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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 G. H. Pardue, L. H. Gollwitzer, J. H. Moran, R. L. Morris

Experimental and theoretical studies of casing-borne signals have provided data on the attenuation efect, compressive strength and shear modulus for different types of cement. These data resulted in the establishment of a definite relationship between the cement compressive strength and the Cement Bond log reading. The relationship is influenced by the casing dimensions, but is independent of the type of cement and the curing conditions. The theoretical analysis provides a mathematical statement of the phenomenon and shows that the attenuation rate is basically a function of the shear modulus of the cement and the thickness of the casing. The lab tests provided a connection between the shear modulus and the compressive strength, and permitted a comparison of the experimental and theoretical work. The results of the experimental and theoretical study have provided means of quantitative interpretation of the Cement Bond log. This interpretation is made more convenient with the use of a nomograph. INTRODUCTION Past interpretation of Cement Bond logs has been essenlially based upon a qualitative comparison between the log response in the zone of interest and the responses in the "fully cemented" and the "uncemented" intervals. Most of the variables influencing the magnitude of the signals were recognized in an earlier paper'; however, insufficient laboratory data were available at that time for quantitative evaluation of these variables. Early attempts to use the numerical amplitudes of the signals without full knowledge of their significance resulted in erroneous comparisons between various types of cement. An extensive program was undertaken to evaluate, both experimentally and theoretically, the attenuation phenomenon and to study the effects of the more common variables. A major objective of the experimental program was to obtain data on the relationship between cement-bond-tool response and physical property standards used by the industry so that practical interpretation methods could be devised. The studies included a comparison of attenuation rate with these properties as a function of time, temperature and pressure, using common sizes of casing. The main result was that a definite relationship was established between the compressive strength of the cement in inti- mate contact with the casing and the response of the cement bond tool. For a given casing thickness, regardless of the type of cement or the curing conditions used, the attenuation rate is a function of the compressive strength. A theoretical analysis showed that the attenuation rate for casing-borne signals should be a function of (among other things) the shear modulus of the cement and the thickness of the casing. The relationship between the compressive strength and shear modulus for curing times similar to those encountered in the field was determined from laboratory tests. Using this relationship, the computed attenuation rates showed reasonable agreement with the measured attenuation rates. The purpose of this paper is to report the results of the experimental and theoretical investigations and to present the first practical method for a quantitative interpretation of Cement Bond logs based on known variables. This method is applicable where the casing-borne signal is not affected by high-velocity formation arrivals. DESCRIPTION OF LOGGING TOOL The Cement Bond logging tool shown schematically in Fig. 1 has been described previously.' The tool consists of two sections: acoustic and electronic. The acoustic section contains a transmitter and a receiver, usually spaced 3-ft apart. Sonic energy emittted by the transmitter travels through the casing and is detected at the receiver. The electronic section measures the amplitude of the

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 P. E. Baker

An improved method of logging formation density has been developed in which the formation is bombarded with a collimuted beam of gamma rays. By means of a scintillation detector and pulse height discriminator, the gamma-ray energy band is accepted and recorded which corresponds to deepest penetration into the formation. Laboratory tests on a field tool revealed no borehole diameter effect for smooth holes and no effect of formation chemistry, except insofar as chemistry affects density. In extensive field tests, the density log has exhibited satisfactory agree-ment with core measurements and has correlated accurately with other logs. INTRODUCTION This paper describes an improved method of logging formation density by means of back-scattered gamma rays to penetrate the formation together with energy discrimination to select only that energy (or frequency) range corresponding to deepest penetration into the forma- tion. This method of density logging was developed at the La Habra laboratory of California Research Corp.* Field instruments have been built and tested by McCullough Tool Co. and commercial service has begun in some areas. All of the data discussed here were obtained for the original field tool. The density log can be a valuable adjunct to existing logs because of its use in determining porosity quantitatively. It is useful also in connection with seismic and gravity surveys where formation density information is of interest. PHYSICAL PRINCIPLES The intensity, I, of a beam of gamma rays after traversing a distance, x, in an absorbing medium is given by I = loe -ax where I, is the intensity of the beam entering the medium and a the attenuation constant or macroscopic cross section of the medium for gamma-ray absorption. The macroscopic cross section depends on the number and types of atoms per unit volume and the gamma-ray energy. In brief, it is the sum of the atomic cross sections of all atoms per cubic centimeter. The density of the material is the sum of the masses of all atoms per cubic centimeter. Thus, the density and the macroscopic cross section for gam-ma-ray absorption vary in propor- tion to the number of atoms per cubic centimeter. The density of the material increases, of course, if the atomic masses increase without a change in the number of atoms per cubic centimeter. When the density increases in this latter way, the macroscopic cross section increases also, but disproportionately. This results from the fact that part of the gamma-ray absorption arises from the photoelectric effect and the pair-production effect**, which are proportional to the sixth and to the second power, respectively, of the atomic number of the absorber. The remainder of the absorption results from the Compton effect, and is directly proportional to the atomic number. The gamma rays that undergo Compton scattering are not immediately absorbed. Since these rays are scattered in all directions, a fraction will emerge from the face of the medium at which they entered. If a gamma-ray shield is placed between the source and detector, most gamma rays reaching the detector will be those scattered out of the medium. The intensity will depend on absorption and scattering in the medium, and so indicates the density of the medium. For gamma rays for which Compton scattering prevails, the intensity

Jan 1, 1958

By A. E. Worthington, R. F. Meldau

An analog computer study was made of the reduction of the magnitude of the SP by formation geometry and resistivity effects. Practical field .situations were studied. The analog data were converted to the form of departure charts. These charts may he used to determine the reduction in the SP due to the above eflects pith good precision Quantitative interpretation of the SP log in terms of formation water resistivity is presently based on the premise that the observed SP is equal to the electrochemical potential developed across a shale between the mud filtrate and the formation water. This procedure inherently assumes that, first, no electro kinetic (streaming) potential is present, and, second, that the SP is not reduced by resistivity or geometry effects in the formation. When, however, such a reduction of the observed SP does occur, one may write, SP = b,E, b, E, (1) where SP is the observed self-potential opposite the center of the bed under consideration. In this case, E, is the electrochemical potential, E, is the electrokinetic potential, b, is the electrochemical reduction factor, and h, is the electrokinetic reduction factor. The first assumption above is equivalent to assuming E, = O in Eq. 1 and the second assumption is equivalent to h, = b, = 1. Examination of electric logs shows that for many formations of interest the observed SP is reduced below its maximum value. The object of this work is to aid quantitative SP interpretation in at least some of these situations by obtaining values for b, and b, in Eq. 1 as functions of realistic combinations of bed thickness, depth of invasion, and formation resistivity. The only previously published work in this field known to the authors is by H. G. Doll' in 1948. He evaluated b, under conditions permitting exact analytical solution. His work clearly established the importance and qualitative nature of formation geometry and resistivity effects upon the SP, but the necessity of obtaining analytical solutions restricted his study to situations of limited practical interest. In order to extend such studies to practical combinations of formation parameters which do not lend themselves to feasible analytical solutions, the results reported in this paper were obtained by use of a special analog computer. THE ANALOG MODEL The analog model used for this study was the Guyed Analog Computer which originally was designed and built for resistivity log departure curve studies. It consists of a two-dimensional mesh of resistors, with the vertical mesh corresponding linearly to vertical distance along the borehole, and the horizontal mesh corresponding to radial distance from the borehole axis. By proper choice of horizontal resistor values, a three-dimensional, axially symmetric, borehole-formation problem can be modeled with this two-dimensional array. These and other details of the model are contained in a paper by H. Guyod'. The geometry used for the SP studies with the analog is depicted in Fig. 1. This configuration has a horizontal plane of symmetry, and, hence, the model, and the following discussion, need only to be concerned with one quadrant such as shown in Fig. 2. A further simplification arises by considering that both the natural potential sources and those used in the model have fixed internal impedance. Therefore, the current flows produced by these sources can be separated and studied independently ( i.e., the superposition theorem can be applied). SP = SP, i SP, = h,E, + b,E, ,(7)

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 J. L. Martin, W. M. Campbell

A new electric logging method, called displacement logging, often gives a direct indication of the presence of mobile hydrocarbons in hydrocarbon-bearing formations. This method is based on the detection of a bank of connate water which is formed between the invading mud filtrate and virgin formation fluids in these cases. The existence of this phenomenon has beer, verified by laboratory studies and by actual field logs taken in known oil sands. INTRODUCTION During the past decade increasing use has been made of conventional electric logs to determine the amount of oil or gas in formations traversed by a borehole. This determination requires knowledge of several factors, such as true resistivity of the formation, formation factor, and water resistivity. Sometimes all of the factors necessary to make a reliable saturation calculation are not available. Also, the computations and corrections which are necessary in such a study often require the services of an experienced log analyst. It has long been the desire of exploration people to have a logging device which will locate hydrocarbon-bearing formations directly without requiring complex interpretation methods. The displacement log, while not completely fulfilling this desire, appears to be a Step in that direction. Basis for the Device The basis for this device stems from a phenomenon which occurs when mud filtrate invades a formation which contains displaceable hydrocarbons. As the mud filtrate invades the formation, most of the oil or gas is pushed out of the invaded zone, leaving residual oil. However, in addition to displacing most of the oil or gas, the connate water is also swept out, since the originally irreducible water is mobile in the presence of a water phase.1,2,3 Tonsequently, this irreducible water piles up as a bank between the virgin oil zone and the invading filtrate. If the mud filtrate is of higher resistivity than the formation water— as is commonly the case—the resulting annular zone, containing the bank of formation water, will be of lower resistivity than either the virgin oil-bearing formation resistivity or the invaded zone resistivity. This resistivity configuration, going from high to low to high again as the distance from the borehole increases, is found only in those zones which contain displaceable hydrocarbons. A device which would reliably detect this low resistivity zone would give a direct indication of mobile hydrocarbons. Illustrations This phenomenon is illustrated in Fig. 1 and 2. Fig. 1 shows a sketch of a zone containing salty connate water plus displaceable hydrocarbons, along with graphs showing fluid content and electrical resistivity vs distance from the borehole, before invasion occurs. Fig. 2 shows this zone, together with fluid content and resistivity graphs. after invasion by a fresh water mud. The resistivity pattern on moving away from the borehole is high: low: high. The absence of the low zone phenomenon in water zones is illustrated in Fig. 3 and 4. Fig. 3 shows a sketch of a zone containing salty formation water and residual oil, along with graphs showing fluid content and electrical resistivity vs distance from the borehole, before invasion occurs. Fig. 4 shows this water zone, together with fluid content and resistivity graphs, after invasion bv a fresh water mud. In this case the resistivity pattern on moving away from the borehole is high: low since there is no change in water saturation at the head ol

Jan 1, 1956

By J. D. Milburn, H. J. Hill

In quantitative interpretation of electrical logs the presence of clay minerals introduces an additional variable which further complicates an already complex problern. Although recognizing the difficulties introduced as a result of the heterogeneity of natural sediments and despite the present incomplete state of knowledge regarding electrochemical behavior of shales, dissemirzated clay minerals and concentrated electrolytes, it was felt that useful empirical correlations might be obtained from experimental investigation. Six typical sandstone formations, having a wide variety of petrophysical properties, were selected for the study. Approximately 45 samples from each formation were selected to satisfactorily represent the range of pore size distribution within the particular formation, As a matter of general interest, four limestone formations were also included in the investigation. Previously proposed equations relating to resistivity, SP and interrelationship of the two phenomena have, where possible, been tested with data obtained in this investigation. These equations do not satisfactorily describe experimental behavior of samples through all degrees of shaliness or throughout the range of brine solution resistivities normally encountered in logging practice. An empirical equation has been developed which quantitatively relates formation resistivity factor to satirrnting solution resistivity, porosity, and "effective clay content." This relation is indicated to be uniformly applicable to clean or shaly reservoir rocks. It is shown that both the SP and resistivity phenomena of shaly samples are related to the sample cation exchange capacity per unit pore volume. The independent chemical determination of this parameter is thus a means of determining the "effective clay content" of samples. Some implications regarding theory and electric log interpretation of shaly sands are discussed. INTRODUCTION The use of electrical resistivity logs as a means for estimating formation porosity is based upon the original work of Archie1. It was shown by empirical methods that the resistivity of a rock, when 100 per cent saturated with brine solution, could be related to rock porosity through the equation, F = Ro/ RW = f-m.......(1) where F, the formation resistivity factor, is defined as the ratio of the resistivity of the 100 per cent water saturated rock, Ro, to the saturating solution resistivity, Rw; f is the ratio of pore volume to bulk volume; and m is the slope of the average line when the data are plotted on log-log paper. This relation was established for relatively shale-free formations containing water having high salt concentrations, and under these conditions F may be considered constant for a given rock sample. Applications of Eq. 1 to interpretation of logs of shale-free formations has been quite successful when satisfactory formation water resistivity data could be obtained. The most readily available means of estimating formation water resistivity is the self-potential log. Conventional methods of SP log interpretation involve correct.

Jan 1, 1957

By G. H. F. Gardner

The velocity and attenuation of elastic waves in sandstones were measured as a function of both pressure and fluid saturation. A large change occurs in these quantities if water is added and the rock is not compressed, but the change is small if the rock is subjected to a large overburden pressure. Measurements were made by vibrating cylindrical samples in both the extensional and torsional modes at frequencies up to 30,000 cycles/sec. Formulas were derived which enable the attenuation of dilatational waves in dry rocks to be deduced from the data. Similar experimental methods were used to investigate the properties of unconsolidated sands. Velocities were found to vary with the 1/4 power of the overburden pressure and attenuations to decrease with the 1/6 power. The effects of grain size, amplitude and fluid saturation were studied. Formulas by which the effects produced by a jacket around the sample may be calculated were derived. The practical application of these results to formation valuation is discussed. INTRODUCTION The attenuation of elastic waves in the earth has been of interest to the seismologist and geophysicist for many years, but only recently to the petroleum engineer. Engineering interest has been brought about by the success of velocity logging devices, for it is possible by modification of these instruments to measure the attenuation of sound waves in addition to their velocity and, hence, deduce the mobility of formation fluids as well as the porosities of the rocks which contain them. The main problem is to decide whether field measurements can be made with sufficient accuracy to be of practical use. This problem can only be solved after we know the magnitude of the attenuations which are typical of the earth at various depths. The logarithmic decrement of a fluid-saturated rock is the sum of a "sloshing" decrement and a "jostling" decrement, the former caused by the mobility of the fluid contained within the rock and the latter by the granular framework of the rock. Sloshing decrements can be calculated' using Biot's theory, but the jostling losses are less well understood. The present paper reports an experimental investigation of jostling losses in consolidated and uncon- solidated sands, particularly with respect to the effect of overburden pressure and fluid saturation. Born' showed that the decrement of a sandstone may increase dramatically when only a few per cent by weight of distilled water is added, and that the additional loss is proportional to the frequency of vibration. His measurements were made with no compressive stress on the framework of the rock. M. Gondouin3 investigated similar phenomena for fluid-saturated plasters but also did not compress the samples. In the present paper it is shown that compression of the framework reduces this effect, so that at depth the jostling decrement of a sandstone may be expected to be almost independent of fluid saturation and frequency. Decrements for many sedimentary rocks have been given by Volarovich,4 but all for the state of zero overburden pressure. Anomalously low velocities have been logged in shallow unconsolidated gas sands. Results of the present investigation confirm that these velocities are not caused by correspondingly high attenuations, because the jostling decrement in a packing of sand grains is small and much less than in a consolidated sandstone at the same depth. Velocities in sands have been measured by Tsareva5 and by Hardin6 as a function of pressure, but the corresponding decrements do not appear to have been measured previously. The widely used "resonant bar method" of measuring velocities and decrements was employed. Comments on variations of this technique have recently been published by McSkimmin.7 The main novelty of the present technique was the application of pressure to the samples. It was found possible to do this by placing the apparatus inside a pressure vessel, provided the conditions leading to large additional losses were avoided. These conditions are discussed below. EXPERIMENTAL TECHNIQUE Cylindrical samples were caused to vibrate in both the extensional and torsional mode of vibration and the amplitude of vibration was measured as a function of frequency in the neighborhood of a resonant frequency. The resonant frequency, fr, is related to the corresponding elastic modulus by the formulas where E and N are Young's modulus and the modulus of rigidity, p is the density of the sample, and A the wavelength of the vibration.

Jan 1, 1965

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 S. R. Bardsley, S. T. Algermissen

Induction, nuclear and sonic well-logging methods were employed in a Green River formation oil-shale analysis and evaluation study conducted in northeastern Uintah County, Utah. The physical and chemical properties of an oil-shale section, previously cored and assayed by conventional methods, were used to evaluate the response of the various logs. The logging program was designed to measure variable properties of oil shale which relate to oil-yield potential in order that a relationship between assay-oil yield and log-determined properties could be identified, thereby permitting a direct determination of yield potential from logs alone. All of the major oil-shale zones and section ttlarkers are recognizable on the logs used in the study. The relationship between the response of the Density and Sonic logs and the assay-oil yield in gallons per ton was suficient to perinit the derivation of equations expressing the relationships. These equations can be used to determine the potential oil yield in gallons per ton of an oil-shale zone or section. The Neutron log response distinguishes the rich oil-shale intervals from the lean intervals, but does not appear to permit establishment of a quantitative relationship. The Garnma-Ray and Induction logs indicate only a qualitative relationship to oil-shale yields. Logging oil shale by Gamma-Gamrna Density and/ or Sonic logging methods will permit a fast, economical and accurate means of evaluating the potential yield of oil-shale deposits. Considerable sums of money have been allocated to Green River formation oil-shale evaluation during the past years by both private enterprise and Federal and state governments. The result of the work accomplished to date is commendable, but the task of fully exploring and evaluating one of the world's greatest reserves of potential energy for economical exploitation is enormous and much information is still needed. Present methods of evaluation consist primarily of sampling and assaying the oil shale for potential yield. The data received are excellent, but are both costly (inasmuch as it requires funds specifically allocated for the evaluation purpose) and time-consuming (as each representative sample must be assayed in the laboratory by specially trained personnel). At the present time, the Green River formation oil-shale province is one of the most active areas in the Rocky Mountain region for exploratory oil and gas drilling. This activity could play a twofold role and serve the function of spear-heading many oil-shale evaluation programs, as it could provide both cutting samples for assaying, geophysical data and modern well logs. This paper deals with a recent study conducted on Green River formation oil shale in which the application of induction, sonic and nuclear well logs to oil-shale evaluation was tested and proved. THEORY AND DEFINITIONS Oil shale may be described as siliceous marlstone, rich in solid organic matter called "kerogen". Kerogen is only slightly soluble in organic solvents, but it will decompose and yield oil vapors and gas when heated to destructive distillation temperatures at about 800 F. The mineral constituents of Green River formation oil shale are found in essentially uniform proportions with one another. The dominant types are, in the general order of abundance, dolomite, calcite, feldspars and quartz. Kerogen is also essentially uniform in its composition, and is about 80 per cent carbon and 10 per cent hydrogen by weight. The ratio of kerogen to the mineral constituents determines the richness or potential yield of the oil shale. This ratio also determines the total physical and chemical properties of the rock and provides a basis by which oil-shale richness may be determined from well logs. Because Green River formation oil shale was deposited in a lacustrine environment, the lithology is laterally consistent over wide areas. The vertical section consists predominantly of thin bands of alternating rich and lean oil shale which have been described by Bradley' as varves. The varves are occasionally broken by thin bands of volcanic ash and tuff and by zones of lean vugular oil shale. The effect that the thin non-oil shale beds and vugular zones would have on the well log analysis was a prime concern in the study. To cope with this possible problem, the logs used in the study were of two types: (1) logs believed to respond favorably to those properties of oil shale which are dependent upon the kero-gen-to-mineral ratio, these logs being the Gamma-Gamma Density log, the Sonic log and the Neutron log; and (2) logs that would respond to litho-logies and properties within the oil-shale section not associated with yield that might result in anomalous responses by the yield-measuring logs. Logs of the second type were the Gamma-Kay log, the Induction log and the Caliper log. THE PRESENT STUDY The present logging study was con-

By B. G. Agnew

In evaluating fracture treatments, the need to answer such questions as "What zone or zones were actually treated?" and "What was the vertical extent of the treatment" is necessary, since determining effectiveness of the fracture treatwrent depends on knowledge of the reservoir portions stimulated and the vertical extent of the fracture system or systems. Injection of hot or cold fluids during fracturing operations will transfer heat to the surrounding formations and fracture faces mainly by heat conduction. Once injection ceases, temperature anomalies will develop opposite the zone fractured because the rate of temperature decay is less than that opposite zones heated or cooled by flow inside the wellbore or along the cement sheath. Thus, temperature surveys can he used to determine where fractures were generated outside the wellbore and to reasonahly estimate the vertical extent of the fractrires. This technique has been used successfully to evaluate over 344 fracture treatments at depths ranging from 1,500 to 15,700 ft. Examples of actual temperature surveys are presented to show how this method of fracture treatment evaluation can be used effectively and beneficially. INTRODUCTION Stimulation of producing or injection wells by fracturing is commonplace in the industry today. In evaluating these treatments, two basic questions which arise are "What zone or zones were actually stimulated?" and "What was the vertical extent of the treatment?". Knowledge of the reservoir portions stimulated and vertical extent of the fracture system or systems is vital to effect efficient and economical well completions and to assure maximum recovery from reservoirs. Not all fracture treatments are successful and many times the desired or anticipated results are not achieved. When this occurs, it is in most cases the engineer's job to determine why. The answer to this problem forms the primary basis for deciding whether to spend more money for development drilling and/or completion attempts or to forego additional expenditures to improve the particular zone. Also, knowledge of the reservoir portion actually stimulated is invaluable in planning future workovers. This is especially true in wells producing from reservoirs containing multiple porosity stringers or zones. For various reasons, all zones within a reservoir may not be perforated on initial completion with the thought of developing remaining zones through future workover operations. Because particular zones are perforated and fracturing fluid pumped down the wellbore, it cannot be assumed that all perforated zones are stimulated, and in turn drained. Occasionally, unperforated zones which are planned for future development are actually stimulated on initial completion. eliminating the need for future recompletion attempts or all zones perforated initially are not stimulated, thus requiring additional completion work to insure that these zones are adequately drained. In most cases, it is costly. if not impossible, to determine with assurance why a fracture treatment is unsuccessful after the job has been completed and the results tested. Further, unpredictable upper and lower fracture barriers. as well as possible borehole communications (cement channels), do not permit it to be taken for granted that the formation opposite the perforations is the only zone receiving the fracture treatment. Thus. evaluation of fracture treatments is necessary for efficient and prudent well completion practices and should be done simultaneously with the fracture job. Several methods have been used to locate fractured zones, all of which are based on detection of radioactive tracer materials added to either the fracturing fluid or the propping agent. These methods have been helpful in increasing knowledge of fracturing operations; however, they are seriously limited because of cost and inability to detect accurately radioactive tracer material more than a few inches away from the borehole. To develop a better diagnostic tool to pinpoint which zone or zones had actually been fractured, temperature surveys were run after fracturing with heated and cooled fluids. Significant temperature anomalies were found to exist opposite zones suspected of receiving the fracture treatment. From the analysis and examples to be shown, it can be seen that temperature surveys run in a stabilized wellbore several hours after a fracture treatment using hot or cold fluid will yield temperature anomalies which show the actual reservoir portion stimulated, the vertical extent of the fracture system or systems and a qualitative indication of the portion of fracture-fluid volume entering a given depth interval. The experience and illustrations used in this paper are based on evaluation of over 344 fracture treatments during the past three years using this diagnostic tool at depths ranging from 1.500 to 15,700 ft and fracture volumes ranging from 2.000 to 110.000 gal. Based on analyses of these temperature surveys, analyses of fracture gradients and evaluation of several open-hole packer impressions in the West Texas area,' vertical fracturing is the predominant mechanism and horizontal fractures occurred frequently, if at all.

Jan 1, 1967

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 R. C. Davis, R. F. Berry, G. W. White, B. T. O’Connell, L. A. Stacha

The formation density logging tool provides a radioactivity measurement that yields formation densities in situ. The relationship between bulk density and porosity is well understood. With knowledge of grain and fluid densities, porosity may be computed from the indicated formation bulk densities in shale-free formations. The porosities thus determined may be used with a resistivity log for water-saturation determinations. One technique utilizes a density vs resistivity plut. A plot of density vs Sonic-log transit time is used for porosity determinations in shaly sands. This method is particularly suited to wells drilled with oil-base or salt muds. In shale-free formations, comparisons of density values nnd neutron-log readings are used to identify lithologr and, thus, to select appropriate values of grain density for porosity computations. Through the use of Formation Density, Sonic and neutron logs, the interpretation problems caused by complex matrix lithologies are simplified. Other applications of the Formation Density log are found in the identification of minerals in evaporite deposits and in yield determinations of "oil shales". INTRODUCTION Widespread field application has demonstrated that the measurement of formation density is a useful and revealing technique for well logging. Responding to the bulk density variations of the formation, the Formation Density log affords valuable data on the porosity, lithology and fluid content of the formations. Although not without its own limitations, the Formation Density tool may provide effective interpretation under conditions that hamper or preclude the use of other porosity devices. When used in conjunction with other devices, such as the Sonic or neutron, complex matrix conditions may be better understood, defined and evaluated. A previous paper&apos; described the valuable contribution of the Formation Density tool in the logging of empty, or gas-filled, holes. The purpose of the present paper is to describe applications of the device in liquid-filled holes. THE FORMATION DENSITY TOOL The Formation Density tool was devised to measure the bulk densities of formations in situ. Actually, the device responds to electron density, but in the overwhelming majority of cases of interest, the electron density is very closely proportional to the bulk density. In other cases appropriate corrections can be made if necessary. Comparisons of log-derived densities with true densities for the more common matrix minerals are shown in Table 1. The tool consists of a gamma-ray source and detector mounted in a skid which, during the logging operation, is in contact with the borehole wall (see Ref. 1 for schematic). Gamma rays are emitted by the source and diffused through the formation. The number of diffused gamma rays reaching the detector at a fixed spacing from the source are counted. An increase in counting rate by the detector indicates a decrease in bulk density in front of the skid. Conversely, a decreased counting rate signifies an increase in bulk density. A measurement of hole diameter, between the face of the skid and that of the eccentering arm, is recorded simultaneously with the measurement of diffused gamma rays. Since the tool is a wall-contact device, the size of the borehole has little influence, provided good contact is maintained with the wall of the hole. Only in extremely large or small boreholes does the actual diameter become significant. However, for most accurate measurements the borehole size should be taken into account. Fig. 1 presents the departure curves for the conversion of counting rate to bulk density for liquid-filled holes of various sizes. It is of utmost importance that the skid maintain good contact with the wall of the hole. If, due to roughness or caving, there is mud between the skid and the formation, the tool will include in its response the relatively low-density mud, and the apparent density reading will be too low. Normally, permeable beds do not cave appreciably, so that reliable readings are usually available for zones of interest. Nevertheless, the caliper reading over the zone of interest should be examined for any wall roughness. When mud cake exists between the skid and the formation, the Formation Density log sees it as part of the formation. When thick mud cakes exist, a correction is required. For best results in wells having thick mud cakes,

By G. H. F. Gardner

The boundary conditions F = 1.0 and 4 = 1.0 (100 per cent) are dictated by the definition of F in the equation 1/F = aFp. These conditions have physical significance as the "limiting conditions" for the observed behavior in systems of dispersed particles. The other boundary conditions, cited by Gardner in his Eq. 3 as applying to this system, have no significance in the systems we studied. Maxwell&apos;s equation (Eq. 2) cited in Gardner&apos;s comments was developed for and limited to a regular, rather than random, dispersion of spheres which are sufficiently removed from each other so that they do not interfere with current flow about their neighbors. These restrictions also apply to Rayleigh&apos;s analysis. The title of Rayleigh&apos;s paper cited by Gardner is "On the Influence of Obstacles Arrayed in Rectangular Order upon the Properties of a Medium". He is not discussing randomly dispersed spheres. It might be inferred from Gardner&apos;s comments that Rayleigh specifically considered the differential equation (Gardner&apos;s Eq. 3). This is not the case. Mathematically, Gardner&apos;s Eq. 3 is exactly true for the system to which it applies, however, as both Rayleigh and Maxwell note that their equation for F in terms of F is not for randomly dispersed spheres. At the time we wrote our paper, we were aware of the work of Wyllie and Gregory as cited by Gardner. We cited their work in Ref. 5 of our paper. Our comment on page 287 of the paper about the validity of an m value of 1.3 for spheres with a porosity of 38 per cent remains as our answer to Gardner&apos;s question on this point. Our data, at 38 per cent porosity, show that the condition a = 1 and m = 1.3 holds for spheres near 40 per cent porosity.

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 N. L. Muench, J. S. Osba

Research conducted previously has demonstrated that spectral analysis of gamma radiation from the naturally radioactive elements present in earth materials permits detervination of the relative concentrations of these elements. This research suggested that spectral analysis of gamma radiation resulting from neutron bombardment of elements not nor-mally radioactive might serve to identify these non-radioactive elements, and might permit their quantitative determination. To investigate this possibility, laboratory experiments were conducted in which various earth materials were subjected to bombardment by neutrons from a polonium-beryllium source, and in which the spectra of the resultant gamma radiation were analyzed. The geometry of the lab-ortory system was designed to simulate wellbore conditions. The laboratory work demonstrated that some elements not only can be identified with relative ease, but also can be determined quantitatively. This finding indicates that the use of an intense source of more energetic neutrons may lead to the identification and measurement of additional elements of interest by means of induced nuclear reactions. INTRODUCTION In recent years the applications of nuclear physics to the producing branch of the petroleum industry have become increasingly numerous. One significant development, an outgrowth of nuclear science which is of potential importance in well logging, has been the analysis of gamma-ray spectra of naturally radioactive elements in earth strata. The work of Brannon and Osoba1 has demonstrated that presently available equipment and techniques may be used to determine the relative concentration of thorium, potassium, and uranium in underground strata by means of gamma-ray spectral analysis. Success of the research on spectral analysis of naturally radioactive elements suggested that spectral analysis of induced radioactivity might serve to identify, and perhaps measure quantitatively, those elements which normally are not radioactive, but which become radioactive on neutron bombardment. It was to investigate this possibility that the research described in the following sections was undertaken. THEORY OF INDUCED NUCLEAR REACTIONS Of fundamental importance is the fact that an element, when bom- barded with neutrons, emits gamma rays of energies characteristic of that element. Therefore, in theory, an element may be identified by analysis of the energy spectrum of the neutron-induced gamma radiation. If a neutron impinges upon the nucleus of an atom, any one of several reactions may occur. For identification of elements in earth formations the more important are listed below: 1. The neutron may be elastically scattered, as in a collision between two billiard balls. In this case the total kinetic energy is conserved, and no nuclear radiation is emitted. 2. The neutron may be inelast-ically scattered, as in a collision between two automobiles in which case the total kinetic energy is not conserved. The lost kinetic energy reappears in the form of gamma radiation. 3. The neutron may be captured, in which case the neutron becomes a part of the target nucleus, and a gamma ray is emitted. For example, if the target nucleus is H1, the pro-duced nucleus will be H3, and gamma radiation of a particular energy will be emitted. 4. The neutron may produce nuclear fission, or may enter into miscellaneous reactions which result in the emission of

Jan 1, 1958