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By M. R. J. Wyllie, H. W. Patnode

In the quantitative interpretation of electric log data it is essential to know the formation factor, defined as the ratio of the resistivity of the formation 100 per cent saturated with brine to the resistivity of the brine.' This concept implies that the formation factor for any given rock is constant irrespective of the resistivity of the brine or solution with which it is saturated. It is apparent that this can be true only when the rock matrix is wholly non-conductive. As reservoir rocks may contain clay or shale having an appreciable conductance one may expect these constituents to influence the determination of true formation factor. The formation factor may be theoretically derived from log data by dividing the resistivity of the mud filtrate invaded formation by the resistivity of the mud filtrate. Such a method of calculntion has implicit in it the assumption that the fluids in the invaded formation are wholly replaced by mud filtrate. that the solid matrix is non-conducting, and that the formation factor of the invaded zone is identical with the formation factor of the uninvaded zone. Since the validity of the first two basic assumptions regarding the insulating character of porous matrices and the displacement of the interstitial fluids in porous media do not appear to be fully established, the formation factors of a number of cores and clay slurries have been measured under conditions suitable for verifying the assumptions and the extent of any errors inherent in them. CORE STUDIES Apparatus and Procedure Resistivity measurements were made on short cylindrical permeable cores which had been previously mounted in lucite.2 The cores were clamped by means of insulated bolts between brass plates about 5 cm square and 1 cm in thickness. The plates were provided with a ring seal to prevent leakage between them and the core mount, and had a centrally located orifice so that fluids could be flowed through the mounted core. The brass mounting plates were used as electrodes and any current flow between them necessarily passed only through the constituents of the intervening core. Fluid saturation of the core, and fluid flow through the core, were effected by a centrifugal pump connected to the outflow end of the core, thus providing a differential pressure across the core of approximately one atmosphere. The procedure used was first to evacuate each core by means of the pump and then to saturate the core with an aqueous sodium chloride solution of known resistivity. The resistance of the core was measured and flow of the solution through the core continued for sufficient time to establish a constant resistance reading. After equilibrium had been reached with one solution, another sodium chloride solution of a different resistivity was flowed through the core and the flow continued until a constant resistance reading was again obtained. This procedure was continued until resistance measurements of the core had been made with a series of solutions within a salinity range from 1.0N NaCl to distilled water. The data obtained enabled the apparent formation factor of given porous rocks when saturated with fluids of different resistivity to be computed and also provided information regarding the ability of an invading fluid to displace interstitial water from a core. Results Berea Sandstone — The first core examined was a specimen of Berea sandstone." This core had been cut essentially parallel to the bedding for permeability studies. The core was clamped in the core holder and saturated with 1.0N NaCl solution and the resistance determined. It was subsequently flushed and the resistance measured when saturated in turn with 0.1N, 0.025N, 0.01N, .005N sodium chloride solutions and finally with distilled water. In flushing the core with each

Jan 1, 1950

By M. H. Waxman, M. Gondouin, H. J. Hill

Streaming-potential experiments were conducted within the Muddy- and Dakota-sandstone interval of a Denver basin well. Analysis of the data shows that, for this case, streaming potentials opposite sands were higher than those opposite shales when the mud was fresh. Streaming potentials opposite shales, however, were of sufficient magniiIlde to be important in SP interpretation. They were linearly dependent upon pressure differential, and they increased with mud filtrate resistivity. The magnitude of streaming potentials opposite sands was influenced by the characteristics of the original mud cake formed at the time of drilling. Use of mud samples taken at the time of logging may not always be satisfactory for determining streaming-potential corrections. Both the streaming and electrochemical potentials were found to be affected by the previous history of the borehole system. Following a change in mud characteristics, several days were required for SP stabilization. This was, in part, due to the mud cake acting as an imperfect shale membrane. INTRODUCTION Laboratory investigations by Wyllie,1 Salisch,2 Moore," Sen Gupta and Bannerjee,0 and Hill and Anderson' have shown that streaming potentials developed across mud cakes deposited on permeable filter beds are of sufficient magnitude to be critically important in SP interpretation. Streaming potentials across shales have been reported by Schenck,' Gondouin and Scala; and Hill and Anderson." The magnitude of the shale streaming potentials obtained by Schenck and by Gondouin et a1 led these authors to conclude that in many cases the shale streaming potential would approximately equal the mud-cake streaming potential. Hill and Anderson, however, obtained somewhat lower magnitudes of shale streaming potential. The field experiment described in the present paper was a cooperative project carried out by the respective operations and research departments of Schlumberger Well Surveying Corp., Shell Development Co. and Shell Oil Co. The primary objective of the experiment was to determine in the borehole the streaming-potential behavior of both shales and mud cakes under conditions approaching, as nearly as possible, those normally encountered in logging practice. METHODS AND EQUIPMENT WELL A Muddy- and Dakota-sandstone vie11 in the Denver basin was chosen for the experiment. Both sandstones were water-bearing and, since reservoir pressures in these sandstones are abnormally low (gradient of approximately 0.25 psi/ft), it was expected that studies of streaming potential could be conducted from low-pressure differentials (approximately 200 psi) to about 27000 psi by bailing mud from the hole, filling up and then applying wellhead pressure. The selected well encountered the Muddy sand-

By R. H. Winn

A method for the selection of the most suitable corrosion inhibitor for a particular system is given. The method involves the evaluation of surface passivity by means of copper ion displacement after the metal surface has been subjected to the corrosive atmosphere. The application of the method to the selection of suitable inhibitors for use in producing wells is described. Correlation with recognized laboratory tests has beet1 found to be good within the limitations of the test. The use of the test to evaluate inhibitor persistencc is described. INTRODUCTION Corrosion as it is associated with the industry shows wide variations in its qualitative as well as its quantitative aspects. This complicates the work of the corrosion engineer. In the past few years the efforts of the corrosion engineer have been further taxed by the large numbers of products being marketed as corrosion inhibitors by various manufacturers. These products are submitted to him together with a limited amount of data to support their use as inhibitors. The data are usually authentic and reliable yet all too often when these products are applied to an actual corrosive system the results are disappointing due to the ineffectiveness of the inhibitor and the corrosive system. The corrosion engineer must select a comparatively limited number of inhibitors for field trial from the large number available. The selection is usually made on the basis of a standardized laboratory test such as that adopted by the National Association of Corrosion Engineers or by field experience in an area; however, testing of this type is discouraging on large numbers of compounds, particularly in view of the specificity of environment. It has been an object of this work to devise a method which will allow the corrosion engineer to select the best inhibitor for a specific environment under field conditions. The test would of necessity be rapid and inexpensive. It would preferably eliminate the need for expensive and delicate instruments. STATEMENT OF THEORY The test as developed makes use of the fact that metal ions will be displaced from solution by metals having a more positive electrode potential. Thus, if an active iron surface is exposed to a solution of a copper salt, free copper will plate spontaneously on the iron surface as it is displaced from the salt solution by iron ions. If the iron surface is passified, as by coating with an insulating-type organic corrosion inhibitor, it is no longer capable of displacing the copper ions due to its own limited ionization. The result will be a change in the amount of copper plated upon exposure to a neutral copper salt solution. In practice it has been found possible to measure the magnitude of the alteration of the cell potential by determining the copper deposited on a standard iron surface under controlled conditions. This means that, as the film builds up, the resulting shift in the electrode potential tends to cause the iron surface to act more like a noble metal, resulting in a reduction in the cell potential to a point that copper will no longer plate spontaneously. Obviously, the salts of other metals such as silver, gold or platinum might be used for this operation; however, copper was selected because of the color difference of the plate, the comparatively low cost of copper salts and the ease of evaluation of the plated copper. Furthermore, its high cell potential provides a substantial driving energy. The determination of the copper is readily done colorimetrically by dissolving it in 5 per cent ammonium hydroxide solution containing 2 per cent potassium per-sulfate. The blue color of the copper ammonic complex ion so developed may be compared with standards prepared by dissolving known quantities of copper powder in the same reagent. In routine screening it is seldom desirable to determine the amount of copper plated. It is usually more important to determine the concentration of inhibitor required to prevent the plating of copper.

By M. Felsenthal

Engineers are frequently faced with the problem of having to predict oil recovery from a solution gas drive reservoir in the early life of a field. This is often the time when actual laboratory or field-derived gas-oil permeability (kg/k0) data are not yet available. Although excellent collections of k0/k0 data for various types of rocks may be found in the literature,1,2,3 a need exists for a more detailed correlation of k0/k0 data with core properties such as porosity, permeability, clay content or pore-size distribution. It is the purpose of this article to present this type of correlation for sandstone material. The correlation is based on laboratory tests performed on over 300 core samples from 19 reservoirs in the United States and Canada. EXPERIMENTAL Cores were analyzed by routine procedures, using samples of conventional size (7/8-in. diameter, 7/8-in long) cut parallel to the bedding planes. Air permeability was measured at 1.67 atm mean pressure in a Hassler-type apparatus. Porosity was determined with the aid of a Ruska bulk volume meter and a Boyle's Law rock volume meter, An evaporation method' was used to evaluate irreducible water saturations. Core samples were saturated with 25,000 ppm NaCl brine. The brine was reduced to the irreducible saturation, and the remainder of the pore space was filled with kerosene. This was followed by multiphase flow tests using the so-called "dispersed feed" technique.5 n this technique, gas and oil (kerosene and kerosene-saturated air) were dispersed with the aid of a porous Alun-durn feed head, the face of which contained a waffle-shaped system of Lucite-lined grooves. Oil entered the back side of the feed head and emerged at the raised areas of the front face. Gas was introduced directly into the system of grooves at the front face. The gas-oil mixture then entered the test core which was kept in capillary contact with the feed head. Permeabilities were determined from rate and pressure measurements and saturations from weights. All determinations were performed at equilibrium or steady-state conditions. Pore-size distributions were determined on selected samples by a mercury injection technique.6 GENERAL CORRELATIVE TRENDS When examining data from a given reservoir, it was noted that k0/k0 vs saturation curves became generally less steep as specific air permeability increased, a development that has a favorable effect on oil displacement efficiency by solution gas drive. This trend has also been reported by others in the literature.' An effect of porosity on k0/k0 data was also noted. This effect was not generally discernible in a study of relative permeability data for a given reservoir but became apparent when data for sandstone reservoirs of similar lithology but differing average porosity were compared. For instance, in a comparison of argillaceous and/or calcareous sandstones from 11 reservoirs ranging in average porosities from 14 to 28 per cent, a definite trend was noted, indicating that for a given permeability k0/k0 curves became less favorable (i.e., steeper) as porosity increased. A similar trend was observed for a group of comparatively clean sandstones from five reservoirs ranging in average porosities from 15 to 21 per cent. For a given permeability and porosity, comparatively clean sandstones gave more favorable k0/k0 curves than argillaceous and/or calcareous sandstone or chert reservoirs. The laboratory studies also showed that least favorable k0/k0 curves were exhibited by shaly sandstone, conglomerate, and sandstone containing carbon inclusions. Table 1 lists the various source reservoirs classified by lithology types. To facilitate a correlation of k0/k0 data with core characteristcis, it was found expedient to work with

By M. P. Tixier, M. Gondouin, G. L. Simard

In the quantitative interpretation of the SP logs, the electrochemical component is generally taken equal to — K log Rm /Rw where K has the theoretical value corresponding to solutions of pure sodium chloride. This method may be misleading when relatively large quantities of salts other than NaCl are present in form-rrtion waters—as is generally the case for low salinities —or in gyp-base muds. In such cases recourse is made in the field to changing the K value or to adding a correction term to the equation on the basis of local experience. An investigation has been made in the laboratory of the influence of HCO3, SO4=, Ca++, and Mg++ on the amplitude of the SP deflection, which included in par-ricular determinations of the activity coefficients of Ca++ and Mg++. The theory, the experimental techniques and a tentative method for applying the results are described. So far, applications to actual field cases where chemical analyses of waters were available have provided an excellent confirmation of the proposed method. The case of the SP in very salty brines is also considered and it is shown that the use of activity data for sodium gives satisfactory results. HISTORICAL In early times of electrical logging, the SP curve was used exclusively as a tool for the location of permeable beds and the definition of their boundaries. Later, with the introduction of methods of quantitative analysis, attention was called to the possibility of deriving from the SP log some information on the formation water resistivity, which constitutes one essential element for the computation of water saturation from log data. The first laboratory experiments' in 1932 had shown that, as a result of electrochemical phenomena arising at the contact of the niud and the formation, the amplitude of the deflection of the SP curve was, at least partly, a function of the salt concentration of interstitial water and accordingly of its resistivity. It was indicated that the amplitude of the electrochemical component of the SP should be equal to K log R1/R2, R1 and R2 being the resistivities of the mud and of the formation water respectively. However, the exact value of the K coefficient was not determined at that time because the surface clay used for a laboratory model was far from an ideal shale membrane. Consequently, the way was not yet open towards quantitative interpretation. In the early forties, Tixier reported2, on the basis of field log observations, the following equation for the case of NaCl solutions, SP = -71 log f1c1/f2c2, c1 and c2 being the concentrations and f1, f2 the mean activity coefficients. The local variations observed in the empirical values of K, chiefly in the Rocky Mountains, led him to advance the opinion that, besides the relative amounts, the nature of the salts present in the solutions had a bearing on the magnitude of the SP. At about the same time Mounce and Rust- ad published laboratory results which emphasized the part played by the shale in the generation of the SP. On the basis of laboratory tests and theoretical considerations, Wyllie in 1948' published the following equation of the electrochemical SP for the case of NaCl solutions, SP= - 71 log (a1)m/(a2)m

Jan 1, 1958

By L. S. Allen, R. L. Caldwell, W. R. Mills

Borehole models used in the study of nuclear well logging are reviewed and the merit of heterogeneous us homogeneous formation simulation is discussed. .A heterogeneous model for simulating sandstone formations of variable porosity is described. Simulation adequacy was checked by steady-state and pulsed-neutron measurements. INTRODUCTION In the course of developing new methods of nuclear well logging, the problem of testing new logging instruments under controlled conditions always arises. This testing is usually done in wells of known lithology, porosity and fluid saturation, or in laboratory test facilities which simulate the borehole environment. Although the former approach is possibly more satisfying, it is frequently difficult or inconvenient to find wells with enough variation in the cited parameters for a truly comprehensive study, On the other hand. laboratow- test facilities can simulate a wide variety of formation and borehole conditions if care is exercised to maintain adequate simulation under all conditions. Workers concerned with the development of nuclear well logging methods have reported several types of research facilities in the past. Tittle, et a1 used cubical tanks filled with Ottawa silica sand to study the steady-state behavior of thermal and epithemal neutrons in simulated sandstone logging environments.1 In addition to the effects of fresh vs salt water, a wide variety of casing sizes and compositions were investigated. Tittman also used a large tank of Ottawa sand to measure the slowing down length of sio2;2 for making the same measurement in CaCO3, however, an assembly of solid Vermont marble blocks was used. More recently a very useful and carefully planned test pit for nuclear logs was constructed under the auspices of the API.3 This facility consists of three massive limestone sections, each 6-ft thick and more than 5 ft in diameter. The blocks are buried, one on top of the other, in a concrete- lined pit having a total depth of 24 ft. Each section is made of a different limestone to achieve porosity variation, the selection being Carthage (2 per cent), Indiana (19 per cent) and Austin (26 per cent). The blocks are traversed by a 7 7/8-in. diameter borehole and are saturated with fresh water. Great care was taken to insure total saturation of the stone. Homogeneous mixtures and materials have not been used exclusively for simulating earth formations. Tittle, et a1 4 showed that a heterogeneous lattice of water and graphite could be used to simulate Liquid furfural with very little effecton measured thermal and epi thermal neutron distributions. Subsequently, a lattice-type model for simulating limestone earth formations was designed and built by Berry This limestone model was constructed of 7/8- x 11/4- x 36411. marble rods glued together with a plastic resin to form a 36-x 42- x 42in. cube. The cube was honeycombed vertically with 7/8- x 7/8- x 3641-1. holes for porosity and had a 111/2-in. diameter hole in the center to serve as the borehole. Lower porosities were simulated by placing marble rods in the square holes. The finished cube was used with the borehole vertical and set in a tank to hold liquid for filling the holes in the rock matrix. A second type of heterogeneous borehole model has been proposed by Kukharenko, et a1.6= In this concept the model is composed entirely of solid material. The hydrogen equivalent of formation fluids is simulated by making the model of alternating layers of dense rock and celluloid. Additional hydrogen is included by drilling vertical holes in the rock sections and filling them with solid forms of hydrogeneous material. The volume of the holes is equal to the volume of the celluloid layers, so an axial and radial dispersion of the hydrogeneous material is thus obtained. One such model was composed of alternate 50 mm-thick sand layers and 2 mm-thick celluloid sheets. Approximately 200 appropriately spaced plastic tubes were used in each sand section. The plastic tubes were filled with paraffin for additional hydrogen concentration. This arrangement yielded a model with a water-equivalent hydrogen concentration of 10 per cent. Experimental data taken in this model and in a model consisting of the same material but homogeneously dispersed showed that the heterogeneous system adequately

Jan 1, 1966

By C. S. Matthews, H. M. Girner, C. D. Williams, M. J. Edwardson, H. R. Parkison

Quantitative interpretation of electric logs requires knowledge of formation temperature. In this paper, methods are developed for computing changes in formation temperature caused by circulation of mud during drilling operations. The basis of the method is the mathematical solution of the differential equation of heat conduction. The solution of this equation is presented in a series of graphs. These graphs are used to determine formation temperature disturbance at various radii for arbitrary mud circulation histories. Example comparisons with field results show reasonable agreement. It is concluded that, in general, the temperature disturbances caused by circulating mud are small beyond 10 ft from the wellbore but are quite significant near the wellbore. INTRODUCTION Quantitative interpretation of electric logs requires knowledge of the formation temperature in order to establish the resistivity of the formation water with accuracy. To determine the formation temperature, the temperature disturbances produced by circulating drilling mud must be evaluated. -The objective of this investigation was to develop a method for the numerical determination of these temperature disturbances at any distance from the wellbore as a function of time. The first step was to solve the differential equation describing the temperature behavior in the formation during and after mud circulation. This solution was used to calculate a series of curves relating temperature disturbance to shut-in time for various circulating periods. An "exact" method for computing formation temperatures with the use of these temperature-disturbance plots is described, and the results of an application of this method to a well in Montana are presented. Procedures for approximating formation temperatures are also discussed. BASIC EQUATIONS AND ASSUMPTIONS With the assumptions that (1) cylindrical symmetry exists, with the borehole as the axis, (2) heat flow is 1. The formation can be treated as though it is radially infinite and homogeneous in extent, as regards heat flow. 2. The presence of mud cake can be disregarded. 3. The effect of heat generated by bit action is negligible. 4. After mud circulation ceases, the rate of radial heat flow at the wellbore is negligible and is assumed zero for purposes of calculating temperature change with time. These assumptions are believed to be reasonable because of the agreement achieved between calculated and measured borehole temperature in a well, to be discussed later. Further, the agreement at the wellbore indicates that temperatures in the formation were also approximately correct. since it is the formation temperatures that determine wellbore temperature after ceasing circulations SOLUTION OF THE DIFFERENTIAL EQUATION AND ITS APPLICATION The solution of Eq. 2 for the temperature behavior during and after a single period of mud circulation is

By E. A. Breitenbach

A computer program has been developed to afford rapid and complete quantitative log analysis for exploration and production decisions. The computation consists of automatic selection of tops and bottoms of porous intervals from the digitized data, and then point-by-point calculations within each selected interval. Nearly all log types can be analyzed. This paper presents the calculation techniques found to be appticable to machine evaluation and gives examples of their use. INTRODUCTION As the quantitative interpretation of well logs entails repetitive use of charts and equations, it is natural that digital computer programs would be written. A Universal Log Interpretation Computer Program (ULICP) has been developed to afiord rapid and complete analysis for exploration and production decisions. Application of this program enables the log analyst to: (I) apply rapid quantitative log analysis for exploration and production decisions on either a field, a well or on a single zone basis; (2) apply concepts of interpretation requiring detailed numerical analysis; (3) analyze all porous intervals on each log, rather than a few selected zones, and complete the analysis in less time than previously required. Computations are reported for every digitized point in each zone; (4) use empirical techniques applicable to a given area as an integral part of the computation; (5) experiment with the empirical coefficients and exponents in the interpretation equations to find the best possible solution; and (6) automatically plot both the original and computed data to scales analogous to the field prints. The primary utility of a log interpretation program stems from its ability to do an overwhelming amount of work with very little man-power. If a calculation procedure or thought process can be formalized to the extent that step-by-step logic can be written, a computer program can be developed that follows this logic. The major question is one of economics. A feasibility study of the costs for such a program indicates that digital processing is economical primarily as a means of increasing the productivity of the log analyst. In effect, the probability of missing productive intervals in any well, because of a lack of time to do detailed calculations, is greatly reduced. The nucleus of ULICP is programmed to compute large sections of a suite of logs by selecting zones automatically and then performing all pertinent computations on a data point by data point basis within each zone.'.' An entire suite of logs can be processed in this manner with very little manual intervention. Sufficient programming logic is available so that each log analyst can request computations pertinent to his area. These requests are made by simple additions or deletions of information on the input header cards. Hence, the log analyst is always in complete control of the computation process. The evaluation of a suite of logs requires pre-editing, digitization, computation, presentation of results and interpretation. Work by the log analyst is reqilired only in pre-editing and interpretation. Thus, he is allowed more time for comprehensive interpretation, rather than calculation. For continuity, the discussion of ULICP is organized sequentially: pre-editing, digitization, computation and presentation of results. DISCUSSION PRE-EDITING The extent of pre-editing prior to computation is dependent on the format of the original data. For analog prints, it requires inspection, correlation and editing of the logs, plus the entering of required data an special forms. For digitized data such as magnetic tape field recordings, only the special forms are necessary. The process for analog prints will be given here. The inspection and correlation process involves the selection of sections for digitization and the correlation of the traces to a common depth. To decrease the cost of digitization, traces that exhibit large variations in shale formations can be redrawn to a non-zero baseline. The next step is to enter all pertinent data on the input header cards. The header cards presently used for ULICP are presented as Figs. 1 through 6. Cards 1, 2, 3 and 4 (Fig. 1) are defined as the Main Header Cards. They describe the particular well for output identification and give basic information. Cards 5 through 15 (Figs. 2 through 6) are defined as the Block Header Cards. As such, they define the log types and the interpretation parameters for the block of data immediately following. Cards 1 through 10 are required for every computer run. Cards 11 through 14 pertain only to nuclear logs. Card 11 is required if any nuclear log is supplied, and cards 12 through 14 are required only when gamma-ray, density or neutron log data, respectively, are supplied. Card 15 (Fig. 6) must be supplied when cross-plot calculations are required. Either two- or three-component

Jan 1, 1967

Jan 1, 1969

By S. E. Szasz, E. J. Moore, B. F. Whitney

An accurate value of formation water resistivity R, is essential in calculating formation porosity and fluid saturation from electrical well logs. In the cases where R, has not been measured directly, it must be obtained from other data, e.g., the SP curve. This paper deals with another approach: how to calculate R, from the chemical analysis of the formation water. INTRODUCTION It is known that the resistivity of aqueous solutions of pure salts depends on their concentration and on the temperature; the concentrations are given in MPL (mg of solute per liter of solution), or sometimes in ppm (mg of solute per kg of solution): MPL = ppm X specific gravity. Values for different pure salts are available in the literature, but not for solutions of mixtures which are of practical interest. The major component of the dissolved material in almost all formation waters being sodium chloride, it is customary to express the resistivity of formation waters in terms of equivalent sodium chloride concentration, i.e., the concentration of a solution of pure NaCl which has the same resistivity at a given temperature as that of the formation water under consideration. Thus, the problem of calculating R, from the chemical anaylsis can also be stated as how to convert the other constituents of the solute into equivalent NaCl concentration. Salts dissolved in water are at least partly dissociated into ions, and do not conserve their identity. If known amounts of several salts are dissolved in water, the solution does not necessarily contain the same salts in the original proportion, but perhaps some other combination of the ions, along with free ions in solution. This is why the chemical analysis of formation waters is often given in terms of ions, as if all dissolved salts were completely dissociated. Our problem then boils down to how to convert the concentrations of the various ions to equivalent concentrations of Na' and C1-. Dunlap and Hawthorne' have proposed to convert the concentration of all other ions to equivalent Na' and C1-concentrations by means of constant multipliers; e.g., 0.95 for Ca"; 2.0 for Mg"; 0.27 for HCO 3-; 0.5 for SO, -, etc. Their factors were based on measurements made at 68F on 26 formation water samples from the Texas Gulf Coast, ranging in concentration from 1,500 to 75,000 ppm. The Dunlap method is widely used in electric log interpretation, and is often extrapolated beyond its original concentration range. A comparison of R, values calculated by this method and values actually measured on formation water samples has shown large discrepancies, especially at higher concentrations. Therefore, two new methods were developed at Sinclair Oil Corp.'s Tulsa Research Center to calculate equivalent sodium chloride concentration from the chemical analysis of formation water samples. FUNDAMENTAL CONSIDERATIONS The resistivity of a solution, or its reciprocal the conductivity, at a given temperature is determined by the charge, concentration and mobility of the ions actually present. Monovalent ions such as Na' or C1- always carry the same charge. Compounds of polyvalent ions, however. may show incomplete dissociation, e.g., NaSO; + Na' instead of SO,-- + 2Na'. This happens especially in more concentrated solutions. Only very dilute solutions are completely dissociated, as assumed in the chemical analysis report. At higher concentration, the degree of dissociation depends not only on the nature and concentration of the particular salt under consideration but also on the nature and concentrations of the other solutes. Mobility of the ions depends on the viscosity of the solution. It also depends on the degree of hydration of the ions, which in turn is a function of the nature and the charge of the ions and also of the amount of free water available per ion, i.e., the total ionic concentration. The net effect is that the conductivity increases slower than proportional to the concentration, even if a solution contains only one salt such as NaC1, and is different for different salts (Fig. 1). Conductivity can even decline with a further increase in concentration, e.g., if additional salt is little dissociated but ties up some of the free water and/or causes an increase in viscosity. In solutions containing more than one salt, the contribution of one salt to the total conductivity depends not only on the fractional concentration of this same salt, but also on the concentration of all other solutes. A perfect method would give the conductivity or resistivity of a solution as a function of the concentrations of all solutes present. This is so complicated as to be impractical, and a simpler method must be found which is of acceptable accuracy. The Dunlap method, on the other hand. is too simple because it askmes that at any concentration the contrih-

Jan 1, 1967

By M. H. Waxman, L. J. M. Smits

A simple physical model was used to develop an equation that relates the electrical conductivity of a water-saturatedshaly sand to the water conductivity and the cation-exchange capacity per unit pore volume of the rock. This equation fits both the experimental data of Hill and Milburn and data obtained recently on selected shaly sands with a wide range of cation-exchange capacities. This model was extended to cases where both oil and water are present in the shaly sand. This results in an additional expression, relating the resistivity ratio to water saturation, water conductivity and cation-exchange capacity per unit pore volume. The effect of shale content on the resistivity index - water saturation function is demonstrated by several numerical examples. INTRODUCTION A principal aim of well logging is to provide quantitative information concerning porosity and oil saturation of the permeable formations penetrated by the borehole. For clean sands, the relationships between measured physical quantities and porosity or saturation are well known. However, the presence of clay minerals greatly complicates log interpretation, particularly the electrical resistivity and SP logs, and considerably affects evaluation of hydrocarbon-bearing formations. The conductance and electrochemical behavior of shaly sands and their relation to log interpretation have been studied by many workers. wylliel and Lunch2 reviewed this work in some detail. Virtually all laboratory measurements of electrical resistivity and electrochemical potential of shaly sands published to date are the work of Hill and Milburn.3 Their measurements were made on about 300 cores covering a large variety of sedimentary rocks, and a wide range of equilibrating NaCl solution concentrations. Hill and Milburn described their conductivity data by an empirical equation in which the shaly sand conductivity Co was expressed as a function of the solution conductivity C and two parameters b and F01 . The quantity b was shown to be a measure of the effective clay content of the rock, being approximately proportional to the cation-exchange capacity of the rock divided by its pore volume. The latter ratio is designated as 9, in this paper and has the dimensions meq/ml or equiv/liter. Qv is identical with the term representing the concentration of fixed charges in the Meyer-Sieved and Teorel15 theory of permselective membrane behavior. F01 is a formation resistivity factor referred to a hypothetical equilibrating solution resistivity of 0.01 ohm m at 25C,* where clay effects presumably are minimized. F01 was correlated to porosity by an Archie-type equation.6 The Hill-Milburn equation describes their data with a standard deviation of approximately 1 percent and a maximum deviation of + 10 percent. Shaly sands behave as permselective cation-exchange membranes, their electrochemical efficiencies increasing with increasing clay content. The electrochemical potential data of Hill and Milburn were expressed graphically, and demonstrate that the membrane efficiency (or cation transport number) of these sands is a function only of the b value (i.e., Qv) and the respective salt concentrations of the two solutions forming the liquid junction in the sand. The diffusion potentials are not dependent on F01 or any parameter relating to the porosity or pore geometry of the rock. The Hill-Milburn resistivity equation correctly predicts a decreasing sand conductivity Co with decreasing solution conductivity C?. However, at some low value of C,, the calculated Co-C, function goes through a minimum; with further decrease in C?, the predicted sand conductivity increases sharply. As pointed out by Hill and Milburn, an increasing value of Co with decreasing C, is physically meaningless. Since this occurs below the range of practical values of C,, the usefulness of the empirical equation is not affected when

Jan 1, 1969

By R. H. Widmyer, G. M. Wood

This investigation was prompted by the absence of a simple, accurate method to predict optimum second stage separation pressure in three stage separation operations. Three stage separation as used here includes two separators plus the stock tank. The first stage pressure is usually fixed by gas sales conditions and the third stage is at atmospheric pressure. Thus, the second stage pressure is the only one that may be varied in-discriminantly during production operations. No variations in temperature were considered in this study, even though it will vary among systems, for a change in temperature has little effect on the optimum pressure. Optimum pressures may be determined from flash calculations, but these are tedious unless a computer is available. An early attempt to develop a simpler method&apos; yielded an equation which gave the optimum pressure only as a function of initial and final pressure. Experience, however, confirms theoretical relationships which show that composition as well as pressure and temperature must be a factor. This indicates that the basic relationship should be an equation of the form, where P, is second stage pressure, P, is first stage pressure, A is a function of P. (stock-tank pressure) and the system composition, and n is a function of the number of stages and the system composition. Fig. 1 shows the basic variation of P2 with P for a fixed system composition. A series of such figures clearly showed the effect of composition. The peak of each curve reflects that second stage pressure at which the stock-tank recovery (gal/MMcf) residue gas is a maximum value. DEVELOPMENT OF NEW CORRELATION Wellstreams having 17 different analyses, ranging from low gravity crude to condensate, were used to determine the effect of composition. Each wellstream was flashed through three stages to determine the optimum second stage pressure for each first stage pressure. Equilibrium vaporization ratios proposed by Latham and Campbell were used throughout. The heptane plus fraction, for simplicity, was assumed to have the properties of octane. The results were subjected to an empirical analysis in an attempt to develop a correlation- that would be (1) simple, (2) accurate, and (3) eliminate the need for any flash vaporization calculations. This analysis yielded two equations, one for wellstreams having a specific gravity greater than one (air = 1.0) and one for those less than one. For crude streams (specific gravFor condensate (specific gravity < 1.0),

By H. Guyod

The response of the Guard Electrode sonde (LL3) and the Laterolog (LL7) can be mathematically computed only for cases that do not represent realistic conditions. A resistance network analogue that simulates a number of typical—although idealized—formations was used instead to obtain, for both devices, a large number of resistivity logs and current distribution maps. From these data, charts were prepared for estimating true resistivities under a number of conditions. Some of these charts and current distribution maps are presented. INTRODUCTION Two main benefits are expected from a resistivity log: (1) obtaining geological information for mapping and other purposes, and (2) obtaining petrophysical data, based on true rock resistivity. The geological information can be derived from any resistivity curve having sufficient vertical detail, but true rock resistivities frequently are difficult to determine with desired accuracy because we do not have sufficient interpretation data. This is particularly true for the records given by the Laterolog tools. The object of this paper is to throw some light on the factors affecting the responses of these tools so that better resistivity data can be obtained from Laterologs. LATEROLOGS Laterolog measuring systems are of two types: the LL3 sonde, frequently called "Guard", and the LL7 sonde. Both measure the resistance between a single exploring electrode placed in the borehole and a faraway return electrode whose influence will be assumed here to be negligible. Although the principles of these tools have already been outlined,1-3 it is desirable to review them briefly in this article. LL3 Fig. 1, left side, represents a long cylindrical, vertical current electrode placed in a medium of uniform resistivity. The current leaving the center section of the electrode flows essentially along horizontal lines, delineating a surface having the shape of a biconcave lens. It is the elec- trical resistance offered to this particular group of current lines that is measured by the Guard tool. This is done in practice by having a long cylindrical electrode consisting of three sections physically and electrically separated by thin insulating washers, as shown in the center of the figure, and keeping the three sections at the same potential. It is obvious, for all practical purposes, that the current and potential distributions about this electrode are the same, as if we had a continuous electrode of same dimensions. Because the three sections are electrically separated, the resistance seen by the center section E can be independently measured. This section will be called the exploring electrbde, or E electrode. Its height generally is from a few inches to 1 ft. The outer sections are the guards G, which are several feet long. The combined length of the three sections is from 10 to 12 ft for the tools currently used in the petroleum industry. Let V denote the potential difference between E and the faraway return electrode, and I be the current flowing between these two electrodes. The resistance (Re) seen by the exploring electrode is VII, and the corresponding apparent resistivity is Ra = k(Re),............(1) where k is the tool calibration factor. The previous description establishes that the Guard tool uses that central portion of the sonde from which, in a uniform medium, the current follows essentially horizontal paths. When the formation being logged is fairly uniform, and when its resistivity is of the same order as

Jan 1, 1965

By Edward B. Walker, Michel Grosmangin

The geological and economic conditions peculiar to the Greater Oficina area are presented to demonstrate the necessity of a low-cost, well-site method of distinguishing gas-bearing formations. The method of gas detection with the neutron log is briefly discussed and its limitations are explained. A new method is described which consists in running a second neutron log with a larger source-to-detector spacing. Field data indicate that under favorable conditions the larger spacing response is proportionately more influenced by the virgin gas zone than is the shorter spacing response. One important condition is that the gas sands be invaded, with a diameter of invasion equal to about two to three times the hole diameter. The calibration of the longer spacing log is made so that the two logs read the same deflection in shale and in a known water or oil sand. Under such conditions, gas is indicated by a positive separation, i.e., the curve for the longer device is displaced to the right of the curve for the shorter device. Because of the non-linearity of the long spacing response, low porosity formations also show positive separations. In sands with large porosity variations, the gas sands can no longer he located visually. They can be detected on a plot of shorter spacing vs longer spac-ing deflections. INTRODUCTION In the Greater Oficina area of Eastern Venezuela, the rapid and accurate detection of gas from well logs is of primary importance because of a combination of economic, geologic, and operational conditions. Briefly, these conditions are: economic—there is no market for gas at the present time; geologic—a single well may contain as many as 30 or more oil or gas sands for which intervals -to be tested must be selected; opera-tional—first, once opened to the casing through perforations, gas sands are extremely difficult and expensive to squeeze off, and second, gas detection must be rapid because the geologist must decide immediately, at the well, which sand to perforate. During the early period of exploitation in Greater Ofi-cina, when clay base muds were used, sidewall samples, together with electric logs, gave fairly good distinction between oil and gas sands. When exploitation became concentrated on deep fields of poorer sidewall sample recovery, and after the advent of oil emulsion muds, now the standard drilling fluid in Greater Oficina, the regular neutron log became the most reliable indicator of gas. In 1953, R. Norelius devised the dual-spacing neutron technique for gas detection. The dual-spacing neutron log has proved to be highly successful in detecting gas and has been adopted as a regular survey by all of the oil companies of the area. Several hundred dual-spacing neutron logs have been run in Eastern Venezuela and several tests per well are available for positive evaluation of the logs. The findings outlined below are based upon this extensive field experience. GEOLOGICAL CONDITIONS OF THE GREATER OFICINA AREA The Greater Oficina area lies on the south flank of the Eastern Venezuela Basin (Fig. 1). Nearly all accumulations of oil and gas in the area are trapped, in whole or in part, against normal faults. All known oil and gas reservoirs in Greater Oficina occur in the Ofi-cina formation (Miocene-Oligocene) or in the "U" sands. The U sands are the lithologic equivalent of the Merecure group (Otigocene-Eocene), which contains oil in many fields north of Greater Oficina. Most of the petroleum produced in Eastern Venezuela is from the Oficina formation.

Jan 1, 1958

By W. B. Nelligam, J. Tittman

Refinements in radiation logging techniques during recent years have involved increasing usage of scintillation ditectors. These detectors produce voltage pulses whose heights are related to the energies of the gamma rays which initiate them. Analysis of the gamma-ray spectrum, as indicated by the pulse heights, yields information about the chemical elements composing the formations surveyed. Refined scintillation counter techniques can furnish chemical information concerning earth formations in situ, from a study of the gamma-ray spectra emitted by the formation either naturally or as a result of neutron bombardment."&apos; Accompanying the rising interest in gamma-ray scintillation spectroscopy, there has been increased activity in the development of accelerator-type neutron sources (in contrast to encapsulated chemical-mixture sources). Such neutron generators are attractive for several reasons: (1) they greatly reduce radiation hazards to personnel; (2) there is a great reduction in contamination danger if they are lost in the hole; (3) they can produce larger neutron intensities than can conveniently available encapsulated sources; and (4) they are capable of being pulsed, thus permitting new techniques in logging. In the past, both accelerator and encapsulated neutron sources have been used by others in conjunction with scintillation-detector pulse-height analysis. The results have not been too encouraging, due to the interference among different gamma-ray spectral lines and to the fact that the gamma-ray peaks were not too clearly distinguishable above the large and ill-defined background "noise".&apos;.&apos; This paper is a status report on laboratory studies of a technique using a borehole accelerator as a neutron source, which gives an improved scintillation spectrum, thus permitting more accurate chemical analyses of the formations penetrated. The Schlumberger-accelerator neutron source&apos; is presented; the origins of inelastic and of thermal-neutron, capture gamma rays are dis- cussed, and results are given for some laboratory measurements performed in borehole geometry. THE NEUTRON GENERATOR-TUBE ACCELERATOR In the attempt to develop an accelerator neutron source which would have the desirable properties outlined in the "Introduction" and which would operate satisfactorily under borehole logging conditions, a small-diameter, cylindrical, neutron generator tube has been developed. This tube utilizes the principle of accelerating deuterons (heavy hydrogen nuclei) by a high voltage so that they bombard a tritium (heavy, heavy hydrogen) target. The resulting reactions produce large numbers of neutrons of 14 Mev energy. Furthermore, the tube is permanently sealed and, thus, the use of pumping techniques in the sonde is avoided. The tube consists of a pressure control, an ion source in which the deuterons are stripped of their electrons, an accelerating gap down which the deuterons are sped by the high voltage, a secondary electron suppressor and a tritium-loaded target. Obviously, the tube requires auxiliary circuitry in a sonde for the control of the ion source, tube pressure, high voltage and other operating variables. Neutron yields, both continuous and pulsed, have been produced under simulated field conditions in the range between 1 and 10 times those conventionally used in neutron logging applications. For the experiments discussed in this paper, neutron-pulse repetition rates in the range between 500 and 5,000 pulses/sec are adequate. Furthermore, by making suitable adjustments in operating conditions, one can vary the pulse width from a minimum of several microseconds up to dc. As will be seen later, the present application to well logging does not require that one have available pulses of neutrons which are appreciably shorter than the time it takes for fast neutrons to slow down to thermal energy in water. As a consequence, much of our interest has been directed towards the operating characteristics of the tube with pulses longer than about 10 microseconds in duration. Our experience to date shows that tubes can be operated in this manner with reasonably constant, average neutron outputs.

Jan 1, 1966

By R. H. Winn

In this paper a heterogeneous carbonate reservoir is considered as a succession of layers of formations of radically different porosities, permeabilities, water saturations, and rock matrix types; i.e., the heterogeneity is vertical rather than radial to the wellbore. Presumably each layer is more or less homogeneous. To determine the "net oil in place" in this reservoir it is desirable to know the porosity and water saturation of each layer. In addition, the section must be subdivided into that which will produce oil, that which will produce water, and that which will produce little or nothing. In numerous wells drilled in these reservoirs radioactivity surveys, guard electrode surveys, and caliper surveys have been made. These logs have been compared with core analysis data, when available, and the analysis of the surveys compared with production data. This study, still in progress, is intended to provide improved analytical techniques if such are possible. This paper is a progress report on the work. DETERMINATION OF POROSITY The neutron-gamma log has long been recognized as a measure of hydrogen concentration.1,2,3 In reservoirs that are free of clay, shale, or other hydrogen containing matrices, it has been accepted as a measure of porosity.4,5 Empirical methods to relate relative neu-tron-gamma intensity to porosity are often employed." To provide a more precise determination of porosity from the neutron-gamma log each instrument is calibrated immediately prior to each survey by a method which refers all tools to a hydrogenous cylinder. To insure stability a calibration check is made after each survey. These calibration records are printed as an integral part of the log that is recorded in standard counts per second. A detailed description of the calibration procedure is available in the literature.&apos; The procedure employed insures that each Survey is numerically reproducible within the limits of statistical variation. To relate the standard neutron counts per second to porosity and hole size, records were made in test wells constructed of blocks of limestone. The porosities of the blocks were accurately measured and the blocks completely saturated with fresh water. Fig. 1 presents some of the results obtained in these test wells.&apos; The lines shown in Fig. 1 were obtained by deriving an empirical equation relating the 11 points shown so that the relationship may be projected to larger and smaller hole sizes. A detailed description of the tool is available in the literature.&apos; Field tests indicate that the tool is adjacent to the wall of the hole most of the time when the surveys are made in uncased holes drilled with saline muds. In this circumstance porosity may be calculated from Fig. 1 if the hole size is known. When fresh muds that form thick mud cakes are employed, the centralizing effect of the mud cake must be considered and the porosity determination is less reliable. In cased holes the combined effect of variations in hole diameter and the unknown eccentricity of the casing in the hole may make porosity determinations extremely unreliable. In any event, an accurate knowledge of hole size is essen-

Jan 1, 1958

By J. T. Dewan

An experimental setup is described whereby the responses of Neutron logging instruments have been determined opposite formations of different porosities and under various borehole conditions. The results of these tests are presented in several charts which show how the Neutron log is affected by the following factors: hole diameter, casing, cement, salinity and weight of drilling mud, and position of logging tool with respect to the wall of the hole. The responses in the case of empty holes are also shown. A chart is furthermore presented which shows the shapes of the Neutron log, as a function of logging speed and time constant, at the boundaries between two formations with different porosities. These were derived mathematically using as a basis laboratory determination of the shape of the curve under static conditions, i.e. at very low logging speed. Corrections for the readings made opposite thin beds are given by these computations. The correction is found negligible under usual logging conditions for beds thicker than about 4 ft. INTRODUCTION The Neutron log is used in borehole surveys both for the delineation of porous formations and for the quantitative estimation of their porosities.1,2,3,4,5 It is common practice to calibrate the response of the Neutron log in terms of porosity values for each given geological unit by means of empirical comparisons between the deflections of the neutron curve and the porosity values given by the core analysis in a sufficient number of wells. Usually, the plots of the porosity values vs Neutron log deflections show a definite trend. It is therefore possible to trace an average line across the plotted points. This average line constitutes a calibration curve which can be used to evaluate the porosities from the Neutron logs in the other wells drilled in the same region. Futhermore, when the porosity values are plotted on a logarithmic scale and the Neutron log deflections on a linear scale, the calibration curve is practically a straight line. Accordingly the calibration curves are often determined by simply tracing a straight line between two points corresponding to two widely different porosities. Different choices are made for these two points, depending on local conditions. For example, one point will be defined by plotting the deflection of the Neutron curve opposite a formation known to be very tight, for which an average porosity value of 1 or 2 per cent is assumed. The other point may correspond to shale sections, to which a porosity of around 40 per cent is ascribed. The information provided by the eletrical logs — in particular the Laterolog, Limestone log or Micro-Latero-log — is also very often a help in the calibration of the Neutron logs. Empirical approaches such as these make possible the derivation of fairly reliable porosity values from the Neutron logs in many cases, at least in open holes and in essentially clean formations. There are, however, several causes of uncertainty which may sometimes entail appreciable errors. On the one hand, the Neutron log readings are influenced by the borehole conditions: hole diameter, presence or absence of casing and cement, presence or absence of drilling mud, characteristics of the mud, and position of the logging instrument with respect to the wall of the hole. The amplitudes of the curves opposite thin beds are furthermore atfected by the bed thickness,

Jan 1, 1957

By A. A. Venghiattis

A rational approach to the selection of the appropriate perforator to use in each specific zone of an oil well is presented. The criteria presently in use for this choice bear little resemblance with actual down-hole condilions. These environmental conditions affect the elastic properties of rocks. One of these elastic properties, acoustic velocity, is suggested as the leading parameter to adopt for the choice of a perforator because, being currently measured in the natural location of the formation, it takes into account all of the effects of compaction, saturation, temperature, etc., which are overlooked in the laboratory. Equations and curves in relation with this suggestion are given to allow the prediction of the depth of perforation of bullets and shaped charges when an acoustic log has been run in the zone to be perforated. INTRODUCTION When an oil company has to decide on the perforator to choose for a completion job, I wonder if it is really understood that, to date, there is no rational way of selecting the right perforator on the basis of what it will do down-hole. This situation stems from the fact that the many varieties of existing perforators, bullets or shaped charges, are promoted on the basis of their performance in the laboratory, but very little is said on how this performance will be affected by subsurface conditions such as the combination of high overburden pressure and high temperature, for example. The purpose of this paper is to show the limitations of the existing ways of evaluating the performance of perforators, to show that performances obtained in laboratories cannot be extended to down-hole conditions because the elastic properties of rocks are affected by these conditions and, finally, to suggest and justify the use of the acoustic velocity of rocks, as the parameter to utilize for the anticipation of the performance of a perforator in true down-hole environment. EVALUATING THE PERFORMANCE OF A PERFORATOR It is natural, of course, to judge the performance of a perforator from the size of the hole it makes in a predetermined target. Considering that the ultimate target for an oilwell perforator is the oil-bearing formation preceded in most cases by a layer of cement and by the wall of a steel casing, the difficulties begin with the choice of an adequate experimental target material. For obvious reasons of convenience, the first choice that came to the mind of perforator designers was mild steel. This is a reasonable choice for the comparison of two perforators in first approximation. Mild steel is commercially available in a rather consistent state and quality, and is comparatively inexpensive. The trouble with mild steel is that it represents a yardstick very much contracted; minute variations in depth of penetration or hole diameter and shape may be significant though difficult to measure. The penetration of projectiles in steel being a function of the Brinell hardness of the steel (Gabeaud, O&apos;Neill, Grun-wood, Poboril, et al), it is often difficult to decide whether to attribute a small difference in penetration to a variation on the target hardness or to an actual variation on the efficiency of the projectile. Another target material which has been widely used for testing the efficiency of bullets or shaped charges in an effort to represent a formation—a mineral target as opposed to an all-steel target—is cement cast in steel containers. This type of target, although offering a larger scale for measuring penetrations, proved so unreliable because of its poor repeatability that it had to be abandoned by most designers. The drawbacks of these target materials, and particularly their complete lack of similarity with an oil-bearing formation, became so evident that a more realistic target arrangement was sought until a tacit agreement was reached between customers and designers of oilwell perforators on a testing target of the type shown on Fig. 1. This became almost a necessity about seven years ago because of the introduction of a new parameter in the evaluation of the efficiency of a perforator, the well flow index (WFI). The WFI is the ratio (under predetermined and constant conditions of ambiance, pressure and temperature) of the permeability to a ceitain grade of kerosene of the target core (usually Berea sandstone) after verforation. to its vermeabilitv before perforation. The value of this index ;or the present state if the perforation technique varies from 0 to 2.5, the good perforators presently available rating somewhere around 2.0 and the poor ones around 0.8, There is no doubt that, to date, the WFI type of test is by far the most significant one for comparing perforators. It is obvious that a demonstration of a perforator

By J. P. Myers, A. H. Flagg, E. S. Mardock, J. L. P. Campbell, J. M. Terry

The development process for the use of radioactive tracers as a means of locating zones of permeability is discussed. The general techniques for the safe handling of radioactive materials is given as developed by the Lane-Wells Co. and Well Surveys, Inc. The prob1em and. successes with tracers in waterflood systetns, oil and gas injection profiles, fracture sand tracing, squeeze (ement tracing. lost circulution, and cement top localion are discussed and illustrated. INTRODUCTION The exact location of the permeable zones lying within the productive horizon has been a major problem faced by the petroleum engineer for decades, and it has been a problem which has seldom been solved with certainty. Reservoir engineers usually have to incorporate a question mark in their estimates of future reservoir performance because of blanks in the core data. Although the use of radioactivity or electrical logs for the estimation of porosity has been of great assistance in furnishing a record for the reservoir engineer, this application of logging data has not completely solved the problem. In short, the industry needs an in-situ well surveying method which can locate and estimate the permeability of the zones existing within a given pay section. The initial development work with radioactive tracers has been towards filling the need for permeability information. Progress to date permits the location of permeable zones with a qualitative estimate of their relative importance with respect to permeability. The calibration of the method is still incomplete. but present development work on tracer preparations, borehole effect correction factors, and instrument limitations give a promise of quantitative "permeability profiles" in the near future. The development work on the radioactive tracer method discussed here began several years ago in the laboratories of Well Surveys, Inc., in Tulsa. At the outset of this work, three approaches to the problem were visualized as follows: 1. A fluid carrying a soluble, chemically inert, gamma ray emitting isotope is pumped down the borehole and out into the permeable zones of the formation. The greater gamma activity of the permeable zones thus permits them to be differentiated from the impermeable zones which contain no active tracer. It was found difficult to obtain a tracer material which was chemically inert. Absorption to some degree was noted in all experiments. Also, it proved impossible to hold the tracer near the horehole where it could be logged. 2. A fluid carrying a soluble, gamma ray emitting isotope is pumped down the borehole into the permeable formations. In contrast with proposal 1, above. the tracer is chemically active with the fluids and materials in the pore spaces of the permeable zones. The permeable zones are thus indicated by their higher radioactivity level. The main difficulty in this proposal was finding a tracer material which would not be absorbed by shale as well as in the permeable porosity. Very little field work was done with this system. 3. Radioactive particles suspended within the injection fluid are pumped down the well. As the fluid enters the permeable formations, the radioactive particles are filtered out on borehole wall. The permeable zones are differentiated from the impermeable by the gamma ray activity deposited on the formation wall.

Jan 1, 1956