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By Robert E. Mclvor

Classification system efficiency (CSE) is a simple metric that can be used to measure and increase ball milling circuit efficiency. It is defined as the percentage of the ball mill energy being used to grind target (oversize) particles. This paper describes CSE analysis conducted for a variety of operations with related improvements in circuit efficiency ranging from 3 to 30 percent. The achievable CSE for any given ball milling circuit is described, providing the means to determine the extent to which every plant can benefit from increasing grinding circuit CSE.

By Anthony Iannacchione, Christopher Mark

Residents of Maxwell Hill, a suburb of Beckley, West Virginia, reported from January until March of 1988 a series of earth tremors. The tremors rattled dishes, and the noises associated with tremors were sometimes loud enough to wake people at night. These events were puzzling because Beckley is in an area of low seismic activity. Maxwell Hill is located above abandoned coal mines, though no direct subsidence damage to surface structures has been documented. A research program was initiated to determine whether subsurface ground movements associated with the abandoned mines could be responsible for the seismic activity experienced at the surface. A hypothesis is proposed which states that seismic disturbances can be caused by abandoned mine failure when two conditions are met. First, some instability must exist at the mine level. The most likely cause of instability is the failure of pillars of coal that were left for support at the time of mining. Second, subsurface movements can result in significant seismic activity only when the rock above the mine contains at least one very strong and brittle layer that is prone to fail violently through rupture or fault slip movement. Analysis of the data indicates that both hypothesized conditions for mine-related seismicity appear to have been satisfied in the case of Maxwell Hill. It has therefore been concluded that the earth tremors experienced by Maxwell Hill residents probably are related to the abandoned mines. Analysis of the potential magnitude of these events indicates that they are unlikely to cause significant surface danlage. The probability that future events will disturb the residence of Maxwell Hill should be quite low based on the identified mechanism.

By J. A. Zimrner, R. J. Tirnko

The roles of main mine fans in underground mines are to induce airflow and continuously re- move hazardous gases and dust. While most larger mines use multiple fans to accomplish these tasks, many smaller mines employ only a single fan. This paper concentrates on those mines having only one fan to provide ventilation needs. If this fan should cease to function, it is likely that methane concentrations will in- crease in some areas of the mine. As a safety precaution, Federal Regulations require that personnel must be- gin evacuating the mine within fifteen minutes after fan stoppage. Powered haulage can be used to transport workers to the mine portal as long as travel is through areas where hazardous levels of methane are not expected. To determine where methane will accumulate along haulageways during a fan stoppage, air samples must be taken at specific areas and analyzed for hazardous gases. During this study, procedures were developed for measuring methane levels along the haulegeways that are used to exit a mine following stoppage of the main mine fan. Methane levels were measured in four different mines at selected underground locations during four planned fan stoppages. In these mines the measurements taken only at the specified locations showed that, if workers had used electrically powered haulage to exit the mine following a fan stoppage, the methane accumulated along haulageways during fan stoppages would not have significantly increased the risk of an ignition.

By H. H. Rachford, D. W. Peaceman

A system of partial differential equations describing miscible displacement of fluids in porous media is derived The system takes into account the influence of gravity, the spatial distribution of permeability, diffusion, and fluid viscosities and densities. A numerical procedure for approximating solutions to the differential systems has been tested for a horizontal two-dimensional geometry. In end-to-end displacements of oil with less-viscous solvents, the numerical solutions exhibited fingering qualitatively similar to that observed in laboratory models. Small random spatial variations in permeability about the mean value are sufficient to initiate fingering. Quantitative comparisons of computed results with laboratory data show good agreement. INTRODUCTION Miscible flooding of oil by solvent is receiving increasing consideration for field use.1-4 Unfortunately, such floods potentially present severe problems in loss of recovery through the by-passing of oil by expensive solvent. Consequently, their economic evaluation requires sound techniques for predicting recovery. The purposes of this work are to present a finite-difference method for calculating the multidimensional displacement of oil by solvent and to investigate the validity of the method by comparing results of calculations with data from displacements in laboratory models.5 The formulation of the method to simulate the model experiments treats a case of limited scope in the description of solvent flooding in the reservoir. The model experiments were carried out with fluids that were assumed to form an incompressible, ideal, two-component system with constant diffusivity. Establishing the validity of the method even in its present form provides a major step toward the goal of quantitatively evaluating individual solvent flooding projects. First, it demonstrates the fea- sibility of calculating the course of displacements which are dominated by an inherent macroscopic instability, i.e., viscous fingering. In addition, the method provides almost the only practical means of examining the effect of the size and extent of reservoir inhomogeneities on the development and propagation of the fingers, taking into account the important influences of diffusion and gravitational segregation. It might be inferred that such studies cannot yield results of practical value because in displacements dominated by macroscopic instability the pattern of finger development and the resulting performance should depend critically on small variations in the geometric distribution of reservoir inhomogeneities. The present method offers the capability inherent in computational techniques of predicting performance reproducibly with any arbitrary distribution of reservoir properties and, as such, provides a means of evaluating the sensitivity of behavior to uncertainties in reservoir definition and, thus, assessing the reliability of prediction of performance. THE PHYSICAL PROBLEM DATA USED FOR QUANTITATIVE TESTS OF CALCULATIONS In this work, a calculation for treating the miscible-displacement process is tested by comparing calculated results with experimental data. The experiments chosen for comparison have been described in detail,5 and the quantitative features are summarized in a later section. Briefly, oil was flooded by solvent of equal density from a thin rectangular channel in Lucite packed with uniform Ottawa sand. Under these conditions, two-dimensional geometry is considered adequate to represent the process. Inasmuch as the present work is concerned with testing of the method by comparison with specific two-dimensional data, the system of equations presented in the succeeding section will be oriented to defining the physical system specifically. THE DIFFERENTIAL EQUATIONS Suppose x, y to be a Cartesian co-ordinate system and define h(x, y) to be the height of a point above a horizontal reference plane. It will be assumed

By E. F. Johnson, F. H. Brinkman, H. J. Welge, A. L. Hicks

A method is presented for predicting the character of gas or water displacement in a radial system, which can be either horizontal or inclined. The latter case would comprise cone-shaped or dome-shaped symmetry. The method conriders the one dimension of radial distance, taken parallel to the bedding planes. Approximate allowance can be made for segregation of the two fluids perpendicular to the bedding planes. A complete saturation history can be obtained in about a day's time with the use of a desk calculator. Results of an example calculation agree well with the performance of simulated gas drive in a large model representing a section of a cone. This pie-shaped, sand-packed model was 8-ft long and 4-in. thick. The method of solution is useful in handling other partial differential equations of first order and first degree. INTRODUCTION A new analytical method has been developed for predicting the performance of gas or water drive in a reservoir having radial or cone-shaped symmetry (see Fig. 1). In addition, this new development offers a general method of handling partial differential equations of first order and first degree. This work extends those methods developed previously'- "or predicting the displacement of oil by gas or water in linear systems. The method of calculating oil recovery in a radial system involves two major parts. The first part is a calculation of the distribution of saturations at various times of depletion. The second part is the calculation of oil recovery and producing gas-oil or water-oil ratios through volumetric balance on the saturation distributions obtained in the first part. This second part differs only slightly in principle from similar calculations made with linear systems, for instance. The basic assumptions used in the calculations are as follows. 1. One-dimensional radial flow. An approach is explained later for approximating a second vertical dimension. (With- drawals of oil, and of the driving fluid after breakthrough, are assumed uniform around the periphery of the dome.) 2. Constant-volume fluid flow. Thus, in a gas drive there is no change in gas solubility, or in oil or gas volume due to viscous and gravity pressure drops. 3. Capillary forces are negligible. 4. Constant rate of injection. A program has been written for carrying out the calculations needed on a digital computer. However, a prediction can also be arrived at using a desk calculator; this latter method of work requires about a day's time for each prediction made. CALCULATION OF SATURATION DISTRIBUTION For definiteness, we describe the development of our method for the case of gas drive from the crest of the structure. The reader will note, however, that the method is just as applicable to an advancing radial water drive. The equation describing gas flow over an infinitesimal

By J. K. Whyatt, B. G. White

A comprehensive survey of mine seismicity and rock bursting during development of two sublevels at the Lucky Friday Mine, Mullan, ID, USA, was conducted to better define rock failure mechanisms and sources of ground control hazards. Survey data included rock burst damage reports, seismic event locations and magnitudes and, for the most energetic events, first-motion information. Several subsets of this database, including large seismic events, rock bursts, and microseismic activity near the face, were analyzed. Elements of the large-event and rock burst data sets were nearly independent. That is, there was no relationship between the risk posed by a seismic event and its energy, although such a relationship is well established for the mine as a whole. All data sets showed that certain geologic features appear to control the spatial distribution of events and the spatial distribution of rock burst risk. The data also suggest that, within the scope of this study. the greatest risk of injury occurs when a pocket of heightened rock burst risk is first encountered and that this risk is controlled when miners adapt their practices to these conditions. Recognition of the role of particular geologic features in the spatial distribution of rock burst hazards provides an opportunity for anticipating, rather than only reacting to, a changing level of rock burst hazard- However, much work will he required to make good on this promise.

By H. N. Hall

Various factors must be considered in an engineering evaluation of gravity-drainage reservoirs. Among these are: (1) the effect of producing rate on total oil recovery; (2) the effect upon well productivity and ultimate recovery of the pressure level maintained during the producing life of the reservoir; (3) the economic advantage of full or partial pressure maintenance; and (4) estimate of the rate of gas production and injection and the possible purchase of gas under conditions of full pressure maintenance to ascertain compressor facilities needed. All of these factors can be evaluated only when a reliable method is employed for determining reservoir performance in gravity-drainage reservoirs. The purpose of this paper is to present a general method for calculating the performance of a gravity-drainage reservoir. This method is applicable for conditions of complete pressure maintenance, partial pressure maintenance and normal pressure depletion. Provisions are made to take into account variations throughout the reservoir of reservoir configuration, changes in permeability and fluid composition. Based on the method presented in this paper, an IBM 650 computer program has been developed. The past performance of an actual gravity-drainage reservoir producing under conditions of declining pressure and no gas injection was duplicated using this program. INTRODUCTION In tilted reservoirs the production of oil is influenced by drainage of oil from upstructure to downstructure locations. When this downstructure drainage of oil is sufficient to cause effective segregation of the gas and oil in a reservoir, the reservoir is usually classified as a segregation drive or gravity-drainage reservoir. (Discussion will be restricted to gravity-drainage reservoirs which have no encroachment of edge water.) The important feature in gravity-drainage reservoirs is the density difference between reservoir oil and gas. These phases tend to segregate in the reservoir with the result that in the gas cap the oil saturation is maintained at a higher level by drainage of oil from the gas-cap area. Oil can be produced from the oil zone at a low gas-oil ratio and reservoir energy is thereby conserved. The standard material balance in not adequate for predicting gravity-dramage reservoir performance because it does not take into account the difference in saturation above and below the gas-oil contact. Several authors'.' have presented methods for calculating the performance of gravity-drainage reservoirs in which reservoir pressure is maintained constant by gas injection into the gas cap. Using some simplifying assumptions, these methods can be employed with a desk calculator to give acceptable results. The problem of predicting the performance of gravity-drainage reservoirs under the conditions of declining reservoir pressure is many time more complex than that of constant pressure. fierefore, attempis to develop a method suitable for desk calculation have required excessively simplified assumptions. In the past several years, highspeed digital computers have become more widely available for reservoir engineering problems. These corn puters are well suited to problems such as the prediction of the performance of gravity-drainage reservoirs with pressure decline. Many of the simplifying assumptions necessary for hand computation can be eliminated so that a realistic approach to the gravity-drainage process can be made. CONCEPTUAL PICTURE OF OIL MOVEMENT IN GRAVITY-DRAINAGE RESERVOIRS Before attempting to develop an analytical treatment for conditions occuring in a gravity-drainage reservoir, a concept should be formed concerning the movement of fluids in the reservoir as oil is produced. A review of the literature'.' shows that it is customary to classify gravity-drainage operations into two categories—(1) with complete pressure maintenance, and (2) with declining pressure. The same line of reasoning will be followed in presenting the concept of the movement of fluids in the reservoir because it is easier to visualize the movement of fluids under conditions of complete pressure maintenance. After discussing complete pressure maintenance, an analogy will be made between that and the case of declining pressure. It should be kept in mind throughout that the final aim for the problem of solving gravity-drainage performance with digital computers will be to develop a general program for any kind of gravity-drainage reservoir. COMPLETE PRESSURE MAINTENANCE One feature which is generally common in gravity-drainage reservoirs is a gas cap located at the top of the structure. This is shown in Fig. 1(a). Fig. l(b) shows oil saturations that might occur through the reservoir. In the gas cap, oil saturation is lower than

By J. W. Wilson, P. C. Graham

Raise-boring experiences in the gold mines of the Anglo American Corporation Group by J. W. Wilson M.Sc., M.I.M.M., F.S.A.I.M.M., M.A.I.M.E. and P. C. Graham M.Sc. (Eng.) Gold mining is being carried out at ever-increasing depths in South Africa. For reasons of safety and human comfort, it is becoming imperative for raises to be developed by means other than conventional drilling and blasting. Raise-boring is an attractive alternative method. Initial raise-boring experiences in South African gold mines showed disappointingly high costs due to the abrasivity and difficulty of drilling Witwatersrand quartzites. Consequently, a research and development project was instigated with the objective of making raise-boring an economically viable technique in hard abrasive rock. A Robbins 61R raise-borer was made available to the Research and Development team and a number of raises have been drilled. During these trials two advances in cutter design were tested. This paper presents the results obtained, including drilling costs, and provides details of the equipment used.

By J. E. Warren, J. H. Hartsock

Because of the extensive utilization of hydraulic fracturing for the stimulation of low-productivity wells, the two related problems of fracture design and evaluation have become economically significant and, as a consequence, helve motivated this investigation. The producing characteristics of horizontally fractured wells were studied to determine the fracture configuration that should be employed as the basis for the design of the treatment and to develop a method that can be used to establish the degree to which the design objectives have been achieved. The equations which describe the steady-state flow of a single-phase fluid into, and through. a finite-capacity fracture were solved numerically for an idealized reservoir-fracture model. The numerical results were used to obtain an apparent skin effect for each combination of the parameters considered. Based on the computed results, subject to the limitcitions implied by the assumptions that were made, the following general conclusions were drawn. 1. For a radius of drainage at least four times us large as the radius of the fracture, an apparent skin effect that is independent of the radius of drainage can be calculated. 2. The productivity of the hydraulically fractured system, relative to that of the unfructured well, can be determined from the apparent skin effect and can be used to establish design objectives. 3. In the evaluation of a fracture job, it is not Possible to determine both the radius of the fracture and its flow capacity uniquely from the apparent skin effect; an independent determination of one of the quantities is necessary. lNTRODUCTION Although hydraulic fracturing has been employed as a method for stimulating the productivity of literally hundreds of thousands of wells during the past 10 years, it is only in the last few years that improvements in fracture design1-6 and fracturing technique' have combined to increase the probability of obtaining a successful treatment to such an extent that the mechanics of the method may be considered to be standardized. From an economic point of view, however, two related questions must be satisfactorily answered before hydraulic fracturing can be used in the most profitable manner. The two questions are the following. I. For a particular well in a given formation, what are the optimum design specifications for the fracture treatment? 2. Have the design objectives been achieved by the fracture treatment? The significance of these questions has been recoguized, and some attempts to obtain answers have been made. Howard, et al,8 endeavored to determine the optimum treatment, based on maximizing profits, for any given formation; unfortunately, this work was based on a crude method for approximating the productivity of a well. Carter and Tracy9 utilized the same approximation to study the effect of fracturing on the behavior of a well producing by virtue of a solution-gas drive. Electrolytic models were used by van Poollen10 to investigate the variation in productivity due to fracturing; however, only a limited number of results were presented. Later, from the same model results, van Poollen, et al,11 attempted to justify an approximate expression for determining the productivity of a fractured well. It is quite apparent that there is a definite lack of the practical information necessary for specifying the optimum fracture configuration to be considered for design purposes. The only detailed attempt to develop a procedure for evaluating the result of a given fracture treatment appears to be that of van Dam and Horner.12 These authors described a technique for analyzing pressure build-down data, obtained immediately after fracturing, to determine the final fracture volume, the final fracture porosity, the fracture area, the fracture thickness and the in situ fluid loss of the fracturing fluid. While this approach should be useful whenever acceptable pressure measurements are available, it does not yield a value for the flow capacity of the fracture. Since the problems of fracture design and evaluation are inversely related, it should be sufficient to study the effect of the fracture configuration on the performance of a well. The primary objective of this investigation is to evolve a technique for computing the desired solutions. The secondary objective is to analyze these computed results in order to prescribe a method for evaluating fracture treatments. Because this study is exploratory in nature, its scope

By M. D. Arnold, H. J. Gonzalez, P. B. Crawford

A method is presented for estimating the effective directional permeability ratio and the direction of maximum and minimum permeabilities in anisotropic oil reservoirs. The method is based on the principle that production from a well in an anisotropic reservoir results in elliptical isopo-tentials about the well, rather than circular. Bottom-hole pressure data from three observation wells surrounding a producing well are required to apply the method. The method involves fitting field pressure data to a set of general charts of isopotentials and making a few simple calculations until a solution is found. The method is based on a steady-state equation for homogeneorrs fluid pow. In addition to the method, a brief discussion of the theory underlying it is presented. INTRODUCTION The existence of a different permeability in one direction than another in oil reservoirs has been mentioned in several papers. Hutchinson' reported laboratory tests on 10 limestone cores and pointed out that one-half of them showed significant, preferential, directional permeability ratios, the average being about 16:1. Johnson and Hughesz reported a permeability trend in the Bradford field in the northeast-southwest direction with flow being 25 to 30 per cent greater in that direction. Barfield, Jordan and Moore -eported an effective permeability ratio of 144:1 in the Spraberry. Crawford and Landrum4 showed that sweep efficiencies could often vary by a factor of two to four, and sometimes considerably more, due to variations in flooding direction and patterns in anisotropic media. These findings indicate that the poss'bility of anisotropy may be worthy of consideration in the development of an oil field. In considering this, it should first be determined if anisotropy exists. If it does, the direction of the maximum and minimum permeabilities and the ratio of their magnitudes are quantities which can be of value in planning the most efficient well-spacing patterns. Past methods of determining these quantities have included analysis of oriented cores and analysis of flooding performance of pilot injection patterns. In recent work, Elkins and Skov5 resented an analysis of the pressure behavior in the Spraberry which accounted for anisotropic permeability. This work was based on the transient pres- sure distribution in a porous and permeable medium, with the solution expressed as an exponential integral function involving rock and fluid properties. The purpose of this study is to provide a method, based on steady-state equations, of estimating the direction and relative magnitude of permeabilities in an oil reservoir from field pressure data and well locations only. The method presented is based on work by Muskat6 which shows that Laplace's equation represents the steady-state pressure distribution for homogeneous fluid flow in homogeneous, anisotropic media if the co-ordinates of the system are shrunk or expanded by replacing x with it is desirable that data be obtained early in the history of a field because knowledge of an anisotropic condition would allow new wells to be spaced in such a manner that reservoir development and subsequent secondary recovery programs could be planned more efficiently. THEORETICAL CONSIDERATIONS A brief discussion of the theoretical basis on which the graphical solution was developed is presented in this section. Muskat's two-dimensional6 olution for the pressure distribution in an homogeneous, anisotropic medium with an homogeneous fluid flowing can be algebraically manipulated to show that the isobaric lines are perfect ellipses. The ratio of the major axis to the minor axis, a/b, is related to the permeability ratio, k,/k,, as follows. alb = dk,/k,--...........(1) It can also be shown that the pressure varies linearly with the logarithm of the radial distance from the producing well. However, the gradient along any ray is a function of the orientation of that ray, and a ..xiable is present when anisotropy exists which cancels out for a radial (isotropic) system. For a system such as that described, a dimensionless pressure-drop ratio was developed which is completely independent of the actual magnitude of the pressures. This was done by arranging Muskat's solution in such a way that aIl variables cancelled out except k,/k, and well positions. However, this solution depends on having a co-ordinate system with axes coinciding with the major and minor axes of the elliptical isobars. Thus, it was necessary to introduce a co-ordinate system rotation factor. The two unknown variables are then k,/k. and 0, and the two measured dimensionless pressure-drop ratios are related to the unknown variables as follows.

By L. A. Wilson, N. H. Harrison, R. R. Clay, R. L. Reed. D. W. Reed

Experiments have been performed in a linear near-adiabatic system for the purpose of extending data on reverse and forward combustion from atmospheric pressure to 1,000 psig. Results obtained from reverse combustion appear to conform qualitatively with the existing description of the process when reaction kinetics are suitably modified to account for the increase in pressure, i.e., increasing tbe pressure decreases the peak temperature and increases the combustion zone velocity. Forward combustion appears to be a fuel dominated process wherein peak temperature and combustion zone velocity are not very sensitive to changes in pressure. The moderate effects of pressure that do exist at low flux virtually disappear at high flux providing all oxygen is consumed. With this provision. increasing the pressure decreases the frontal velocity and increases the peak temperature. Results me shown graphicaIIy which demonstrate the effects of presswe on peak temperature, rate of advance, oil recovery, air/oil ratio, carbon oxides produced and temperature distributions. INTRODUCTION Numerous field tests of oil recovery using the technique of underground combustion are now in progress. Operating pressures used are always substantially in excess of atmospheric pressure. Nevertheless, the literature contains no laboratory data pertaining to the effects of pressure except for those of Martin, Alexander and Dew.1 Unfortunately, these data appear to reflect heat losses which may have obscured some of the effects of increased pressure. The underground combustion processes are exceedingly complex, and general concepts relating to them have necessarily been described in relatively simple terms. Particularly with regard to forward combustion, the interaction between multiphase fluid flow, heat transport and various rate mechanisms is so involved that to date a rigorous treatment is not available. In this paper a linear near-adiabatic system is described which was found capable of operating at pressures up to 1,000 psig and temperatures of at least 1,100 F. Using this equipment, experiments on both forward and reverse combustion were accomplished at elevated pressures and the data presented as a function of air flux or temperature. It will be assumed that the reader is familiar with the papers of Wilson, Wygal, Reed, Gergins and Henderson on forward combustion and that of Reed, Reed and Tracht3 on reverse combustion, so that it is not necessary to repeat the details of the two processes. EQUIPMENT AND PROCEDURE It was decided to study the effects of pressure over the interval 0-1,000 psig using a near-adiabatic system. Since satisfactory operation of such a system requires very thin tubing walls, it proved necessary to insert the entire combustion tube and heater assembly into a high pressure jacket in such a way that the internal tube pressure could be counterbalanced by pressurizing the annulus. This meant that the numerous heater and thermocouple wires had to pass through gas-tight seals that required considerable effort to maintain effective. An unexpected difficulty arose in connection with the nature of the annulus pressuring gas. It turned out that the composition of this gas critically affected the functioning of the adiabatic control system. Operation of the equipment at elevated pressures was not particularly difficult. The problems that did arise were a direct consequence of the large numbers of connections and seals involved. EQUIPMENT The equipment consisted of the combustion tube which fitted within the pressure jacket. This jacket was in turn mounted on a wheeled carriage which facilitated movement and provided for rotation of the

By R. E. Cook

This paper presents results of a study to determine to what extent errors in estimated free gas saturation affect the results of static pressure calculations from build-up curves in two-phase systems. Use is made of the method of pressure build-up curve analysis developed by Miller, Dyes and Hutchinson1 , with modifications for two-phase flow advanced by Perrine2. Cornhined fluid compressibility of gas-oil mixtures is included, with special attention given to the discontinuity that occurs in fluid compressibility at the saturation pressure and its effect on static pressure calculations from build-up curves. The sensitivity of static pressure calculations to errors in gas saturation is considered over wide ranges of formation and fluid properties and reservoir pressure conditions. It is concluded from this study that for analyses of two-phase pressure build-up curves (I) the use of under-saturated crude compressibility data, even when producing GOR's are at or near solution values, will result in very significant negative errors in calculated static pressrrre, and (2) except for large values of buildup curve .slope and/or very low crude gravities, rather large errors in calculated gas saturation can he tolerated without .significant effect on calculated static pressures. The conc1usions arc qualified as referring only to the effects of gas saturation and excludc possible errors in the nuumerous other factors that enter into the ancllysis of pressure build-up curves. INTRODUCTION As part of the analysis of basic data for several major Eocene reservoirs in the Bolivar Coastal field (Western Venezuela), it was necessary to analyze a large number of pressure build-up curves for oil permeability and static reservoir pressure. From performance data it became apparent that gravity segregation is very active in these reservoirs. As a result of this performance it was recognized that the free gas saturation within the oil leg of the reservoirs would be small but would be subject to certain errors in calculation due to the inaccuracy of relative permeability data in the low gas saturation region. Since all of the various methods of build-up curve analysis were originally derived for sin- gle-phase, constant compressibility systems, and since the presence of a small but rather indeterminate gas saturation would greatly affect the reservoir fluid compressibility, a study was undertaken to investigate the effect of gas saturation on the results of two-phase pressure build-up analyses. TWO-PHASE BUILD-UP CURVE ANALYSIS The method of analysis used in this investigation is basically that originally developed by Miller, Dyes and Hutchinson1, with modifications for two-phase flow advanced by Perrine2. Miller, et al, showed that the original equation for single-phase permeability away from the well bore, held for two-phase flow except that the calculated permeability is the effective permeability to oil away from the wellbore. This finding was acknowledged by Per-rine, who also presented the equation for effective gas permeability* as Since Eqs. 1 and 2 contain no terms influenced by fluid compressibility, no distinct problem should develop in calculating permeability from two-phase build-up curves. In regard to the calculation of static reservoir pressure from build-up curves in single-phase systems, the modified Miller, et al, method as presented by Perrine is briefly as follows. 1. From build-up curve data, PVT data for the reservoir fluid and the well spacing and sand thickness, calculate the climensionless shut-in time corresponding to the highest value of actual shut-in time (t, hrs) on the straight-line portion of a semi-log build-up curve. Dimenrsionless shut-in time is related to actual shut-in time by the relation, t- 0.000264 kt 2. From a graph of dimension less shut-in time vs dimensionless pressure difference (Fig. 1 1 ) find the value of dimensionless pressure difference corresponding to the value of 7 calculated under (1) above. Dimen-

By I. Fatt

Study of a model which contains "dead-end" pore volume indicates that pressure transients are influenced by the amount of dead-end pore volume and by the resistance of the flow path between the dead-end pore volume and the main flow channels. A semi-empirical method is demonstrated that makes possible measurenment of the volume in the dead-end pores and the total pore volume. The difference between these two volumes is the volume of the flow channels. An indication of the flow resistance between the dead-end pore space and the lain flow channels is also obtained. INTRODUCTION In some engineering calculations the distribution of pore volume in a petroleum reservoir need not be known. For example, a material balance calculation treats a reservoir as an oil-filled tank. In other calculations the distribution of pore volume appears implicitly through use of the porosity and the relative permeability and capillary pressure characteristics. It is the purpose of this paper to point out that under certain conditions the exact distribution of pore volume must be known in order to interpret correctly transient flow behavior. Pressure transients during single-phase flow in porous media are usually said to obey differential equations of the form

By G. W. Nabor, M. Mortada

The effects of anisotropic or directional permeability on the areal sweep efficiency and the flow capacity are examined. The paper points out the importance of taking directional permeability into consideration in planning a flood. It analyzes the two-dimensional flow pattern associated with the skewed line drive for a unit mobility ratio. The direct and staggered line drives are treated as special cases of the skewed line drive. Analytical expressions are developed for the areal sweep efficiency at breakthrough and the flow capacity. They are related to the spacing between like wells, the distance between a row of injectors and the nearest row of producers, and the degree of skewness of the line drive. The latter quantity is defined such that it is equal to zero for the direct line drive and equals one-half for the staggered line drive. The areal sweep efficiency and the flow capacity depend also on the orientation of the flood pattern with respect to the principal axis of anisotropy. The paper provides a simple method for determining the areal sweep efficiency and the flow capacity for a formation in which the permeability in the bedding plane is anisotropic. INTRODUCTION Directional or anisotropic permeability is manifested by the ability of the formation to conduct fluids more readily along certain preferred directions. This situation occurs in many producing formationsl-4 and is usually attributed to depositional features in which the sand grains are oriented in a preferred direction. In some cases it results from the formation of a major and a minor fracture system. 4 Directional permeability should be taken into account in many phases of the production and exploration activities. Recognizing its existence in the formation of interest and planning accordingly can lead to increased recovery and substantial savings. For instance, the areal sweep efficiency in a water flood depends to a great extent on the orientation of the flood pattern with respect to the principal axis of permeability. Anisotropic5 permeability is specified by the directions of its three principal axes and the permeability along each axis. The principal axes of permeability are mutually perpendicular. This paper deals with the areal sweep efficiency at breakthrough and the flow capacity for formations with aniscltropic permeability. The flood pattern considered consists of alternate rows of injecting and producing wells. The rows of wells are parallel and form a developed, skewed line drive which is illustrated in Fig. 1. The staggered and direct line drives are treated as special cases of the skewed line drive. PRELLMINARY CONSIDERATIONS The formations considered in this paper are assumed to be of uniform thickness and porosity. The permeability is uniformly anisotropic, with each principal axis of permeability maintaining

By C. Bryce

Rhenium is primarily recovered as a byproduct from molybdenum roasting circuits. However, rhenium is also present in copper heap leach solutions at very low concentrations, and this represents a potential new rhenium source. Freeport-McMoRan (FCX) has developed a new process using carbon adsorption followed by ion exchange or solvent extraction to concentrate rhenium from less than 1 ppm to 15 g/L. The product is compatible as a feed to an existing rhenium processing plant. A pilot plant operated at Freeport-McMoRan?s Sierrita Mine has demonstrated the technical and financial feasibility of this new process. Copper heap leaching dissolves more than just copper from the copper ore. Several metals can be identified in leach solutions at concentrations of financial interest, rhenium in particular. Rhenium spot prices ranged from a yearly average of $1,070/kg ($483/lb) in 2005 (Magyar, 2008) to $10,400/kg ($4,706/lb) in 2008 (Polyak, 2013). The spot price in September 2013 was approximately $3,000/kg ($1,357/lb) of rhenium (Metal Bulletin, 2013). Several facilities at Freeport-McMoRan have very low rhenium concentrations in their copper leach solutions, ranging from 0.1 to 0.7 mg/L. The large quantity of solution available, if coupled with an attractive rhenium price, means that the rhenium contained in leach solutions may represent a significant value if a method of extraction could be developed. Testing has confirmed that rhenium adsorbs onto activated carbon much more selectively than other metals in the pregnant leach solution (PLS). A 100-gpm pilot plant was constructed to verify the lab-scale results on a larger basis and establish operating parameters for a full-scale operation. This report summarizes the initial technology development and pilot plant operation.

By L. W. Emery

Undergrorlnd combustion operations were initiated in a 60-acre Bartlesville sand "shoe-string" reservoir in Allen Connty, Kans., in 1956. Tests in separate patterns were conducted using various co~nbinations of air and recycle gas to propagate combustion fronts from the injection toward the producing wells. These patterns were made up of 6 injection and 20 prodrrcing wells Gas and liquid prorluctiorz from each pattern was measured on an individual-well basis, and comparisons were made between the three patterns to ascertain the relative effects of injected gas composition on production behavior. Breakthrough of the combustion front at a well was characterized by an increase in water production from the well followed by an increase in bottomhole temperatrrre to approximately 250" F. After burning fronts had broken through at five producing wells, operations were terminated in 1960. From the total project approximately 79,000 bbl of oil were produced during thermal operations at a cumulative produced GOR of 23 Mcf/bbl. No appreciable change in the character of the produced crude was observed. Combustion in the reservoir was maintained with injected gas compositions ranging fronz 6 per cent oxygen in recycle gas to 100 per cent air. lnjectiotz of large quantities of recycle gas resulted in higher producing GOR's from offset wells than were measured from a pattern into ~vhich straight air ~vas injected. The air required to move the combustion front through I acre-ft of reservoir was computed to be 20 MMscf. This valrre was found to be relatively independent of the quantities of recycle gas injected. The recovery efficiency from the swept area was esti~izated to be about 59 per cent. Areas swept were similar in shape to tlzose obtained with a laboratory potentiometric model. Samples of sund taken from behind the burning front by coring indicated almost total oil removal from the sand. Petrographic analysis of the core samples indicated that the sand had been heated to peuk temperature of rlbout 1,200" F. No rignificant difference in peak temperature was forrnd in two areas where compositions of injected gas were quite different. Compression costs for thermal recovery were estimated to be $1,20/bhl of produced oil. INTRODUCTION The use of the "forward combustion" process as an oil recovery method has received a great deal of attention. This method involves ignition of the formation in an injection well, followed by propagation of a combustion front through the reservoir. Combustion is maintained by the injection of an oxygen-containing gas to react with reservoir hydrocarbons. As the flame front progresses through the reservoir, oil and formation water are vaporized, driven forward in the gaseous phase and recondensed in the cooler part of the formation. In turn, the condensed fluids push oil into the producing wellbores. Completed field tests of the process were first reported by Kuhn and Koch,' and by Grant and Szasz.' Results from other tests have since been reported by Walter,3 by Moss, White and McNeil,' and by Gates and Ramey." ach of these tests essentially utilized a single injection well surrounded by four or more producing wells. Sinclair Research, Inc., elected to do field experimental work using a number of test patterns in a single field in order that comparisons between various operating schemes could be made. The site selected and purchased in 1955 for this experimental work was a 60-acre Bartlesville sand reservoir located in Allen County, Kans. Combustion operations were initiated in mid-1956. Between that time and termination of the project in mid-1960, combustion fronts were propagated from injection wells to producers in three separate well patterns, using different mixtures of air and recycle gas. The test was terminated before sweep of the three patterns was complete so that information about the effect of combustion on the swept areas could be obtained by coring. Results from the test in the form of injection and producing well performance have been carefully recorded, and these form the general basis for this paper. DESCRIPTION OF RESERVOIR The reservoir in which the combustion tests were conducted is a Bartlesville sand "shoe-string", typical of a number of small reservoirs in Southeastern Kansas. Average reservoir characteristics are shown in Table 1. Fig. 1 is an isopachous map of the producing sand showing the reservoir to be approximately 400-ft wide and 2,500-ft long. Maximum net productive sand thickness is 21 ft. Fig. 2 shows a typical core analysis obtained by coring with water-base mud. The reservoir has no appreciable dip and is closed on the sides by degradation of sand into shale. The main body of sand is heavily laminated with shale stringers, which are not continuous between wells. The main reservoir is overlain by 30 to 40 ft of laminated low-permeability sand and shale streaks. No information is available on the original properties of

By B. Habermann

Artificially consolidated sand models, representing one-quarter of a five-spot, have been developed and used to study factors aflecting misciblt. displacrmenr. Sweep efficiency at breakthrough, size of the mixing zone between two miscible liquids and per cent area contacted by drive after breakthrough were determined tor the high mobility ratios encountered in actual resvrvoirs. Quantitative relationships between the degree of viscous fingering and mobility ratio were obtained by measuring the length of the fluid interface. Scaled miscible-slug experiments, supported by field evidence reported in the literature, have shown that when the slug is followed by dry gas the process is less efficient than expected. In addition to low areal sweep efficiencies encountered for high mobility ratio displacements, the effectiveness of a miscible slug is greatly reduced. This is caused by an accelerated growth of the mixing zone between the driving and the displacing fluids. INTRODUCTION Considerable interest in miscible displacement as a secondary recovery process has been shown by the oil industry in recent years. In addition to extensive laboratory investigations, numerous field operations have been initiated so that 39 miscible displacement projects had been reported' in the United States by early 1959. By far the most popular approach in these projects is the use of an LPG slug followed by dry gas. Laboratory tests have indicated that with a small miscible slug, amounting to several per cent of the hydrocarbon pore volume, practically 100 per cent recovery of the oil in place can be achieved and that all of the slug material can be recovered by a subsequellt gas drive. However, these experiments were conducted on small-diameter long cores that can be considered as essentially uni-dimensional reservoirs that do not represent actual field conditions. It soon became apparent that the inherently adverse mobility ratios existing in the reservoir cannot be ignored in any miscible displacement field project. When a less viscous fiuid such as an LPG slug drives a more viscous reservoir oil, fingers develop that reduce the areal sweep efficiency. The slze of the miscible slug to be used is a subject of some controversy. It has been proposed that the size of siug needed be calculated by setting lengths of the mixing zone proportional to the square root of the distance traveled. This proposal is based on experimental evidence' and theoretical considerations"' in which fingering was not a factor. A prerequisite for successful application of the miscible displacement process to field operations is a better understanding of the following factors. L What is the effect of mobility ratio on the rate of deterioration of a miscible slug? 2. How large a slug should be used for given reservoir conditions? 3. What is the sweep efficiency? The purpose of this investigation was to provide some additional laboratory data that should help to answer these questions. More specifically, it was intended to study more quantitatively the effect of viscous fiinger-ing, mobility ratio and slug size on the efficiency of this relatively new secondary recovery process by means of experiments on thin, horizontal, porous medium models.

By R. A. Salathiel, A. D. Kaiser, P. H. Monaghan, B. E. Morgan

The productivities of many hydrocarbon-bearing for-rnntions appear to be reduced during drilling, completing and repairing operations. The reason for these othcarwise unexplainable low productivities may be a drastic reduction of formation permeability immediately surrounding the borehole. A possible cause of the reduced permeability is swelling and dispersion of clays present in porous media when contacted by fresh water or mud filtrates. Hence, the invasion of fresh water or mud filtrate into hydrocarbon-bearing formations that contain clays may cause low productivities as a result of formation damage. Present laboratory investigations have yielded results which supplement existing literature on formation damage. An expanded-type clay, montmorillonite, way found in hydrocarbon-bearing formations not previously analyzed. When sand columns and formation cores containing montmorillonite were contacted by fresh water, their oil permeabilities were reduced. This reduction in oil permeability way restored partially but not completely by a repair procedure, i.e., flooding with kerosene containing organic agents or flooding with water containing electrolytes. Hence, where montmorillonite is present in formations, prevention of formation danzage was indicated to be the only complete solution to the problem. To prevernt formation damage, results suggested use of an approximately 1 per cent solution of calcium chloride or stronger solutions of sodium or potassium chloride. In conventional rotary drilling operations the wall of the hole is exposed to drilling mud for days, weeks, and in some instances for as long as several months. During this time, drilling mud filtrate seeps slowly into formations surrounding the hole. The permeability and stability of many formations, especially those containing clayey materials, are impaired by the mud filtrate. Often interaction between the mud filtrate and the formation causes drilling and production difficulties. Serious reduction in productivity of oil and gas formations during drilling, completing and repairing wells has been noted often in recent years. Cases are known of development wells which produced only small volumes of fluid upon completion. However, after a period had elapsed, they began to produce oil or gas in commercial quantities. In other cases, results of drill-stem tests taken during the drilling of deep wells have indicated good production should be obtained from shallow formations. Later difficulty has been experienced in obtaining production from these shallow formations which had remained in contact with drilling muds for an extended time. In yet other cases wells have failed to attain the productivities expected from previous performance after the use of drilling mud as a circulating fluid during workover operations. It is evident from the field behavior cited that the productivities of certain oil- and gas-bearing formations have been damaged by exposure to drilling muds. This reduction in well productivity, called "formation damage", causes serious consequences. In development wells, expensive remedial operations are incurred. In wildcat wells, good formations may appear to be marginal or even non-productive. The importance of formation damage has been recognized by a number of investigators1-s who have considered the effects of fresh water, saline solutions and aqueous mud filtrates on the permeabilities of formations. A general conclusion from such studies is that interaction between water and formation clays reduces permeability of reservoir rock and that the permeability decreases as salinity of the water decreases. Data in these references, however, concern the permeability change with only a single fluid present. A more pertinent and direct consideration in the production of oil and gas from wells is the permeability change when two fluids, oil and water, are present. Recognizing this, Nowak and Kreuger2 and Bertness1" considered several ways in which mud filtrates and saline solutions caused reductions in the oil permeability of formation cores. Investigations discussed here were designed to supplement information in the literature on changes in oil

By Charlie Vaught, Bill Wiehagen, Lynn Rethi, Pamela Kidd, Lisa Steiner, Ted Scharf, Henry Cole, Kathleen Kowalski

The most hazardous work environments share one feature in common: constant change. Many different, but constantly changing hazards are found in agriculture, construction, mining, and transport. This dynamic feature of work-place hazards varies by: (1) degree of control, (2) predictability, (3) visibility, (4) movement, and (5) degree of speed and force. In some cases the actions of the dynamic hazards are required for production to take place, and in many cases,

By R. J. Wagner, F. F. Craig, H. G. Riley, J. D. Griffith

Peripheral water injection has been underway in the Sholem Alechem Fault Block "A" Unit, Stephens County, Okla., since 1955. In the engineering planning of the flood, it was recognized that maintenance of pressure in the large, dry gas caps was vitally necessary to prevent the loss of an estimated 27 million bbl of oil through saturation of the gas caps by the oil banks moving updip on the peripheral flood pattern. The development of an abundant, low-cost water supply and the rising cost of makeup-gas purchases indicated that gas-cap control by water injection was desirable from an economic standpoint, provided an eflective water barrier could be placed without premature water breakthrough into downdip oil producers. A laboratory model scaled to the existing reservoir conditions was comtructed to evaluate the feasibility of gas-cap water injection. Model studies indicated that (I) water injected at the edge of the gar-oil contact would form a continuous barrier between the oil and gas zones, and (2) water would advance uniformly downdip without segregation due to gravity effects provided a specified, minimum water-injection rate was maintained. The model test results also indicated that it was not necessary to fill the gas cap completely with water. Water injection at the edge of one of the gas caps was initiated in March, 1958, to field test gas-cap water injection. Water breakthrough occurred at a downstruc-ture producing well in April, 1959, after approximately 2.5 million bbl of water had been injected into the gas cap. This was the volume calculated to be required to form the barrier between the oil zone and gas cap. This performance indicates that prevention of oil encroachment into dry gas caps in a peripheral water flood by water injection at the gas-oil contact appears practical and that the model studies provided a valid prediction of field performance. INTRODUCTION The Sholem Alechem Fault Block "A" Sims Sand Unit was one of the fist major waterflood projects in Oklahoma to utilize a peripheral injection pattern. Design of control measures to minimize oil encroachment into the large crestal gas caps was one of the greatest single problems during engineering planning of this flood. Engineering studies indicated that saturation of the gas caps with oil displaced by the peripheral water flood could result in a loss of about 27 million bbl of oil, or over one-half the estimated waterflood recovery. This estimate was based on a residual oil saturation after water flooding of 35 per cent pore volume, compared to the negligible oil saturation initially in the gas caps. The Sholem Alechem Springer field, located in Stephens County, Okla., is an elongated anticline with structural dips varying from 400 to 1,000 ft/mile. The structure contains numerous faults, some of which are sealing. The portion of the field considered in this paper is Fault Block "A", which is the largest of the five major fault segments in the field. A map of the unit is shown on Fig. 1. The unit is bounded on the east and west by major sealing faults, on the north by a water-oil contact and to the south by a deterioration of sand development. Two domes, each having gas caps, exist in the unit and are separated by a north-south fault as shown in Fig. 1. The sands being flooded are the Sims sand members of the Springer series of early Pennsylvanian age. The Sims sands average over 100 ft in thickness in Fault Block "A" and have a porosity of approximately 19 per cent. Core permeabilities average 160 md, with interstitial water saturation of about 23 per cent pore volume. Three different zones can be correlated over most of the area. However, they are commingled in most of the producing wells. The two upper zones, designated as First and Second Sims, are the most important. Both the First and Second Sims have gas caps in the east dome, while only the First Sims has a gas cap in the west dome. These gas caps, whose limits are also shown on Fig. 1, initially occupied nearly 11 per cent of the total reservoir volume. The major concern of this paper is the control of the two gas caps in the First Sims sand. Fig. 2 is a cross section, to scale, across the east dome of this formation. Notable features are the relatively shallow dip, the deterioration of the First Sims sand on the south side of the gas cap and the water-oil contact on the northern edge. The formation dip at the gas-oil contact in this cross section is approximately 5".