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By W. E. Brigham, P. W. Reed, J. N. Dew

By J. D. Alexander, W. L. Martin, J. N. Dew

This paper presents data obtained using a flood-pot technique to determine the fuel available and the corresponding theoretical air requirements for in situ combustion of crude oils. Since the technique is relatively quick and easy, it is a practical and convenient tool for evaluating reservoirs as fireflood prospects. It is also a research tool which facilitates systematic study of the variables affecting fuel availability and corresponding air requirements. The understanding of these variables is of prime importance to those concerned with the technical and economic development of in situ combustion as an oil-recovery process. The experimental results show conclusively that the fuel available for in situ combustion is not a constant but, rather, varies with crude-oil characteristics, porous-medium type, oil saturation, air flux and time-temperature relationships. Thus, the fuel availability for specified field applications should be determined using actual reservoir crude and core material and the process conditions expected during in situ combustion in the reservoir. INTRODUCTION In situ combustion is a thermal process for recovering crude oil from reservoirs. The thermal energy released during the combustion of a small amount of the oil in place aids in the displacement of the remaining oil. Numerous articles have been published describing the in situ combustion process giving detailed results of laboratory and field experiments.10 In order to engineer an in situ combustion project, a number of important factors must be considered and determined. These factors include: (1) the amount of fuel consumed per unit of reservoir volume swept by the combustion zone, (2) the composition of the fuel consumed, (3) the amount of air required to consume this fuel, (4) the portion of the reservoir swept by the combustion zone, (5) the appropriate air-injection rates and pressures, (6) the amount of oil that will be recovered, (7) the rate of oil production and (8) the operating costs. Nelson and McNiell1 recently have described a procedure which utilizes laboratory combustion-tube data as a basis for the calculation of some of these design factors. Various authors have attempted to describe the in situ combustion process mathematically, and considerable progress has been made. Analytical solutions to the problem of heat transfer from a moving combustion front have been obtained for linear and radial systems."-' All of the published results involve the assumptions that: (1) fuel concentration is constant throughout the reservoir, or that fuel concentration is inversely proportional to the velocity of the front for a given rate of oxygen consumption; and (2) the fuel reacts instantaneously with injected oxygen, while liberating a constant amount of heat per unit weight of fuel at all temperatures. It seems both desirable and reasonable to test the validity of these assumptions experimentally. This paper presents laboratory data which were obtained by means of a "fire flood-pot" method for determining fuel availability and composition, and the corresponding theoretical air requirements for in situ combustion of crude oils under variable conditions. The mechanics of the method are similar to a conventional tube-run experiment.' The important differences involve the size of the reservoir model used and the method for providing the experimental environment. The new method subjects conventionally-sized core samples or unconsolidated sands to a programmed environmental sequence similar to that experienced by a similar volume of rock during the approach and passage of a combustion front in a long tube or in an oil reservoir undergoing in situ combustion. Restored-state samples can also be used. The small samples and relatively simple techniques involved allow an experiment to be set up, run and calculated in about three 8-hour days. This is a considerable improvement over long-combustion-tube techniques which can require several days to run and several more work days to set up and calculate. All the runs presented were run at 40-psig injection pressure. Pressure was not considered as a variable for these experiments, since we previously had found that it had only a small effect on fuel availability up to 600 psig.APPARATUS AND MATERIALS APPARATUS The fire flood-pot apparatus consists of a consolidated

By J. Downie, H. A. Kendall, G. H. F. Gardner

Some cases of the motion of two miscible fluids in uniform linear models are discussed. There is no bulk flow through the models, and the convection currents are caused solely by density gradients. Horizontal, vertical and inclined positions of the models are treated separately. Analytical formulas for the motion of a narrow transition zone between the fluids are obtained and compared with measurements, and the limitations are discussed. Observations of the ultimate stabilizing effect of diffusion on the motion me compared with the theory. It is shown that fluid motion in an inclined model with a constant rate of bulk flow can be directly deduced from the cases discussed, provided the viscosity ratio is small. INTRODUCTION In some reservoirs, convection currents caused by variations in the fluid densities may be significant. For practical purposes it may be desirable either to minimize the effect, particularly in miscible displacement, or to maximize the effect as in some schemes for the production of heavy crude oils by combustion. Experiments by Craig, et al,l have shown the effectiveness of gravity in reducing the efficiency of a miscible displacement when the mixed zone between the displacing and displaced fluids is narrow compared with the height of the system. The presence of a board transition zone from one fluid to the other has been shown by Perkins, et al,2 to nullify considerably the influence of a difference in density. Indeed, the theoretical discussion given by Perrine3 has shown that when the transition zone exceeds a certain critical length the efficiency approaches 100 per cent. Many additional results 495 have been published on miscible and immiscible displacements which show the importance of density difference and also mobility ratio. The aim of the present paper is to discuss some cases of gravity segregation of miscible fluids in linear models such as are often used in the laboratory to evaluate recovery processes, and to supply additional experimental evidence in support of the conclusions. An attempt is made to calculate simply the magnitude of the fluid motion caused by density pdients and mobility ratios, and to quantify the modifications in the fluid motion produced by the combined effect of molecular and convective dispersion. However, it should be pointed out that the uniform permeability of the models and the use of only a single pair of fluids (whereas several pairs of fluids may be employed in a recovery scheme) severely restricts direct conclusions about natural reservoirs. For conciseness, the motion generated by density gradients is emphasized for the case of no bulk flow through the models. This is not a drastic limitation because, as shown in Appendix A, a fluid motion with a constant bulk flow through any linear model is equivalent to a fluid motion with no bulk flow in the same model inclined at a different angle to the horizontal, provided only that the density is a linear function of the viscosity of the fluid mixture. HORIZONTAL MODEL In this case the model is assumed to have a rectangular cross-section with a horizontal breadth b, vertical height and a great length L. Throughout.the paper it will be assumed that x-axis points along the length, the y-axis along the width and the z-axis along the height. Thus, in the present case the x, y plane is horizontal. Initially, the transition zone between the fluids is assumed to be thin and parallel to the y, z plane. An example of this situation in a practical problem arises in a scheme for using air for cushion gas in the storage of fuel gas in aquifers. 6 With the passage of time the denser fluid sinks and spreads along the bottom of the model while the lighter fluid rises. The interface extends from the top plane of the model to the bottom. Experiments have shown that for practical purposes this interface may be treated as a plane surface at all times. The surface is significantly curved, however, for viscosity ratios greater than about 10. Other complications arise with large viscosity ratios because of the nonlinear dependence of the viscosity on the composition of the mixture, so that the simple results given here are restricted to fairly low viscosity ratios.

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 V. V. Valleroy, A. J. Cornelius, B. T. Willman, G. W. Runberg, L. W. Powers

This paper reports the results of an investigation into the use of steam as a recovery agent. High oil recoveries by steam, as much as 100 per cent greater than by water flood, were demonstrated in laboratory linear cores. The principal mechanisms responsible for the additional oil have been identified as (1) thermal expansion of the oil, (2) viscosity reduction and (3) steam distillation. Although the first two also enhance recovery by hot water flood, they are effective with steam injection at lower volumes of produced fluids. Steam-zone residual oil saturation is independent of initial saturation. Recovery by steam is greater for lighter oils because they contain a greater fraction of steam-distillable components. Equations for the steam-zone advance in a radial homogeneous system are presented; these show the effect of reservoir parameters. The displacement in the hot liquid region moving ahead of the steam front can be estimated by a calculative procedure which is suggested. The method which takes account of the temperature gradient is applicable also to a regullar hot water flood. INTRODUCTION Considerable industry interest in the application of heat to petroleum reservoirs as a means of increasing oil recovery has been evident in the past few years. Three thermal methods which have attracted interest are (1) the injection of saturated steam, (2) the injection of hot water and (3) the injection of air into a formation to support combustion within the reservoir. Much has been published in recent years on underground burning, and there have been several papers on hot water injection. Although there are several early reports1,2 on steam injection, no recent experimental studies have been published on this recovery method. In our early thermal methods research, a marked improvement was found in oil recovery by steam injection compared with recovery by water injection in the same system. An investigation subsequently was undertaken to obtain quantitative information from which to evaluate steam injection as an oil recovery method. In addition, it was desired to investigate the recovery mechanism of hot water as compared with that of "cold" water and steam injection. An understanding of the mechanisms by which these processes operate would generally define favorable field conditions for their successful application. This paper reports the results of the laboratory study and suggests calculative approaches to estimate the field behavior of the steam-injection process. EXPERIMENTAL METHOD EQUIPMENT A schematic diagram of the equipment used for the displacement tests is shown in Fig. 1. Essentially, it consisted of a core with suitable means for recording temperatures, a feed system for injecting steam or cold or hot water, and a receiving train for condensing, cooling and measuring produced fluids. For the steam experiments, air-free saturated steam was piped from the boiler to the core face in insulated lines that were provided with steam traps and bleeds to remove any condensate formed in the lines due to heat losses. A 12-in. section of the line immediately ahead of

By M. D. Arnold, P. B. Crawford, P. C. Hall

An experimental study has been made to determine the optimum flooding pressures for four different oils. The oil formation volume factors ranged from 1.08 to 2.13, and solution gas-oil ratios ranged from about 200 cu ft/bbl to 2,250 cu ft/bbl. Viscosities ranged from 0.38 to 0.95 cp at the respective bubble points of the fluids and from 0.7 to 20 cp at atmospheric pressure. Water floods were conducted at various pressure levels from run to run. The recovery as a function of flooding pressure was found to be different for each fluid, with optimum gas saturations ranging from 7 up to 35 per cent. The data indicate that substantially higher recoveries may be obtained if water floods are conducted at an optimum pressure and that this optimum pressure is a function of fluid properties. The same core was used for all tests, and the reproduction of saturations for various runs indicates that wettability in the predominantly water-wet core did not change. INTRODUCTION A paper was presented by Bass and Crawford' which described an experimental study of the effects of flooding pressure and rate on oil recovery by water flooding. This work was conducted using high-pressure models operated in a manner similar to that of an actual reservoir, with gas saturations being obtained by a solution-gas-drive mechanism. They found that the greatest oil recovery was obtained for the system studied by flooding in the presence of a 5 to 7 per cent gas saturation. Another experimental study simulating field conditions was presented by Richardson and Perkins.' They used an unconsolidated sand pack containing kerosene-natural gas fluid and interstitial water. They flooded at various pressures and flooding rates. For their system it was found that the recovery was independent of the pressure level at which the water flood was performed. Kyte, et al," found that oil recovery by water flooding was increased as the free gas saturation at waterflood initiation was increased. However, after the initial gas saturation was increased above 15 per cent, the increase in oil recovery tended to level off. All of their runs were made at the same pressure using a light oil saturated with helium. The desired gas saturation was obtained by injecting helium into the core. Dyes' made calculations which showed that an optimum gas saturation of 12 to 14 per cent may result in an increase in oil recovery of 7 to 12 per cent over that obtained by flooding at the bubble-point pressure. Others have also found that the presence of a free gas saturation may increase the waterflood oil recovery. In each case shrinkage was small and changes in fluid properties with respect to pressure were small. A careful review of the literature reveals that at the present time there is a wide difference of opinion on the factors affecting waterflood recoveries. This diversity of opinion is probably due to the fact that very little research has been done which has taken into account the many variables existing in an actual field being water flooded. Since the literature contains little information on high-pressure waterflooding studies using various types of reservoir fluids, it was believed appropriate that such a study should be made. EQUIPMENT AND PROCEDURE All tests were made using the same consolidated sandstone core. Torpedo sandstone was used to turn a cylindrical core 13.5-in. long and with a 2.92-in. average diameter. The core had a porosity of 28 per cent and a permeability to brine of 146 md. This brine was made up by adding 20,000-ppm sodium chloride and 30,000-ppm sodium nitrite to distilled water. This was used as connate water and flooding water. No fresh water was ever brought in contact with the core, as tests showed the sandstone contained argillaceous material which swelled in the presence of fresh water and plugged the stone. The core was sealed in a section of 6-in. N-80 tubing with Woods metal filling the annulus. The core was mounted horizontally; an injection well was placed in the center of one end and a production well in the center of the other. Pressure control was maintained by placing a back-pressure regulator (upstream control) on the producing well. The "live" oil was stored in a separate bottle and water was injected into this bottle to displace the oil for saturating the core using a two-cylinder standard-proportioning pump. This same pump was used for water flooding the core at a constant rate. This system was enclosed in water jackets and the temperature was automatically main-

During development mining, ventilation capacity may decrease and the ventilation requirements may depart from initially planned values depending on the mining rate, increases in the methane emission rate, and changes in ventilation airway leakages. Insufficient ventilation air quantities and the occurrences of high methane liberation rates can overwhelm the existing quantity of ventilation air and result in elevated levels of methane gas during development mining. This condition can both limit the development of that section and increase the risk for an ignition that may lead to an explosion. Thus, the prediction of ventilation air requirements prior to mining can enhance worker safety by reducing the likelihood that explosive methane-air mixtures form. This study presents an approach for prediction of methane inflow rates using coalbed methane reservoir modeling. For this purpose, a two-phase coalbed reservoir model of a three-entry type roadway is developed. In the model, grids are dynamically controlled to simulate development of entries. Examples are given for methane inflow and ventilation air requirements as a function of mining rate, development section length, mining height, and the existence of degasification boreholes. This technology can be used to limit the methane concentrations occurring as a result of the influences of various coalbed and operational parameters.

Jan 1, 2008

During development mining, ventilation capacity may decrease and the ventilation requirements may depart from initially planned values depending on the mining rate, increases in the methane emission rate, and changes in ventilation airway leakages. Insufficient ventilation air quantities and the occurrences of high methane liberation rates can overwhelm the existing quantity of ventilation air and result in elevated levels of methane gas during development mining. This condition can both limit the development of that section and increase the risk for an ignition that may lead to an explosion. Thus, the prediction of ventilation air requirements prior to mining can enhance worker safety by reducing the likelihood that explosive methane-air mixtures form. This study presents an approach for prediction of methane inflow rates using coalbed methane reservoir modeling. For this purpose, a two-phase coalbed reservoir model of a three-entry type roadway is developed. In the model, grids are dynamically controlled to simulate development of entries. Examples are given for methane inflow and ventilation air requirements as a function of mining rate, development section length, mining height, and the existence of degasification boreholes. This technology can be used to limit the methane concentrations occurring as a result of the influences of various coalbed and operational parameters.

Jan 1, 2008

By Wayne E. Glenn

The San Miguelito Field of Ventura County, California, lies along the coast approximately five miles northwest of the city of Ventura. The structure is one of several in the Ventura anticline, a series of anticlinal folds trending northwest-southeast through the San Miguelito Field. The Ventura Avenue Field lies to the southeast along the anticline, and Padre Canyon and Rin-con Fields lie to the northwest; the series then extends beneath the Pacific Ocean. Production is obtained from the Lower Pico and Repetto formations of Pliocene age, and oil accumulation is controlled by faulting, lithology and structure. The first well in the First Grubb Pool was completed in November, 1931, and to date 48 producing wells have been drilled on the 276 productive acres. Approximately 685 ft of net pay are contained in the eight sand bodies grossing 1,220 ft of section. Production of oil to date has been 15,-600,000 bbl. A gas injection project was instigated in April, 1940, but was discontinued in September, 1949. This paper is confined to a discussion of the development and performance history of the First Grubb Pool of the San Miguelito Field. LOCATION AND GEOLOGY The San Miguelito Oil Field is located in Ventura County about five miles northwest of the city of Ventura along the coastal highway to Santa Barbara. It is located within sections 23, 24, 25, and 30 of Township 3 North, Range 24 West, San Bernardino Base and Meridian. Surface elevation in the field ranges from sea level to plus 1,200 ft, and the terrain is extremely rugged. The structure is well defined on the surface and on the wall of the Amphitheatre Canyon where appears a so-called "text book" anticlinal section. The San Miguelito structure is an asymmetrical, elongated anticline about two miles long and three-fourths of a mile wide. The trend of the axis of the anticline is northwest-southeast. Fig. 9 illustrates the contours and major faults of this structure. Dips on the southwesterly flank average about 40 degrees, whereas the northeasterly flank ranges from 60 to 75 degrees. There are several faults striking generally east and west. These faults do not appear to affect materially the area of accumulation or performance behavior. It is believed that accumulation was affected by steeply dipping beds and extremely low permeability of the northeast flank of the structure. As shown by the typical log, Fig. 1. the San Miguelito Field is divided into two stratigraphic producing intervals. The First Grubb Pool comprises the interval from the "G" to "L" markers; the Second Grubb Pool from the "L" to "M" markers. The First Grubb Pool, ranging in thickness from 1,105 to 1,680 ft, with an average of 1,220 ft, includes approximately 685 ft of oil-bearing sands. The First Grubb zone consists of eight sand intervals separated by shales. The shale bodies separating the eight sand intervals within the First Grubb Pool are continuous throughout the major part of the structure and serve as an effective barrier. Many of the thin, irregular shale or siltstone streaks within these sand bodies are discontinuous and do not affect well performance appreciably. The productive horizons in the First Grubb Pool are siltstones and sandstones of the Lower Pico and Repetto formations of Pliocene age. It is apparent from inspection of the typical log that the "G" to "L" interval might have been separated into at least six producing zones and selectively pro. duced. Unfortunately the electric log and some of our modern tools were not available or were in their infancy dur. ing the period 1931 through 1937. Not until 1937 when eight wells had been completed were there sufficient geological data to permit definition of the sand bodies. Then the problem of reservoir control in this multiple-sand field, where all sands are open to a common

Jan 1, 1950

By F. H. Callaway, W. O. Keller

The various theories as to the well spacing-recovery relationship are reviewed in considerable detail and these theories analyzed in terms of their consistency with modern reservoir engineering concepts. It is concluded that the well spacing problem must be analyzed in terms of recovery efficiency and that a positive answer to the relation between well density and recovery efficiency is not available from direct comparisons of the production histories of wells and fields. The results of an engineering analysis designed to permit approximate calculation of recovery efficiencies as a function of well spacing in a depletion type reservoir from basic reservoir data is presented. Results of this type analysis indicate that the effect of well spacing on recovery efficiency in depletion type reservoirs can be expected to be very small. Limitations of this approach are pointed out, particularly with respect to its application in lenticular reservoirs. Testing techniques are outlined which should indicate whether or not a reservoir is continuous between wells and whether or not satisfactory drainage is being obtained with present spacings. A mass of data of this type indicates continuity to exist in most fields. INTRODUCTION The purpose of this paper is to review critically the engineering aspects of the well spacing problem, both from the standpoint of certain concepts and from the standpoint of reservoir mechanics. The well spacing problem is primarily an economic problem in which the optimum well density for a particular field is that density which will yield the greatest oil recovery consistent with justifiable development costs. The well spacing answer in terms of economic conditions, however, is extremely sensitive to the variation in recovery efficiency with well density. The variation in recovery efficiency with 'References given at end of paper. Manuscript received at the office of the Petroleum Branch October 2, 1949. Paper presented at the Petroleum Branch Meeting in San Antonio. Texas, October 5-7. 1949. well density is properly an engineering problem. Different opinions as to the correct answer to this engineering problem is the basis for most of the wide difference in opinion among various members of the industry as to optimum well spacing. This paper will be confined to the engineering problem of the relation between well density and ultimate oil recovery; economic considerations necessary for the evaluation of optimum well density for any particular field will not be discussed. The paper can be logically divided into two parts. The first part deals with a critical examination of the background and logic of the Cutler Rule and of similar studies by other authors and of related well spacing concepts. It is indicated that the variations in recoveries with well density* observed by Cutler and. others can be logically attributed to regional migration. Theoretical justification of the Cutler type relation wherein observed variations in recovery with well density in the same field is attributed to variations in recovery effiiency, in terms of energy relations, is refuted. The second part consists of a review of concepts of reservoir mechanics with regard to the well density-recovery relation. It is indicated that little variation of recovery efficiency with well density can be expected in a depletion type reservoir, unless lenticular conditions prevent communication between wells. The significance of field test data with regard to the existence or non-existence of lenticular conditions is pointed out. THE CUTLER RULE The first published article concerning the engineering aspects of the well spacing problem to receive wide attention was the work of W. W. Cutler' of the U. S. Bureau of Mines, published in 1924. In a study of decline curves from a large *The expression "well density" as utilized herein refers to the number of acres attributed to each well in a uniform well pattern, and is expressed in acres per well. The term "well spacing" Is utilized to denote the average distance between adjacent wells in a uniform well pattern. †Although the Cutler rule is treated critically in this discussion the authors intend no personal criticism of W. W. Cutler or of his hark The currently accepted concepts of reservoir mechanics were no": existent at the time of Cutler's work, as were even the moat basic tools (such as the bottom hole pressure bomb) for observing reservoir behavior.

Jan 1, 1950

By C. S. Yust, J. W. Smith, J. R. Walsh, R. E. Simpson

This paper presents the results of a complete reservoir studv designed to determine a sound economic program for the conservation of oil and gas in the Pickton field, Hopkins County, Texas. The Pickton field produces from the Bacon Lime with all indications of the study being that production is predominately by dissolved-gas drive. Calculations of the total ultimate recovery to be expected under primary operations indicated only 16.7 per cent of the oil originally in place would be recovered. This unusually low recovery is due to the type of drive operating and the extremely high dissolved gas-oil ratio and shrinkage. Results are presented for six plans of returning gas to the reservoir, evaluated to determine (1) comparative recoveries and economics of (a) returning gas at a constant rate by supplementing Pickton gas with extraneous gas during the early portion of the operation, and (b) conventional gas-return operations without using extraneous gas, and (2) the optimum size of compressor plant for each type of pressure maintenance. The over-all economic program considers, for either type pressure maintenance operation. a gasoline plant to process the unusually rich casinghead gas. Since pressure maintenance will disturb equities, pooling of royalties is in the case of Pickton a prerequisite to conservation of oil by this type of operation, both from an economic and legal standpoint. In the event pooling of royalties cannot be achieved, the study considers a gasoline plant to operate under a modified primary production operation which will make the conservation of gas possible. INTRODUCTION The Pickton field, located in Hopkins County, Texas. was discovered in November, 1944. by the completion of Humble's C. D. Nichols 1, in the Bacon lime of the Lower Glen Rose formation, through perforations from 7,888 to 7.896 feet. The well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cubic feet per barrel. Subsurface samples of the reservoir fluid obtained soon after completion of the discovery well showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Calculations of the future behavior of the Pickton reservoir indicated that ultimate oil recovery by primary operations would be 3,269,000 barrels, representing only 16.7 per cent of the oil in place (19,577,000 stock-tank barrels), and that recovery could be substantially increased by returning the produced gas. The cumulative production of 1,382,694 barrels on November 1: 1947, amounted to 42.3 per cent of the estimated ultimate oil recovery from primary operations. The purpose of this study is to determine and evaluate the optimum program for conservation of oil and gas in the Pick-ton field, including the desirability of conducting gas-return operations and of installing a gasoline plant. LOCATION AND DESCRIPTION Pickton Field, The Pickton field, as shown in Fig. 1, is located in southwest Hopkins County, Texas, 12.5 miles southwest of the New Hope field, 2.7 miles northeast of the Coke field, 16 miles southwest of Sulphur Springs, and 8 miles northwest of Winnsboro, Texas.

Jan 1, 1949

By C. S. Yust, J. W. Smith, J. R. Walsh, R. E. Simpson

This paper presents the results of a complete reservoir studv designed to determine a sound economic program for the conservation of oil and gas in the Pickton field, Hopkins County, Texas. The Pickton field produces from the Bacon Lime with all indications of the study being that production is predominately by dissolved-gas drive. Calculations of the total ultimate recovery to be expected under primary operations indicated only 16.7 per cent of the oil originally in place would be recovered. This unusually low recovery is due to the type of drive operating and the extremely high dissolved gas-oil ratio and shrinkage. Results are presented for six plans of returning gas to the reservoir, evaluated to determine (1) comparative recoveries and economics of (a) returning gas at a constant rate by supplementing Pickton gas with extraneous gas during the early portion of the operation, and (b) conventional gas-return operations without using extraneous gas, and (2) the optimum size of compressor plant for each type of pressure maintenance. The over-all economic program considers, for either type pressure maintenance operation. a gasoline plant to process the unusually rich casinghead gas. Since pressure maintenance will disturb equities, pooling of royalties is in the case of Pickton a prerequisite to conservation of oil by this type of operation, both from an economic and legal standpoint. In the event pooling of royalties cannot be achieved, the study considers a gasoline plant to operate under a modified primary production operation which will make the conservation of gas possible. INTRODUCTION The Pickton field, located in Hopkins County, Texas. was discovered in November, 1944. by the completion of Humble's C. D. Nichols 1, in the Bacon lime of the Lower Glen Rose formation, through perforations from 7,888 to 7.896 feet. The well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cubic feet per barrel. Subsurface samples of the reservoir fluid obtained soon after completion of the discovery well showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Calculations of the future behavior of the Pickton reservoir indicated that ultimate oil recovery by primary operations would be 3,269,000 barrels, representing only 16.7 per cent of the oil in place (19,577,000 stock-tank barrels), and that recovery could be substantially increased by returning the produced gas. The cumulative production of 1,382,694 barrels on November 1: 1947, amounted to 42.3 per cent of the estimated ultimate oil recovery from primary operations. The purpose of this study is to determine and evaluate the optimum program for conservation of oil and gas in the Pick-ton field, including the desirability of conducting gas-return operations and of installing a gasoline plant. LOCATION AND DESCRIPTION Pickton Field, The Pickton field, as shown in Fig. 1, is located in southwest Hopkins County, Texas, 12.5 miles southwest of the New Hope field, 2.7 miles northeast of the Coke field, 16 miles southwest of Sulphur Springs, and 8 miles northwest of Winnsboro, Texas.

Jan 1, 1949

By E. A. Swedenborg

The unit agreement for the Wertz Dome field, Wyoming, was approved by the Acting Secretary of the United States Department of the Interior on November 4, 1937, effective on December 1, 1937. The stated objectives of the agreement are to conserve and put to beneficial use all oil and gas produced; to make possible a uniform withdrawal of oil and gas in order to maintain equalized reservoir pressures; to provide for an orderly determination of the structural features of the productive horizons; and to permit the injection of gas for pressure maintenance. The purpose of this paper is to show by a discussion of the problems involved and the engineering practices employed by the unit operator, how well the objectives of the unit agreement have been accomplished in the development and production of oil and gas from the field. HISTORY AND DEVELOPMENT The Wertz Dome oil and gas field is located 88 miles southwest of Casper and 38 miles north and westerly from Rawlins, Wyoming. It is served by a state secondary oiled road connecting with U. S. Highway No. 220 at Lamont, a distance of 3 miles from the field. It has been a producing field for 27 years, first as an important producer of gas and more recently of oil. The Producers and Refiners Corp. completed Well No. 1, NE1/4SW1/4 sec. 7, T. 26 N., R. 89 W., the first productive well in the field, in September. 1921, in the Muddy sandstone of Upper Cretaceous age, at a depth of 3435 feet for an initial production of 42,000,000 cu. ft. of gas per day. In 1922 pipe lines were laid to Casper, Wyoming, for supplying fuel to the Standard of Indiana refinery, 'the adjoining town of Mills. and the Producers and Refiners Corp. pump station No. 6 in Mills; and to Parco (now Sinclair), Wyoming, for supplying that refinery with fuel. The gasoline content of the gas was extracted in an absorption plant located near the town of Mills. No compressors were used as the line pressure was sufficiently high to flow the gas through the absorbers. As high as 30,000,000 cu. ft. of gas per day were treated in the plant extracting 6000 gallons of gasoline. In September 1937, the pipe line was discontinued and the plant was dismantled at which time 61,000,000,000 cu. ft. of gas had been produced from the seven Muddy, Cloverly, and Sundance gas wells drilled in the field. Of this volume of gas 800,000,000 cu. ft. were produced from the Frontier formation, 34,200,000,000 cu. ft. from the Muddy sandstone, 24,000,000,000 cu. ft. from the Cloverly, locally called Dakota, and 2,000,000,000 cu. ft. from the Sundance formation. The pipe line was discontinued because of the near depletion of the gas reserves in Wertz and nearby fields, and hecause of the local field requirements demanding the retention of the remaining gas reserves. In December 1936, the Sinclair Wyoming Oil Co. completed Well No. 10, SE1/4NW1/4 sec. 7. T. 26 N., R. 89 W., at a depth of 5886 feet. as the first Tensleep sand producer with an intial of 1700 barrels of oil per day. The well was originally drilled only 14 feet into the sand and in August 1939 was deepened to a depth of 6161 feet, 289 feet in the sand, and the daily produe tion increased to 8350 barrels of oil. In February 1948 Well No. 22, SE1/4 SE1/4 sec. 1. T. 26 N., R. 90 W., was deepened from the Tensleep to the Basal Amsden sand and completed at a depth of 6635 feet for an intial of 600 barrels of oil per day in the Basal Amsden. In April 1948, Well No. 2. SW1/4 NE1/4 sec. 1, T. 26 N., R. 90 W.. was deepened from the Tensleep to the Madison limestone and was completed at a depth of 7193 feet for an intial of 1145 barrels of oil per day in the Madison. Well No. 26, SE1/4SE1/4 sec. 1, T. 26 N.. R. 90 W., was deepened from the Ten-sleep to the Cambrian and in October 1948 it was completed in the Cambrian for an intial of 277 barrels of oil per day. GEOLOGY AND PRODUCTIVE ACREAGE The surface is Steele shale of Upper Cretaceous age, covered in part by gravel beds. The topography of the field is that of a rolling hill with a steep draw or gulch along the northern edge of the field. The Steele shale lies conformably on the lower formations as

Jan 1, 1949

By E. A. Swedenborg

The unit agreement for the Wertz Dome field, Wyoming, was approved by the Acting Secretary of the United States Department of the Interior on November 4, 1937, effective on December 1, 1937. The stated objectives of the agreement are to conserve and put to beneficial use all oil and gas produced; to make possible a uniform withdrawal of oil and gas in order to maintain equalized reservoir pressures; to provide for an orderly determination of the structural features of the productive horizons; and to permit the injection of gas for pressure maintenance. The purpose of this paper is to show by a discussion of the problems involved and the engineering practices employed by the unit operator, how well the objectives of the unit agreement have been accomplished in the development and production of oil and gas from the field. HISTORY AND DEVELOPMENT The Wertz Dome oil and gas field is located 88 miles southwest of Casper and 38 miles north and westerly from Rawlins, Wyoming. It is served by a state secondary oiled road connecting with U. S. Highway No. 220 at Lamont, a distance of 3 miles from the field. It has been a producing field for 27 years, first as an important producer of gas and more recently of oil. The Producers and Refiners Corp. completed Well No. 1, NE1/4SW1/4 sec. 7, T. 26 N., R. 89 W., the first productive well in the field, in September. 1921, in the Muddy sandstone of Upper Cretaceous age, at a depth of 3435 feet for an initial production of 42,000,000 cu. ft. of gas per day. In 1922 pipe lines were laid to Casper, Wyoming, for supplying fuel to the Standard of Indiana refinery, 'the adjoining town of Mills. and the Producers and Refiners Corp. pump station No. 6 in Mills; and to Parco (now Sinclair), Wyoming, for supplying that refinery with fuel. The gasoline content of the gas was extracted in an absorption plant located near the town of Mills. No compressors were used as the line pressure was sufficiently high to flow the gas through the absorbers. As high as 30,000,000 cu. ft. of gas per day were treated in the plant extracting 6000 gallons of gasoline. In September 1937, the pipe line was discontinued and the plant was dismantled at which time 61,000,000,000 cu. ft. of gas had been produced from the seven Muddy, Cloverly, and Sundance gas wells drilled in the field. Of this volume of gas 800,000,000 cu. ft. were produced from the Frontier formation, 34,200,000,000 cu. ft. from the Muddy sandstone, 24,000,000,000 cu. ft. from the Cloverly, locally called Dakota, and 2,000,000,000 cu. ft. from the Sundance formation. The pipe line was discontinued because of the near depletion of the gas reserves in Wertz and nearby fields, and hecause of the local field requirements demanding the retention of the remaining gas reserves. In December 1936, the Sinclair Wyoming Oil Co. completed Well No. 10, SE1/4NW1/4 sec. 7. T. 26 N., R. 89 W., at a depth of 5886 feet. as the first Tensleep sand producer with an intial of 1700 barrels of oil per day. The well was originally drilled only 14 feet into the sand and in August 1939 was deepened to a depth of 6161 feet, 289 feet in the sand, and the daily produe tion increased to 8350 barrels of oil. In February 1948 Well No. 22, SE1/4 SE1/4 sec. 1. T. 26 N., R. 90 W., was deepened from the Tensleep to the Basal Amsden sand and completed at a depth of 6635 feet for an intial of 600 barrels of oil per day in the Basal Amsden. In April 1948, Well No. 2. SW1/4 NE1/4 sec. 1, T. 26 N., R. 90 W.. was deepened from the Tensleep to the Madison limestone and was completed at a depth of 7193 feet for an intial of 1145 barrels of oil per day in the Madison. Well No. 26, SE1/4SE1/4 sec. 1, T. 26 N.. R. 90 W., was deepened from the Ten-sleep to the Cambrian and in October 1948 it was completed in the Cambrian for an intial of 277 barrels of oil per day. GEOLOGY AND PRODUCTIVE ACREAGE The surface is Steele shale of Upper Cretaceous age, covered in part by gravel beds. The topography of the field is that of a rolling hill with a steep draw or gulch along the northern edge of the field. The Steele shale lies conformably on the lower formations as

Jan 1, 1949

By W. Tempelaar Lietz

The Ten Section oil field is located in the San Joaquin Valley in Kern County, California. about 12 miles southwest of Bakersfield in Township 30 South, Ranges 25 and 26 East. The accumulation is in a low relief anticlinal dome and has a productive area of approximately 2,200 acres. Discovered in 1936 as a result of seismic work, it was the first field on the floor of the Valley to obtain production. It had a small primary gas cap, and since its inception has been produced by depletion with controlled withdrawal from the gas cap to minimize blowthrough. STRUCTURE AND STRATIGRAPHY The Ten Section structure is an elongated anticlinal dome with flank dips of only about 7 degrees. A map of the field, now fully developed, and a composite log are shown in Figs. 1 and 2. Contours shown on the map are on the top of the first zone, or Marker XA as indicated on the composite log. As shown, the field has a productive closure of only some 350 feet, and there apparently is no faulting in the reservoir. The productive measures in Ten Section are of Upper Miocene age and are known as the Stevens sand. They contain thin, irregular shale or siltstone streaks which vary considerably in stratigraphic position and thickness and apparently are rather discontinuous. As a result, individual sands and shales cannot be correlated over any appreciable area, which makes it difficult to subdivide the sand body into separate zones which are distinct throughout the field. However, there are two fairly persistent siltstone bodies that at the time of development were considered to divide the productive measures into three - zones. The first, or uppermost zone is productive over the entire field and has an average thickness of 180 feet, of which some 65 per cent is sand. It had a primary. gas cap in the crestal area with an areal extent of 930 acres. The second zone has a productive area somewhat smaller than the first zone, but it did not have any original gas cap. It has an average thickness of about 360 feet, of which 55 per cent is sand. The third zone has a very limited areal extent and a maximum productive thickness of 100 feet, of which 80 per cent is sand. Recently, a deeper oil accumulation, termed the "53" sand, was discovered, but it is not discussed in this analysis. In the first and second zones the water table was at 7,980 feet subsea, while in the third zone it was at 8,080 feet subsea. RESERVOIR CHARACTERISTICS Sand Characteristics The Stevens sand in Ten Section is hard and well consolidated, and numerous wells were cored for core analysis. Core data on four representative wells are shown, plotted beside the electric logs in Figs. 3 to 6. The average porosity is 20 per cent, with porosities ranging from 15 to 30 per cent. It is estimated, from cores taken with oil base muds, that the interstitial water content is about 40 per cent. The average weighted permeability is approximately 140, with measured permeabilities ranging from 10 to 3,000 md. As might be expected with practically no correlation of individual sand

Jan 1, 1949

By W. Tempelaar Lietz

The Ten Section oil field is located in the San Joaquin Valley in Kern County, California. about 12 miles southwest of Bakersfield in Township 30 South, Ranges 25 and 26 East. The accumulation is in a low relief anticlinal dome and has a productive area of approximately 2,200 acres. Discovered in 1936 as a result of seismic work, it was the first field on the floor of the Valley to obtain production. It had a small primary gas cap, and since its inception has been produced by depletion with controlled withdrawal from the gas cap to minimize blowthrough. STRUCTURE AND STRATIGRAPHY The Ten Section structure is an elongated anticlinal dome with flank dips of only about 7 degrees. A map of the field, now fully developed, and a composite log are shown in Figs. 1 and 2. Contours shown on the map are on the top of the first zone, or Marker XA as indicated on the composite log. As shown, the field has a productive closure of only some 350 feet, and there apparently is no faulting in the reservoir. The productive measures in Ten Section are of Upper Miocene age and are known as the Stevens sand. They contain thin, irregular shale or siltstone streaks which vary considerably in stratigraphic position and thickness and apparently are rather discontinuous. As a result, individual sands and shales cannot be correlated over any appreciable area, which makes it difficult to subdivide the sand body into separate zones which are distinct throughout the field. However, there are two fairly persistent siltstone bodies that at the time of development were considered to divide the productive measures into three - zones. The first, or uppermost zone is productive over the entire field and has an average thickness of 180 feet, of which some 65 per cent is sand. It had a primary. gas cap in the crestal area with an areal extent of 930 acres. The second zone has a productive area somewhat smaller than the first zone, but it did not have any original gas cap. It has an average thickness of about 360 feet, of which 55 per cent is sand. The third zone has a very limited areal extent and a maximum productive thickness of 100 feet, of which 80 per cent is sand. Recently, a deeper oil accumulation, termed the "53" sand, was discovered, but it is not discussed in this analysis. In the first and second zones the water table was at 7,980 feet subsea, while in the third zone it was at 8,080 feet subsea. RESERVOIR CHARACTERISTICS Sand Characteristics The Stevens sand in Ten Section is hard and well consolidated, and numerous wells were cored for core analysis. Core data on four representative wells are shown, plotted beside the electric logs in Figs. 3 to 6. The average porosity is 20 per cent, with porosities ranging from 15 to 30 per cent. It is estimated, from cores taken with oil base muds, that the interstitial water content is about 40 per cent. The average weighted permeability is approximately 140, with measured permeabilities ranging from 10 to 3,000 md. As might be expected with practically no correlation of individual sand

Jan 1, 1949

By Sam N. Dewitt, Albert S. Trube

This paper presents a discussion of the pressure maintenance operations which were begun in the New Hope Field. Franklin County. Texas. in 1944. The project has required the injection of extraneous waters at depths from 7.300 to 8.000 ft with intake well-head pressures up to 4.000 psi in three different reservoirs — the Bacon. Hill. and Pittsburg. Records of oil and water production. water injection and the GOR have been kept for each reservoir and reservoir pressures were taken at regular intervals. These data indicate that the Bacon Reservoir had no apparent water encroachment up to the time of water injection. However. the Pittsburg and Hill reservoirs had some natural water influx hut not sufficient to prevent pressures from declining below the bubble point. The Bacon and Hill reservoirs responded almost immediately to water injection. while the Pittsburg which is the least permeable. has shown good pressure response only since .August, 1948. The principle objective of the project has been to increase ultimate recovery. Success of the project to date also has resulted in reduced lifting costs. Esti- mates based on the initial water breakthrough patterns indicate that the primary objective of substantial additional recovery will he accomplished, and there is a possibility that the original estimates elf oil recovery with pres-sure maintenance will he exceeded. INTRODUCTION This pressure maintenance project was one of the earliest primary pressure maintenance programs to he attempted on a multiple zone field. There are three producing reservoirs into which water is being injected for the purpose of maintaining pressure and increasing the ultimate recovery- from each. This paper is limited in scope to al1 account of the development of the project. the pressure production relationship prior to the injection of water and the effect of water injection on the producing reservoirs. Also discussed are the nature of the injection system and the indicated results on initial water break-through in the Bacon Reservoir. FIELD CONDITIONS The New Hope Field, which is located about 12 miles northeast of Winusboro, Franklin County, Texas, is an elongated symmetrical anticline containing four known oil reservoirs. The reservoirs are of the Trinity group of the Comanchean or Lower Cretaceous period and are found in Table I. The oil productive portion of each reservoir is not present in all of the producing wells because their areas and positions vary with respect to one another. Fig. 1 shows the relative position of the four reservoirs and illusIrate? how some wells could penetrate all four, while others are restricted to three. two. or perhaps one. depending on structural location. The first three reservoirs contain undersaturated oil. The deepest. the Elledge, has a primary gas cap. Although this reservoir covers a considerable area of the field. it has a very thin section and a low order of permeability. Elledge producing wells have generally been characterized by an early increase in GOR, making it necessary to recomplete them in other reservoirs. (At present. one well is completed in the Elledge. which is still producing.) Because of the difficulties en-countered in producing oil from this reservoir. and the small quantity of oil actually present. future attempts at producing it will probably be on a salvage basis during the later life of the program. For this reason, the remainder of this report will be confined to a discussion of the Bacon, Hill and pius-burg reservoirs.

Jan 1, 1950

By W. G. Frailing, W. P. Sims

The Lakeview Pool of Kern County, California, was discovered in 1910 with the drilling of Lakeview No. 1 which blew out and produced an estimated 8,250,000 bbl of oil in 544 days of uncontrolled flow. The well has since been known as the Lakeview Gusher. Full exploitation of the pool did not take place until about 25 years later. A total of 112 producing wells were completed in the Lakeview sand through April 30, 1949. As of that date, about 30 per cent of the total wells drilled were still producing, with an average pool production rate of approximately 2000 bbl per day. The cumulative oil production was about 41 million bbl of oil, or 55.3 per cent of the tank oil originally in place. The pool is bordered on its down-structure side by a body of inactive edgewater and water production where present has been principally the result of coning. Since the depletion of the greater portion of the gas energy by the Lake-view Gusher, the pool has operated under gravity drive. Relatively high angle dips, good permeabilities and favorable fluid characteristics have made gravity drainage particularly effective. Since January, 1942, the oil recovery -has been relatively constant at about 53,000 bbl per ft drop in fluid level. Correlations between the volume of reservoir space drained and the cumulative oil produced indicate that an ultimate recovery of 63.3 per cent of the tank oil originally in place is attainable. INTRODUCTION The Lakeview Pool is an outstanding example of gravity drainage. It is one of many productive reservoirs of the Midway-Sunset Field, and is located in Kern County, approximately five miles southeast of Taft and two miles north of Maricopa, California. Its position rel- ative to surrounding pools and to the Thirty-Five anticline is shown on Fig. 1. The northern portion of the pool lies in sections 32 and 33, Township 32 South, Range 24 East, Mt. Diablo Base and Meridian, while the southern portion lies in sections 25, 26, 35 and 36, Township 12 North, Range 24 West, San Bernardino Base and Meridian. As no two sections bear the same number, they will hereafter be referred to by section number alone. The purpose of this paper is to review the performance of the Lakeview Pool in an effort to evaluate the effectiveness of gravity drive as a recovery mechanism. REGIONAL STRATIGRAPHY AND STRUCTURE The oustanding structural feature is this area is the Thirty-Five anticline, the axis of which plunges South 75" East through the center of Section 35. As shown on Fig. 2, the following zones are oil and gas bearing in the Thirty-Five anticline area: Pleistocene Basal Tulare Tar Sands Pliocene San Joaquin Mya Sands Top Oil or Scalez Zone Etchegoin Kinsey Sand Wilhelm Zone Gusher Sand Calitroleum Sand Miocene Reef Ridge Lakeview Sand Sub-Lakeview Miocene Sands Monarch Sands or fractured shale equivalent Maricopa Webster Sand or fractured shale equivalent Fractured Shale-Uvigerina Zone C Obispo Sand and fractured shale equivalent Pacific Shale Zone The productive interval of the Lakeview Pool is limited to Upper Miocene and Lower Pliocene deposition. In this general area, the most prevalent type of accumulation results from stratigraphic traps or permeability pinchouts. As is the case of the Lakeview Pool, strati-graphic traps resulting from angular unconformities are present. The structure within the Miocene does not parallel that of the Etchegoin (Pliocene), as the Miocene beds were folded, and in places faulted, and subjected to erosion prior to Pliocene deposition. The Lakeview horizon consists of truncated sands which occur on the northeast flank of the Thirty-Five anticline. The direction of strike is west and northwesterly through sections 25 and 36 and continues northwesterly through sections 26 and 33, to the approximate center of section 32. At this point the strike swings to the northeast and the horizon re-enters section 33. in the northwest corner. The change in strike in section 32 affords synclinal accumulation at that point. The Lake-view sand is truncated updip by the Etchegoin overlap. To the southeast, the sand shales out, while to the northwest, the productive interval appears to be limited by a combination of stratigraphic pinchout and permeability barrier. Structurally, the Lakeview reservoir presents three areas of interest, as shown on Fig. 3. Area I in section 32 is a region in which a productive Sub-Lakeview Miocene sand is present. It occurs from 10 feet to 30 feet below the base of the Lakeview sand and attains a maximum thickness of 25 feet in Well No. 21, section 32. The producing characteristics of the Sub-Lakeview Miocene sand differ radically from those of the Lakeview sand. Water production at high structural locations and abnormally high fluid levels indicate that there was no communication with the Lakeview sand. Wells in Area I penetrated this sand and produced it in conjunction with the Lakeview sand. In Area 11, the Lakeview sand is a

Jan 1, 1950

By John W. Crutchfield, Emil F. Bowers

This paper presents the initial results of a pressure maintenance by water return project in the Lower Pawelek reservoir of the Falls City Field, Karnes County, Southwest Texas. Production is from the Lower Wilcox section at an average depth of 6,030 ft on the downthrown side of a "down to the coast" fault. Of particular interest is that the reservoir oil is high gravity and low viscosity but far undersaturated with gas at the original reservoir pressure and temperature. The early pressure and production history indicated only a partial or limited water drive, and this fact, coupled with the characteristics of the reservoir fluid and artificial lifting problem.. made advisable the water injection program to maintain reservoir pressure. The paper includes a description of the reservoir and reservoir fluids, the pressure and production history, a description of the water injection facilities, and the results of reservoir calculations involving Hurst's unsteady state flow and the material balance equations for calculation of water influx and prediction of the pressure-production relationship at various rates of withdrawal. The reservoir calculations and initial field results indicate that reservoir pressures in excess of 85 per cent of original pressure can be maintained by control of water injection even at very high rates of production. INTRODUCTION The purpose of this paper is to report the initial results of a pressure maintenance by water return program in the Lower Pawelek reservoir, Falls City Field, Karnes County. Texas, and to calculate an empirical relationship between pressure and production in this limited or partial water drive reservoir. Location The Falls City Field (Fig. 1) is located two miles north of the town of Falls City in Karnes County, Texas, and is approximately 50 miles south-southeast of San Antonio on U. S. Highway 181. Discovery and Development The initial block of leases was taken after a surface geological survey identified a major east-west fault and closure on the south or downthrown section. The discovery well, Southern Minerals Corporation's Joe F. Bartosch 1; was completed at 4,650 ft in the Lower Bartosch sand in December, 1944. Drilling was continuous until December, 1946, and resulted in the discovery of 12 oil reservoirs between 4,600 and 6,050 ft in the Middle and Lower Wilcox formations. These are shown on the cross-section (Fig. 2). As of the current date there are 64 oil wells completed as follows: Southern Gulfshore Magnolia Minerals Oil Petroleum Reservoir Corp. Co. Corp. Total Upper Bartosch 0 0 0 0 Lower Bartosch 16 0 0 16 Shulze 7 0 1 8 Upper Faires 2 0 0 2 Lower Faires 4 0 0 4 Upper Moczygemba 0 0 0 0 Lower Moczygemha 2 0 0 2 Olinick 2 0 0 2 Upper Martinez 0 0 0 0 Lower Martinez 5 0 0 5 Upper Pawelek 0 0 1 Lower Pawelek 27 1 3 31 Total 65 2 4 71

Jan 1, 1950

By P. P. Reichert, L. S. Gournay, N. T. Burdine

An investigation of equivalent pore entry radii in typical samples of petroleum reservoir rock and the pore volume associated with each value of pore entry radius has been made. Theoretical discussions together with experimental procedures for obtaining pore entry radii and the distribution of pore volume with pore entry radii are presented. Experimental results on a number of core samples, along with typical distribution curves, are shown. Data on the per cent of the pore volume filled by mercury at a pressure of 1500 psi are included. The results of re-runs of samples, made possible by regenerative apparatus, show the repeatability of the data and indicate the amount of physical change in the samples by mercury penetration. Theoretical equations for calculating permeability from pore size distribution data were derived and the results of such calculations are compared with measured gas permeability data. The effect of the shape, surface area, and weight of the sample on the pore size distribution of reservoir rocks was investigated experimentally. Mercury capillary pressure curves are compared with those obtained by the porous diaphragm method using pas to displace water. Standard core analysis techniques, in general, lead to quantities which are statistical averages of the varying properties of the samples under examination. Although such statistical information has real value in predicting the gross performance of porous bodies. it fails to provide fundamental information concerning the properties of the porous medium itself or any processes which may be occurring in it. For example, a gas permeability measurement on a core sample is an indirect way of determining an average pore radius for that particular sample. Since there are many combinations of pore radii that will give the same radius. and, hence, the same permeability, no information is obtained on the pore size distribution. Furthermore, similar values in permeability do not imply similarity in other properties of a porous medium. For instance, it is possible to have two core samples with identical permeability which would have different residual oil contents at the end of an air-oil drive, or even different amounts of interstitial water. It has been recognized for some time by the petroleum industry that a determination of pore size distribution for porous reservoir rocks offered promise of increased understanding of fundamental flow processes in the porous matrix. and therefore of petroleum res- ervoir performance in general. There have recently been published several methods for determination of pore size distribution in porous materials. A report is given here of the modifications in equipment and technique required to adapt one of these methods to measurements on petroleum reservoir core samples. Although only a few correlations or applications of the method are available for presentation at this time, the technique is brought to the attention of the industry so that the opinions and experience of others with this or similar techniques may be exchanged. It seems possible that the method will have wide application in the future. METHOD There are three general methods which may be employed to measure the pore size distribution in naturally occurring rock formations. One method1 is based on experimentally determined adsorption isotherms for calculating the surface area of the porous medium. Knowing the surface area and the pore volume, a rough estimate of the pore radius can be made. Since this method depends on the thickness and uniformity of the adsorbed layer, the validity of the results would be highly questionable. A second method utilizes capillary pressure data obtained by static dis-

Jan 1, 1950