limits versus the stratification constant are similar to those forthe exponential permeability distribution. However, for the higher values ofthe stratification constant the recoveries and throughflows do notasymptotically fall to 0 as in the latter, but approach constant valuesdetermined by the abandonment limit of wet gas content in the produced gas.
It is becoming generally recognized that one of the most important factorsdetermining the economic feasibility of cycling operations is the arealcontinuity and permeability distribution of the producing formation. While theeffects of areal variations in permeability, porosity, thickness, and wellpattern on the sweep efficiency can be evaluated by electrical model studies,those due to permeability stratification require separate treatment: Severalstudies have been reported on the influence of permeability variations on thewet gas recovery by cycling. In these, however, discontinuous permeabilityvariations either have been assumed explicitly, or the analysis has beencarried through as if they were discontinuous.
This paper describes the sources of funds required by the petroleum industryto finance capital expenditures and also presents a discussion of the effect ofrising construction costs on these expenditures. The petroleum industry obtainsits capital funds from several sources: (1) internal, from retained cashearnings; and (2) external, from borrowings and the sale of securities to thepublic.
The upward trend of capital expenditures of the petroleum industry is causedin the main by the influence of two powerful factors: (1) the physical growthin the demand for oils; and (2) the rising cost of drilling wells andconstructing refineries, pipe lines, and other facilities. The segregation ofthese factors is accomplished by deflating the actual capital expenditures sothat they are shown in terms of 1939 costs and then subtracting the adjustedseries from the actual figures to yield a set of data representing theexpenditures made on account of higher costs.
Rising costs affect prices and the portion attributable to this factor hadto be generated from the cash earnings of the industry, which called for higheroil prices.
Capital may be defined as "wealth employed in or available forproduction." All production requires capital. Expanding industries requiremore capital than static ones, and technological industries employ more capitalthan those in which little equipment is needed. The petroleum industry is bothrapidly growing and highly technological, and, being a large industry, itscapital requirements are prodigious, amounting to about one-seventh of thetotal of all American business, excluding agriculture.
Capital formation may be defined as the method by which the wealth orcapital needed in the productive processes is created. There are various waysin which capital funds may be obtained but there is only one way in whichcapital can be created - out of production in excess of consumption, that is,savings. The physical realities are simple, but the monetary concepts arecomplicated because the mechanism of credit can draw upon future savings.
In this paper, the theory of elasticity has been applied to the rock about adeep well. It is assumed that the rock has a modulus of elasticity and aPoisson's ratio and that the theory of elasticity applies. It is necessary toknow or assume the state of stress existing in the rock before it is penetratedby the well drill.
The application of this theory indicates that stress concentration of shear,tensions, and compressions about the bore hole are of a high order. This isparticularly true when a horizontal compressive stress exists in one directiononly in the formation before drilling. If such an initial state of stressexists before drilling, then the rock will have stress concentrations of bothtension and compression at the same elevation and of such magnitude thatfailure of the rock is likely. Accompanying these is a shearing stress of largeproportion which is likely to produce spalling of the well walls. Internalpressure applied to the well bore will relieve the extreme compression but notthe tension and has little effect upon the shear. Plastic deformation of therock through a geological time tends to mitigate the stress concentrations.
It has long been known that the stresses about holes and re-entrant cornersof elastic solids under the influence of loads are different and generally moreintense than those imposed upon the body elsewhere. Stress concentration at are-entrant corner can be reduced by increasing the radius of the fillet at thecorner. Stress concentration at the end of a crack in a plate undergoing eithertension or compression can be relieved appreciably by drilling a hole at thevery end of the crack. Also, stresses can be increased in an elastic body intension or compression by making a hole in it. The stress concentration isgreatest at the edge of the hole.
Considerable knowledge of the stresses which exist about the bore hole of adeep well may be had by applying our knowledge of engineering mechanics; ormore particularly the theory of elasticity. It is, of course, necessary to makethe assumption that the rock is elastic and behaves as an elastic solid, thatis, that it obeys Hooke's law, has a modulus of elasticity, and a Poisson'sratio. It is also necessary to know, or assume, the state of stress whichexists in the rock prior to the penetration of the drill. With this knowledgeit is possible to compute the stresses about the bore hole.
The problem can be simplified by considering several simple cases separatelyand then by applying the principle of superposition to solve the more complexcases which are made up of the simpler ones.