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By D. H. Henley, F. F. Craig, W. W. Owens

The oil recovery performance of systems producing entirely by bottom-water encroachment has been experimentally determined in a series of scaled laboratory-model tests. The effects of well spacing, fluid mobilities, rate of production, capillary and gravity forces, well penetration and well completion techniques on the oil recovery performance have been investigated. The laboratory tests were performed using two uniform, un-consolidated sand-pack models. The models have ratios of the interwell distance to the formation thickness of 12 and 2, respectively. Tests at constant total fluid production rate were performed simulating a range of uniform reservoir characteristics and operating conditions encountered in field operations. The performance was determined by material balance and by observation of the encroachment of dyed fluids into the models. The results of the model tests agreed with those obtained mathematically when the conditions previously considered in theoretical studies were simulated, that is, when the oil and water are of equal density and no capillary forces exist. The model study of bottom-water drive indicated that certain variables can aoect the oil recovery performance to a greater degree than can be predicted by present analytical methods. In one comparison, the oil recovery at a water-oil ratio of 20 (obtained at a wide well spacing) varied as much as threefold, depending upon the system's properties and the production rate. Lesser effect of mobility ratio and no eflect of capillary forces over the range studied were observed. The test 'results also showed that the deeper the well penetration into the oil column, the greater the total water production to a producing WOR of 20. However, the ultimate sweep efficiency, and so the oil recovery to this level of WOR, did not vary significantly with well penetration. Horizontal fractures at the top of the formation did not significantly change the sweep characteristics of the reservoir models when values of radius and fracture capacity encountered in actual reservoirs were used. Impermeable pancakes at the bottom of the well moderately increased the oil recovery efficiency both at water breakthrough and at high water-oil ratios. A method is outlined by which the oil recovery performance of other uniform bottom-water drive systems can be estimated from the information obtained in these model tests. INTRODUCTION When oil is produced from a well which partially penetrates an oil zone completely underlain by water, the water rises directly beneath the well in a symmetrical cone when the system is uniform. Two different flow mechanisms can cause the water cone to form—coning and bottom-water drive. In coning, the aquifer is relatively inactive and the cone is formed beneath the well by the pressure gradients associated with the oil flow to the well. The oil can be produced by a solution-gas drive, an edge-water drive or other driving forces in the interwell area. In a bottom-water drive, the driving force for oil production comes from an upward encroachment of the underlying active aquifer. Two papers have analyzed the theoretical performance characteristics of bottom-water drive reservoirs. In the initial mathematical investigation, Muskat' established the equations which determine the pressure distribution in this type of reservoir and solved these equations for certain conditions. Specifically, it was assumed that the water and oil had equal mobilities and equal densities, there were no capillary forces, the pressure throughout the oil zone remained above the bubble-point pressure, a constant pressure existed at the initial water-oil contact and the oil was completely displaced by the encroaching water. These assumptions were used in obtaining analytical solutions. In general, Muskat found that the sweep efficiency to initial water breakthrough to the well was larger for the thicker oil zones, the closer well spacings, the lower ratios of vertical to horizontal permeabilities, the smaller the penetration of the well into the oil zone and the smaller the bore size of the well. The production history after water breakthrough was expressed as a volumetric sweep efficiency at a given producing water-oil ratio. The results indicated that cumulative oil production at producing water-oil ratios of 10 is less affected by the well spacing than is the water-free production history. Muskat studied well spacing which today would be regarded as close. The maximum value of his dimensionless well spacing (ratio of interwell distance to formation thickness) was 4.3. This would require the development of a 50-ft-thick oil sand on less than 10-acre spacing if the vertical and horizontal permeabilities were equal, with

By John W. Pack

At present the manufacture of metallic zinc, or spelter, in Missouri, is carried on only at the establishments located at Carondelet, or South St. Louis. Although the development of the industry has not yet reached that fulness which it has attained elsewhere in the United States, still the commanding advantages of position of these establishments are so evident that the prospective importance and magnitude of spelter manufacture in this State, and especially at this locality, can hardly be doubted. A study of the chemical and technical aspects of the business of these points cannot be without interest to the metallurgist as well as to the capitalist. I have endeavored to investigate, as far as was practicable, within the limits of a paper of this character, some of the problems connected with this industry, at the same time making a few comparisons of the results attained at some of the Carondelet works with those of other establishments with regard to which information could be obtained. In the prosecution of these studies I have been kindly aided by the managers of Carondelet establishments, and by Prof. Charles P. Williams, Director of Rolla School of Mines. To the latter I am especially indebted for assistance in regard to methods of analysis. To all these gentlemen I return my thanks for their valuable aid. Other sources of information will be duly credited in their proper places.

By J. H. Henderson, R. J. Wygal, J. Naar

Experimental work is reported which shows that consolidated rocks and unconsolidated porous media exhibit different imbibition flow behavior. At a given saturation the imbibition nonwetting permeabilities for a rock are smaller than the drainage permeabilities. The contrary happens for unconsolidated aggregates — imbibition nonwetting permeabilities are larger than drainage ones. A similar difference is observed for the wetting phase. Imbibition permeabilities are larger than drainage ones for a consolidated rock but smaller than drainage permeabilities for an unconsolidated medium. The results of these differences are examined for two cases. 1. Flooding Efficiency — Craig's1 scheme for the computation of production history of a five-spot water flood is shown to agree extremely well with experimental results obtained when using a system packed with glass spheres if imbibition relative permeability curves are used. 2. Alcohol-Slug Displacement — Published theory 2 on oil displacement by alcohol slugs has been questioned despite the apparent agreement between predicted and observed results. The present work suggests that, if imbibition relative permeability curves characteristic of the unconsolidated media used in the early experiments had been available to make the predictions, the inadequacy of the theory would have been immediately evident. The experimental work shows that poorly consolidated formations tend to behave like unconsolidated media. Finally, it is shown that the difference in imbibition behavior is directly related to pore-size distribution and cementation. PART 1 — THE FLOW BEHAVIOR OF UNCONSOLIDATED AGGREGATES Experiments on scaled models of field reservoirs are useful for studying new displacement processes which are incompletely understood. Even when a mathematical description is possible, the solution might be difficult and complex. An answer obtained from a scaled model is extremely valuable in such cases. A great amount of work$-5 therefore, has been devoted to the derivation of scaling laws. Similarity groups have been defined which assume (1) that the relative Permeability curves of the prototype and the model are the same whether the displacement is an imbibition or a drainage process and (2) that there is a linear relationship between the capillary pressure of the model and the prototype. For practical reasons (simplicity in the preparation of models, duration of the experiments, etc.), the porous media of laboratory models are usually unconsolidated packs of sand or glass particles. Hence, unless the capillary and flow characteristics of unconsolidated and consolidated systems are identical, the model data are applicable only to unconsolidated formations. The usefulness of scaled-model studies may then be seriouslyrestricted since most oil-bearing sands are consolidated. Perkins and Collins6 suggested the use of model and prototype curves normalized with respect to both relative permeability and saturation to improve compliance with scaling criteria. Even this technique does not give a satisfactory model-prototype match. This paper reports an observation of two-phase flow in unconsolidated sands which shows that, for most displacements, "scaling" in the strict sense of the word is not even qualitatively feasible with a sand model. It provides, however, a firm foundation for testing a theory by matching it with observed performance of laboratory-size models. EXPERIMENTAL AS a part of a basic study of packed aggregates, the relative permeability of glass-spheres and sand-grain packs was measured with capillary control. The fluids were oil and air' The spheres were packed in plastic cylinders 1-in. in diameter;

By M. A. Selim, W. H. Somerton

Thermal expansions and heats of reaction of three typical sandstones were measured in the temperature range of 25°to 1,000°C. The significance of these data in subsurface heat-transfer calculations is discussed. Linear thermal expansions were measured both parallel and perpendicular to the bedding planes. Volume expansions are reported as the perpendicular expansion plus two times the parallel expansion. Expansion behavior of the sandstones was found to be controlled by the expansion characteristics of the quartz content. Differential expansion of the quartz grains and other minerals included in the sandstones caused permanent deformation of the heated samples after they were cooled to room temperature. Structural damage resulting from heating is probably an important cause of the reduction of thermal conductivity of heated samples. Measurements of heats of reaction were based on the known heat required for a- quartz inversion. Thermal reactions, which probably include deby-droxylation of clay minerals and decomposition of carbonate minerals contained within the samples, were found to require more than one-fourth of the amount of heat necessary to raise the temperature of the rock alone. In shales and limestones, the reaction heat could be substantially greater than that required from specific heat considerations alone. INTRODUCTION In earlier work, l-3 methods of measuring thermal properties were developed and thermal data for several sedimentary-rock types were reported. Data included thermal conductivity, specific heat and thermal diffusivity. In addition, calculations of heat transfer in subsurface formations may require data on the thermal-expansion characteristics of rock and the heats of reaction of mineral constituents. Thermal expansion of rocks is relatively small in magnitucle and, from the standpoint of change in bulk density, has only minor effects on heat-transfer cliaracteristics. Thermal-expansion behavior, however, may have significant effects on the structure of rocks. Differential expansion of different minerals and along different crystal-lographic axes may result in structural damage which could effectively reduce the thermal conductivity of the rock. Many mineral constituents of sedimentary rocks undergo phase or related changes when heated to sufficiently high temperatures. Although some of these reactions (such as the a-ß quartz inversion) are reversible and the heat absorbed is returned to the system upon cooling, many of the major reactions are irreversible. Through certain temperature ranges, the additional heat energy required to complete the reactions may be nearly as great as that necessary to raise the temperature of the rock in the absence of thermal reactions. If the heat requirements for these reactions are not considered, serious errors in heat-transfer calculations may result. Thermal-tzxpansion and thermal-reaction data have been obtained for three typical sandstones. Methods of measurement and results obtained are reported and discussed in the following. THERMAL EXPANSION OF SANDSTONES The linear expansions of three outcrop sandstones (Bandera, Berea and Boise) have been measured in the temptbratue range of 25° to 1,000° C. Expansion measurements were made in the directions parallel and perpendicular to the bedding. The differential expansion apparatus used is that described by Mitoff and Pask.4 The test sample is heated in an electric furnace with a temperature rise of 6°C/minute. The lengthening of the samples upon heating is compared with the small and known expansion of a fused silica rod. The change in length is transmitted to an X-Y recorder by means of a Statham transducer. A maximum error of ± 1.5 per cent has been obtained with this apparatus

THE Institute assembled on Tuesday evening, in the building of the University of Pennsylvania. In the absence of President Thomas, Vice-President Raymond occupied the chair. The Institute was welcomed in an eloquent and thoughtful address by Prof. J. P. Lesley, to which Mr. Raymond responded. Invitations were announced from the proprietors of Sellers' Tool Works, Whitney's Car-wheel Works, the Baldwin Locomotive Works, Lewis & Brothers' White Lead Works, the Southwark Foundry, Harrison's Boiler Factory, the University of Pennsylvania, and the Academy of Natural Sciences. The following gentlemen, being duly recommended by the Council as members and associates, were unanimously elected : Alexander, John S., . . . . . Philadelphia, Pa. Biddle, E. R., . New Pork. Britton, J.. Blodget, . . . . . Philadelphia, Pa. Brooks, Maj. T. B., . . . . . Marquette, Mich. Brown, D. P., . Pottsville, Pa. Canfield, Edw., . . . . . . Dover, N. J. Cogswell, W. B., . .Franklin IronW'ks, N. Y. Cornwall, Prof. H. B., . .New York. Edwards, Daniel, . . . . . . Danville, Pa. Estabrook, Juhn D., . . . . . Philadelphia, Pa. Firmstone, William, . . . . . Easton, Pa. Fritz, John, . . . . . . . Bethlehem, Pa. Gignoux, Charles, . . . . . . New Pork. Grant, E. M., . . . . . . . Tuskegee, Ala. Humphreys, A. W., . New York. Ingham, W. A,, . . . . . . Philadelphia, Pa. Keyes, W. S., . . . . . . Eureka, Nev. Kimball, Dr. J. P., . New Pork. Law, Charles, . Pittston, Pa. Neilson, W. O., . . . . . . Philadelphia, Pa. Newberry, Prof. J. S., . . . . . New York. Pearse, John B., . .Steel Works P. O., Pa. Ricketts, P. De P., . . . . . New Pork. Scranton, Col. Charles, . . . . . Ox ford, N. J. Sontag, Hugo, . . . . . . Cologne, Prussia. Steele, Thomas C., . .Summit, Pa. Wharton, Joseph, . . . . . . Philadelphia, Pa.

By R. W. Raymond

I wish to call the attention of the Institute to a curious subject, brought to my notice last summer by Mr. Begger, the accomplished metallurgist of the smelting-works of the Boston and Colorado Company at Black Hawk, near Central City, Colorado. At these works, the richest auriferous sulphurets of Colorado (particularly copper pyrites) are smelted in reverberatories, together with roasted tailings (iron pyrites), and the gold and silver are concentrated into a new, artificial sulphide, or copper matte, containing $1500 and upwards of the precious metals per ton, and this is shipped to Swansea. I will say in passing, that this shipment of an unrefined product, like the similar shipments from Utah and Nevada to San Francisco, Chicago, St. Louis, Newark, New York, and Europe, of crnde argentiferous lead or "base bullion," is not a sign of incomplete metallurgy here, but has a sound business reason. The separation of the precious metals in the West would be more expensive, to begin with ; and then it would necessitate the movement of these metals by express, . - at high rates and risk, to commercial centres or coining mints, while the base metals having no home market, must be shipped and sold at little or no profit. At present, the gold and silver, safely packed, as it were, in the base metals, are transported with safety as ordinary freight; and the base metals probably more than pay cost of shipment and separation. To return to the Black Hawk reverberatories. On a recent occa-

By J. Geertsma

The relationship between porosity and the speed of propagation of acoustic waves in fluid-saturated porous rocks as measured by the Sonic log and by ultrasonic tecbniques is analyzed. Biot's continuum theory 1 is used to explain the difference in acoustic wave propagation between a dry and a liquid-saturated porous material. The porosity is a variable in this theory. However, the acoustic wave propagation in the dry rock depends too on porosity, and this dependence is not predicted by the theory. Frequently in dry sandstones, a nearly linear relationship between reciprocal acoustic wave velocity and porosity is observed in the low-porosity range. The physics behind this behavior is outlined. An empirical relationship of the form, 1/v = A + F, applies accordingly for many porous dry rocks, provided the porosity is the only variable. The presence of a liquid in the pores changes the value of B, and this change is found to be in agreement with the Biot theory. The time-average relation introduced some years ago2 results in an equation of the same type — 1/V = F/Vf + (1 - F)/Vr — but is not based on a sound physical picture. Still, this relation sometimes predicts approximately correct A and B values. Carbonate rocks with their complicated pore structures sometimes show a different relationship between wave velocity and porosity, unfavorable for log interpretation. Examples are presented. The simultaneous presence of calcite, dolomite and anhydrite, with their different grain densities and matrix compressibilities, complicates acoustic-log interpretation in carbonate rocks still further. Other complicating effects of acoustic-log interpretation are discussed. They are related to the influence of shale streaks and natural fractures on the average wave velocity observed by the logging tool and to the effect of adsorption phenomena on wave propagation in unstressed rocks particularly in sandstones. INTRODUCTION The velocity of propagation of sound waves in porous sediments as a function of depth is a quantity frequently measured. Velocity loggers of various d-sign may be used, for which velocity is defined as the. distance between a wave generator and a wave detector (one-receiver system) or the distance between two wave detectors (two-receiver system), divided by the shortest time required for a vibrational pulse to cross this distance. Velocity loggers ale used to assist in seismic prospecting, to differentiate between the various types of sedimentary rock layers, and also to determine rock porosity and pore fluid content. This paper is especially concerned with the relation between velocity and porosity and the effect of the pore fluid. Most velocity-log interpretation in terms of porosity is based on a formula advocated by Wyllie, et al,2 suggested earlier by Hughes and Jones,3 and known as the "time-average relation". This formula app1ies for a model consisting of a layered system of parallel alternating slices of a solid and a liquid, crossed by the wave path perpendicular to the interfacrbs. This must be an unsuitable model for the derivation of wave propagation properties of liquid-saturated porous media. It suggests that only rock matrix and fluid properties influence the wave velocity. The surprising fact, nevertheless, is that applications of this formula to clean sandstones under specific conditions (sufficient effective stress) results in porosity predictions which are close to reality. Other authors, such as Gassmann,4 White and Sengbush,5 Brandt,6 and Hicks and Berry,7 make use of more realistic models to arrive at a wave velocity formula for porous sediments. Their models consist of various liquid-saturated packings of frictionless spherical grains and are, therefore, also highly idealized. A number of experimental results obtained in the laboratory can be better explained with these model theories than by the time-average relation. A study of a general character, not depending a priori on a special model of the porous structure, was still lacking.

By Henry Engelmann

ORes are generally found in the mines mixed with more or less base matter, which renders their treatment by smelting or milling unnecessarily costly. They have to be sorted. Those of a higher grade remain often mixed with substances which might, with hardly a loss of metal and at small expense, be removed by dressing machinery, and a concentrated and purified ore thus obtained, which would bring a far higher price, because it can be reduced by cheaper methods, and, at any rate, at less expense, besides affording a saving of transportation, which in our territories is often an item of no small magnitude. The ores of a lower grade have often to be

By G. Thodos, R. B. Grieves

A method has been developed For predicting the critical temperatures and critical pressures of binary mixtures of carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen with the normal paraffin hydrocarbons. For carbon-dioxide and hydrogen-sulfide systems, relations are presented that take into account the peculiar behavior of mixtures with closely boiling components, such as carbon dioxide-ethane and hydrogen sulfide-propane mixtures which exhibit minimum critical temperature points. For hydrogen, nitrogen and carbon-monoxide systems, the extreme critical behavior caused by wide differences in pure component properties is established In addition, those fixed gas-paraffin systems which resemble paraffin-paraffin systems are also accounted for. For a mixture of known composition, the pure component critical temperatures, critical pressures and normal boiling points are all that are required to determine its critical point. Graphical relations are presented relating Tc and PC , of the mixture to the pure component properties. From the treatment of 12 carbon-dioxide and hydrogen-sulfide systems reported in the literature (74 mixtures), the expected error lor the critical temperature is approximately 1.5 per cent, and for the critical pressure, approximately 2 per cent. From the treatment of six hydrogen, nitrogen and carbon-monoxide systems reported in the literature (30 mixtures), the expected error for both the critical temperature and critical pressure is approximately 2.5 per cent. The relationships, which have been developed with only normal paraffins as the hydrocarbon components, may be extended to those isoparaffins and olefins which fall within the allowable volatility ranges. INTRODUCTION Many of the fixed gases — carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen — occur in natural mixtures with hydrocarbons. Carbon dioxide and hydrogen sulfide are frequent components of the fluids produced from underground petroleum reservoirs. Nitrogen, carbon dioxide and hydrogen sulfide are present in varying quantities in most natural gases and gas-condensate well effluents. Hydrogen mixtures are of considerable interest in many phases of refining processes of petroleum. The determination of the critical temperatures and critical pressures of such mixtures is of value in vapor-liquid equilibrium studies, for the prediction of the characteristics of underground reservoirs, and for reduced-state correlations of PVT, transport and thermodynamic properties. The accurate estimation of the critical point for binary mixtures is an important initial step toward a complete analysis for the establishment of the critical temperatures and pressures of multi-component mixtures. Methods for predicting the critical temperatures and critical pressures of binary hydrocarbon systems have already been presented in the literature.8 It is possible to apply these existing methods to fixed gas-paraffin mixtures, but due to their unusual critical behavior, values calculated deviate considerably from experimental values. For systems containing trace quantities of the fixed gases, these methods are acceptable; however, for systems containing more than 5 mol per cent of the fixed gases, these utterly fail to produce reasonable critical values. Consequently, in this study a method has been developed for handling such binary mixtures over the entire composition range. CARBON-DIOXIDE AND HYDROGEN-SULFIDE SYSTEMS The critical behavior and the vapor pressure behavior of mixtures of carbon dioxide and hydrogen sulfide with paraffinic hydrocarbons may be quite similar or quite dissimilar to that of paraffin-paraffin mixtures, depending on the volatilities of the components involved. The critical temperature and normal boiling point of carbon dioxide are very close to the corresponding values for ethane, while its critical pressure is considerably higher than that of ethane. The normal boiling point of

By D. B. Robinson, J. Lukacs

A knowledge of the equilibrium water content of hydrocarbon systems under pressure is important to the natural gas industry. The information available on the solubility of water in hydrocarbon, hydrogen sulfide, and carbon dioxide systems is reviewed in this paper and the influence of the more important variables such as temperature, pressure and molecular structure on solubility in liquids and gases is discussed. A suitable cbromatographic technique has been developed for determining low concentrations of water. Tailing of the water peaks has been elim inated by adding water to the carrier gas stream The method is applicable for both gas or liquid samples and is effective in the presence of hydrogen sulfide. The experimental study of water solubility in methane-hydrogen sulfide systems at a temperature of 16oF has shown that the presence of hydrogen sulfide causes only a modest increase in water content at pressures up to 1,400 psia. Theoretical considerations and data on pure hydrogen sulfide and carbon dioxide suggest that the effect of both these compounds will be greater at higher pressures and in the liquid phase. INTRODUCTION Before transporting or processing natural gases and gas condensates, it is usually necessary to dry them using suitable dehydration equipment. The design and operation of this equipment requires a knowledge of the amount of water present in the fluid at the reservoir and operating conditions. This is influenced by temperature, pressure and composition, particular1y when certain non-hydrocarbon components are present. Field experience indicates that hydrogen sulfide and carbon dioxide, for example, alter the usual water solubility relationships appreciably. However, an extensive search of the literature does not reveal any quantitative data on such systems. For sweet natural gases, generalized empirical correlations such as the one proposed by Katz, et al,6 can be used to predict water solubility with confidence at most temperatures and pressures of interest. However, existing theoretical relationships do not permit a calculation of the deviation from these curves when polar substances like hydrogen sulfide are present in the system. Thus one must resort to an experimental approach to obtain the necessary information. The fact that laboratory experimental methods frequently involve the use of mercury which reacts with hydrogen sulfide in the presence of water, and that hydrogen sulfide interferes with many chemical reactions specific for water has contributed to the difficulty of studying water solubility in systems containing hydrogen sulfide. In this investigation the water content of a limited member of methane-hydrogen sulfide mixtures was determined using a special technique with gas chromatography. REVIEW OF PUBLISHED DATA Experimentally determined water solubility data have been reported for methane, 14 ethane, 15 propane, 9 n-butane, 16 1-butene, 11 hydrogen sulfide 18 and carbon dioxide. 19 These studies report the effect of pressure, temperature and molecular structure on water solubility in single component gases and liquids. Fig. 1 compares experimentally determined water solubilities in several hydrocarbons, carbon dioxide and hydrogen sulfide at l00F as taken from this

By Henry D. Hibbard

At the beginning of a Henry M. Howe lecture it seems fitting to refer to Howe's great contributions to steel metallurgy, and particularly to the literature thereof. Most of my predecessors in this role have been able, from their association with him, to give direct testimony as to his great services; but although connected with him for years in a business way, I am less familiar with what might be called his academic side, except as it is embodied in his utterances, written and oral. Howe was adept in his genial way in extracting information in any line which, at the time, was of interest to him. In a technical lecture one expects as a rule new knowledge—something about recent advances relating to the subject. On this occasion, however, I will ask you to go back with me to the primary department of steel lore, as the title of my lecture shows, to review the more fundamental features in that field for the purpose of seeking some gaps which we can fill and so give the subject renewed interest. In thus going back one must inevitably repeat many familiar facts, but that seems to be necessary in order to reach a clear understanding of the unrecorded matters. The full interpretation of a steel analysis is at present unattainable, though much progress toward that end has been made. The ultimate analysis, giving the percentages of the five commonly determined elements, does indeed usually give a fair idea of what the steel is, and is ordinarily enough, with knowledge of its history and physical condition, to enable it to be assigned to some purpose or use for which it is reasonably suitable. But discrepancies arise. Every maker and every user of steel knows, from at least occasional examples in his own experience, that the ultimate analysis is insufficient by itself to enable one to tell positively, from its interpretation, either the mechanical properties of the steel or its adaptability to the purpose for which it was made. Further, if, while having the specified composition, it is abnormal or unsatisfactory, why it is so. Good, bad and indifferent steels may have substantially the same ultimate analysis.

By Francis L. Vinton

THE eccentric theodolite I exhibit is one constructed by the Stack poles of New York, from drawings, considerably modified, of Combes's theodolite. The telescope is on one side of the horizontal limb, and the vertical circle is opposite to the telescope ; thus they nearly balance each other, making already the construction lighter than in the instrument of Combes, where the telescope and vertical circle are together on the same side, and are both balanced by a considerable weight. The instrument stands upon three levelling screws or feet, an improvement upon the old or general style of mounting a transit on four feet for indeed the instrument is easier levelled, and, moreover, stands more stable on three than on four points of support. The general advantage of an eccentric theodolite is evident, namely, that it can measure Any and all vertical angles, from 0 to 360, without being interfered with by the horizontal limb as is the transit; besides this advantage, it needs no preparatory adjustment or correction for eccentricity; on the other hand, however, that correction

By L. H. Robinson

Triaxial compression tests on Indiana limestone indicate that chemical additives in the pore fluids can increase or decrease the strength in plastic failure but not in brittle failure. Tests using a series of the sodium salts of dicarboxylic acids show that odd-number carbon-atom chains decrease the yield strength as much as 3.0 x 10 3 psi, and even-number carbon-atom chains increase the yield strength as much as 9.0 x 102 psi. ,The most effective chemical (sodium citrate) decreased the yield strength of Indiana limestone from 16.0 x 103 to 12.0 x 103 psi. The chemical additives investigated have no influence on microbit drilling rate when drilling with zero differential pressure. However, when drilling at a 2.0 x 103-psi pressure differeniial and using an odd-number carbon chain compound as the circulating fluid, the roller bit drilling rates were slower than with water whereas the drag bit drilling rates were faster. One even-number carbon chain compound added to the circulating fluid produces the opposite effect: the roller bit drilling rate is slightly faster than with water and the drag bit slower than with water. INTRODUCTION A Russian book by Rehbinderl published in 1944 generated much interest in the possibility of aiding and accelerating the destruction of solids by the action of a liquid in which the solids are deformed. This book describes a process in which microcracks are generated during elastic deformation. To describe this process, the rock is divided into three zones: (1) the zone in which the destruction takes place, (2) the predestruc-tion zone (an affected area immediately below the destroyed zone) and (3) the undisturbed specimen. Consider a load applied normally to a surface of an infinite slab of rock. Immediately below the point of application of the load, the rock is destroyed by compression or shear forces. Below this area of destruction, because of a great number of discontinuities ranging from defects to weak points in crystals of discontinuities in crystal latices, very small cracks are created in or between the crystals (often referred to as microcracks). Upon removing the load, the broken rock in the destroyed zone could be removed. In the lower predestruction zone, however, the microcracks in and between the crystals could disappear by the process of rehealing, i.e., the molecular attraction from one side of the crack to the other side being sufficient to completely eliminate the crack. Thus, a large number of these microcracks possibly exist only for a relatively short period of time. The concept of small cracks being generated within the crystals of a rock is not unreasonable. If the rock matrix is deformed below the yield point, some of the defects present within the crystalline structure could start small cracks through the interior of the grains. Upon removal of the load, these microcracks reheal (or the newly generated surfaces come back together) so that all evidence of cracks completely disappears. Under various types of loading, and in various types of fluids, the rehealing of these cracks would be time dependent. If a liquid adhered to the surface of a rock, it could penetrate into the microcracks and thus delay or prevent the rehealing process. This suggests that the prevention of healing of the microcracks may be dependent upon the wetting characteristics of the solid. Thus, rocks which are water-wet should be more easily destroyed in water than in nonpolar hydrocarbon liquid. Adsorption of a liquid could also reduce the free surface energy which could explain the decrease in strengths of materials under nonrepetitive-type loading. Rehbinder's work prompted Boozer, Hiller and Serdengecti 2 to examine the effects of pore fluids on the deformation of rocks subjected to triaxial compression over a range of confining pressures, temperatures and strain rates. Fluids which strongly adsorbed on the rock grain surfaces decreased the strength of sandstone and limestone, which deformed plastically. For certain strain

By G. H. Alani, H. T. Kennedy

One of the major difficulties in predicting the performance of oil reservoirs from their early pressure history lies in the uncertainty of estimating the volume of the liquid hydrocarbons contained in them. As a first step in filling this need, an equation was developed to determine the Inolal liquid volume of pure hydrocarbons over a wide range of temperature and pressure. The second step consisted of adapting the equation to apply to mixtures, with the heary hydrocarbons expressed as c The equatious are similar in form to van der Waals equation. hut the constants a and b tire considered as furnctions of temperature. In addition to the gas constant R, there are four constants characteristic of each hydro- When comptired with experimental values jound in the literal the. the average absolute deviation in the calculated molal volumes is found to be a Maximum of 0.33 per -cem for any of the pure liquid hydrocarbons studied. This maximum deviation was that found when comparing the calculated and observed values over a temperature range of 86° to 482°F and a pressure range from the bubbl-point ro 10,000 psis. The equations expressing the correlation for. mixrurrc were developed from 647 experimental measure-rilents of volume on 47 bouom-hole samples covering ; temperature range of 72" to 250°F and a pressure znge from bubble-point ro 5,000 psig. The average absotute deviation was found to he 1.6 per cent with the maximum for any measurement of 4.9 per cent. INTRODUCTION Accuratc information of the pressure-volume-temper-iiture behavior of hydrocarbon liquids is of considerable importance in the field of both applied and theoretical science and, especially, in the solution of petroleum reservoir engineering problems. These PVT relationships can be expressed graphically, in tabular form or as equations of state. Equations of state for gases have been developed based on the ratio of pressure, temperature and volume to the pressure, temperature and volume at the critical points of the hydrocarbons. These equations have been successful in yielding values fairly accurate for reservoir engineering purposes. For liquids, however, relations of this type are more complex and have not yielded useful results. The composition of reservoir liquids is normally expressed in terms of the moles of hydrocarbons C,? C,. C,. elc, per mole of mixture. The composition must include the fraction of a mixture such as C,,, which cannot be separated with reasonable time and effort into specific hydrocarbons. Although there are several equations of state having variable degrees of accuracy applicable to pure liquid hydrocarbons, none includes a means for estimating the volume of mixtures as a function of temperature. pressure and composition expressed in this manner.

By H. W. Becker, C. C. Frye, A. V. Degau, A. Masuda

Natural gas containing 25.65 per cent hydrogen sulfide and 4.75 per cent carbon dioxicle is gathered frorn eight \veih arid tratzsporrcd 26 miles at a flow rate of 160 MMcf/D and at operating pressures of frotrl 1,200 to 1,800 psig. Dry desiccant dehydrators at each wellsite tnaintaitz the dew point of the gas below 17F. Telemetering facililies permit control of field operations from a central instrunlent console. Corrosion control ineasures, design coilsiderations and material specifications pertainitz to these specia1 conditions are cliscussed. INTRODUCTION Natural gas containing 25.65 per cent H2S and 4.75 pcr cent CO, is produced from the Pine Creek field, Alta. It is dehydrated at wellheads, gathered at 2.200 psig and transported 26 miles to the Windfall field where it is delivered to the inlet of injection compressors at 1,800 psig. The daily average volume of gas transported is 160 MMcf. The project is believed to be unique in its combination of percentage of hydrogen sulfide, operating pressure and transportation distance. This paper describes the project and presents details of some of the design features, corrosion control program and centralized automatic operational control. The Pine Creek field project is one phase of a joint operation of two fields—thc other being the Windfall field. The two fields lie about 30 miles north of Edson, Alta. and 20 miles west of Whitecourt, Alta., respectively, as shown on the map (Fig. 1). They are owned by the same interests and operated according to a plan for maximum economic recovery of products. The Windfall Leduc D-3 reservoir contains a rich condensate-bearing gas containing 15.5 per cent HIS. The gas from the Pine Creek field contains only very small quantities of butane and heavier products. The Windfall reservoir is being cycled to obtain maximum condensate recovery using gas from the Pine Creek field as the displacing fluid, while producing the residue sales gas for both fields from the Windfall field. The Pine Creek field development and gas-gathering facilities are shown on the map (Fig. 2). The producing formation is the Leduc D-3 reef at a depth of 11,300 ft. The original reservoir pressure was 4,590 psia at 7,400 ft subsea and the temperature is 245F. Eight wells are equippcd with dry desiccant dehydrators with the following capacity ratings: three at 35 MMcf/D; three at 20 MMcf/D; and two at 10 MMcf/D. WELLHEAD EQUIPMENT Dry desiccant dehydrators were designed to reduce the water content of the saturated wellhead stream to 2.5 lb of water/MMcf at 2,000 psig. This specification was necessary to prevent hydrates and corrosion forming in the pipeline which will operate at temperatures as low as 20F. A typical flow diagram is shown in Fig. 3, and Fig. 4 is a photograph of one of the wellhead installations. Some of the design details given below are subject to modification in the field. The well-stream flowing temperatures range from 135 to 170F. Wellhead flowing pressures up to 3,200 psig are reduced to the dehydrator-operating pressure of about 2,100 psig by throttling through a pressure control valve. The gas is then passed through an aerial cooler where its temperature is reduced to 105F. thus removing over half

By H. A. Wahl

This paper presents methods of designing hydraulic fracture treatments in formations saturated with slightly compressible liquids. Howard and Fast describe the fluid-loss control resulting from the viscosity and compressibility effects of the reservoir fluid in terms of a fracturing fluid coefficient. However, for horizontal fractures, this coefficient is applicable to infinitely thick reservoirs. These methods of evaluating fluid loss from horizontal fractures during treatment differ from previous methods in that: (I) formation thickness is incorporated in the velocity function describing the rate of fluid loss to the formation; and (2) for a given thickness the relative position of the fracture to the horizontal boundaries of the reservoir or any interrnediate permeability barrier is incorporated in the design procedure. This theory is applied to several actual and hypothetical field cases. The results of these calculations demonstrate that the eflect of formation thickness on fluid loss from horizontal fractures may result in fractures several times larger than predicted by other methods. INTRODUCTION Hydraulic fracturing has been the dominating well-stimulation technique during the last decade. From the time it was commercially available, fracturing has had a very favorable success ratio compared to other stimulation methods. However, numerous wells that were successfully stimulated remained economic failures. Only in the last few years has the oil industry recognized the importance of designing treatments for each well which will yield the maximum profit. This implies that for a given set of treatment conditions the size and general physical characteristics of the fracture can be determined. One of the outstanding contributions in the field of fracture design was presented by Howard and Fast.' In their paper, three flow mechanisms that control fluid loss from the fracture to the formation are defined: (1) viscosity effects of the fracturing fluid, (2) viscosity and compressibility effects of the reservoir fluid, and (3) wall-building effects of a treated fracturing fluid. The rate of fluid loss to the formation adjacent to a fracture is shown to be a function of time. For each flow mechanism the velocity function v(t) is expressed as a constant or fracturing fluid coefficient divided by the square root of time. This form of v(t) can be used in the Carter equation, as developed in the Howard and Fasc paper, to estimate the areal extent of fractures. This equation may be written as In the following sections the effect of formation thickness on fluid loss from horizontal fractures is evaluated when the controlling flow mechanism is the viscosity and compressibility of the reservoir fluids. The major assumptions inherent in the Carter equation are brought out in subsequent mathematical developments. THE EFFECT OF RESERVOIR FLUIDS ON FRACTURE EXTENSION When a fracture treatment is performed using a fracturing fluid identical to the reservoir fluid, the only flow mechanism controlling fluid loss is the viscosity and compressibility effects of the reservoir fluids. In developing a fracturing fluid coefficient for this mechanism, Howard and Fast considered a segment of the formation bounded by a unit area on the fracture face and extending to infinity in the direction of leak-off as shown in Fig. 1(a). The direction of leak-off z is normal to the fracture face. The equation governing the linear isothermal flow of fluid into this segment is where a = Eq. 2 is a form of the diffusivity equation. It is derived from the equation of continuity, Darcy's law and Eq. 3

By C. R. Sandberg, L. S. Gournay, R. F. Sippel

The effect of fluid-flow rate and fluid viscosity on oil-water relative permeability determinations was studied using the "dynamic flow technique." In this work relative per-nleability curves were obtained for homogeneous small core .samples from several sandstorle outcrop form-utions. Radio-tracers were used for the determination of fluid saturation and for the detection of saturation gradients. Cobalt-60 in the form of cobaltous chloride was used as a water-phase tracer in some of the experiments. Iodine-131 in the form of iodobenzene and Mercury-20-3 in the form of mercury diphenyl were used as oil-phase tracers in other experiments. Flow rates for each phase were varied within a range of 2.5 to 140.6 ml/hr. Oil-phase vis-cosities under flowing condition,> were varied from 0.398 to 1.683 cp. The relative permbilities ob-tained were found to he solely a function of saturation and independent of flow rare, provided there was no .Saturation gradient induced in the core sample by "boundary effect." Even though equilibrium with re-sped to flowing conditions was obtained at the lower flow rates, where a saturation gradient exists, this equilibrium is of a "contingent"-type rather than the "steady-state" equi-librium implicit in the relative per-meability concept. The only effect of increasing the oil or non-wetting phase viscosity was to decrease the flow rate required for the elimina-tion of the boundary effect. Fairly good agreement between experimentally determined and calculated values of the boundary effect was obtained when the non-wet-ring oil phase was the only Flowing phase. INTRODUCTION In the characterization of reservoir rock, as well as in the solution of reservoir production problems, it is most desirable to have reliablc rela-tive permeability measurements for the rock and fluids of interest. Many techniques have been developed for the laboratory determination of the relative permeability of both large and small core samples. In varying degree, difficulties attend the use of all of the methods. Each of the methods requires the metered flow of fluids of known viscosity through the core sample under conditions wherein the pressure drop in the individual flowing phases can be measured or closely approximated. Since the relative permeability is a function of the saturation and distribution of the flowing fluids, some means of obtaining such information is also required. The laboratory determination of the relative permeability of a sample should give the same relative permeability saturation relationship that would exist if the sample were in place in the oil reservoir. The attainment of this objective is complicated by the fact that the use of small core samples for laboratory measurements is usually necessary. As a result, errors in measuring the relative permeability arise from boundary effects at either the fluid input or output ends of the sample; no significant boundary effect is anticipated at the sides of the sample normal to direction of fluid flow. At the input end of the sample a boundary effect exists if the flow fluids are not com- mingled as they would be in the reservoir. At the output end of the sample a boundary effect exists as a result of discontinuity of the capillary properties of the system. Here the flowing fluids leave the small flow channels and enter a collecting system having much enlarged flow channels. Thus, there is a tendency for the wetting phase to be retained by the core sample because of the attraction of the core sample for the wetting fluid. No reference is made to these boundary effects in either Darcy's equation or in the relative permeability concept. As a consequence the saturation effect peculiar to the input end of the core sample may cause an error in the effective permeability measurement, since some portion of the core sample must be utilized for commingling of the flow fluids. At the output portion of the core sample a saturation gradient or a saturation change along the axis of flow results. Since relative permeability is a function of fluid saturation, this saturation gradient may cause a variable permeability measurement, especially since extent and character of the saturation gradient can vary with fluid-flow rate. The most convenient method of minimizing the boundary effect, especially at the output end of the sample, is to flow the fluids of interest through the core sample at such high rates that the capillary forces arc insignificant as compared to the viscous forces involved in the fluid flow. Since recent work of a preliminary nature has indicated that fluid dispersion in the porous medium increases with the flow rate, the high flow minimizes the boundary effect at the input end of the core sample by enhancing the mixing of the fluids.