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Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

Jan 1, 1943

By H. F. Winham

The history, development, subsurface geology, production, economics and estimated reserves are discussed in this paper. The Magnolia structure is an anticline with a known maximum structural relief at 372 ft., and the areal extent of the producing acreage is 4494 acres. Production is obtained from the Smack-over oölitic lime and 116 successful wells have been drilled. The field, which was developed on 40-acre spacing, has been under strict control. It is believed to be producing with a strong water drive, To date it has produced more than eighteen million barrels and the estimate of ultimate recovery is 220 million barrels. Early History The Magnolia field is in colurnbia County, Arkansas, T. 17 s., R. 19 and 20 W. Various geologists had long been interested in this general area, and as early as 1921, John F. Magale was able to define a surface structure. The first wildcat, one of the first in Columbia County, was drilled in 1923 by Mid-States Oil Co., in sec. 10, T. 17 S., R. 20 W. This well was about 11/2 miles northwest of the Kerlyn oil Company's discovery well and was based on surface geological work done by Jewel and Dobie. Subsequently, several shallow wells that were not carried below the Upper Cretaceous beds were drilled in the immediate area of the discovery well, but none of them contained any commercial showings of oil Or gas. In the latter part of 1935, Elam and Magale (or Southwood) Garrett NO. I was located in sec. 13, T. 17 S., R. 20 W., 3/4 mile east of the discovery well. It was drilled to a total depth of 4018 ft. in the lowermost Glen Rose beds but failed to obtain any showings of oil or gas. Interest had been stimulated in this general area, however, by the discovery of several oil fields, mainly Glen Rose oil production in the Rodessa field in Louisiana in 1935, Smackover lime productioil in Snow Hill in May 1936, production from the Cotton Valley formation in Schuler in 1937, and Smackover lime production from the Buckner field in November 1937. With this background and subsequent seismic work, which was carried on partly because the old shallow wells drilled in the township had shown evidence of closure in the Upper Cretaceous beds, the discovery well, Kerlyn Oil Company's Barnett No. I, Sec. 14, T. 17 S., R. 20 W., was originally projected to a total depth of 6300 ft., to test the equivalents of the Morgan sands of the Cotton Valley series, then producing at Schuler. The well was carried to a depth of 6325 It. and tested the objective beds without finding commercial production. In the meantime, however, one well had found production in the Jones sand and another in the Smaclrover lime at Schuler. Kerlyn immediately made arrangements to deepen the Barnett well to the Smackover lime. The top of the Smackover lime was encountered at 7618 ft. and the well

Jan 1, 1943

By C. P. Parsons

Caliper logging is a practice of measuring the variations in the diameter of the open hole in a well. This information is useful for many purposes, among which are: Determining the volumetric capacity of the portion of open hole to be cemented; the amount of gravel to be used for gravel-packing a well; the size and location of seat for a packer to be placed in a well; studying the effects of nitroglycerin shots; studying the effects of acidizing; studying the cause of drill-pipe failures; studying drilling technique; geological correlations. This is a new practice in oil fields and is eliminating considerable guesswork. Introduction Caliper logging of the open hole in oil wells, recently introduced and now showing initial results in many sections of the country, is providing information that is filling a long-felt need in oil-well cementing and in numerous other oil-field practices. Briefly, it measures the variations in diameter, of the open hole in a well. This direct physical measurement of the strati-graphic profile has considerable value for subsurface interpretations by the geologist, engineer, driller and others charged with the responsibility of properly completing and repairing oil and gas wells. The caliper shown in Fig. I is run into a well in closed position. The four arms are released when logging is to start. These arms are independent of each other. As the calipers are pulled upward through the open hole, the arms are like nimble fingers feeling the changing profile of the hole. This mechanical action is in turn converted into an electrical circuit, which is connected to a recording mechanism at the surface. a. Lowered into well in closed position. b. Arms released. Readings are made while caliper travels upward. Direct recording is made at surface, in inches. The recording of the diameter of the hole is directly in inches.

Jan 1, 1943

By Charles C. Rodd

Prior to 1938, proration procedure in Kansas required the physical testing of wells in order to set up a basis for allocating production. Subsequently the use of liquid-level data and bottom-hole pressure data was authorized on certain types of wells as a basis for calculating well capacities, thereby permitting wells to be tested at low rates and with small volumes of production. This paper gives some attention to the equipment used for obtaining liquid-level data but in general it is devoted to the theoretical and physical factors involved in well testing by drawdown methods. These tests are divided into two classifications: (I) liquid-level data used directly to calculate capacities, and (2) liquid-level data and liquid-level measuring equipment used in connection with other data to determine bottom-hole pressure. Equations and calculations for both types are shown. Well capacities calculated from fill-up data have not been used generally but offer a simple means of testing some wells. Theoretical factors and calculations for such tests are shown. In the state of Kansas, proration laws required that the "ability of a well to produce" be given consideration in state allocation orders and for many years this was the only factor used in prorating the allowed oil. The "ability of a well to produce", was the quantity of oil that could be obtained from a well in a prescribed period, usually 24 hr. Early in the history of State-regulated proration, Kansas operators realized that, unless some restriction were placed upon equip- ment, the competition between producers to obtain large well "potentials" might result in a race to install the largest pumping equipment. Consequently, restrictions were placed upon the size of tubing and length of pump stroke that could be used in pumping wells during potential tests. Later, restrictions were placed also upon the size of tubing and chokes that could be used in flowing walls. Despite the restriction setup, better pumping equipment was designed and installed, pumps were improved, and various devices were invoked to obtain high rates of production for short periods of time. By 1937 pumping cycles of forty to forty-five 54-in. strokes per minute were not uncommon, and numerous wells had produced at the rate of 3500 bbl. per day for short periods. Such production was far beyond any rate that could be long sustained. Equipment necessary to take "potentials" was several times larger than that needed for normal producing purposes, and repairs and replacements required by the high pumping speeds were excessive. Also, many operators suspected that the high rates of production main tained during '"potential" tests were conducivc to early water encroachment. By 1938 large-scale physical testing of wells in Kansas ended, the use of the bottom-hole pressure gauge had become common, engineers and operators were becoming familiar with the term ''productivity index," and bottom-hole pressure was being used as a factor in allocation in many areas. There were many drawbacks, however, to large-scale use of

Jan 1, 1943

By William Hurst

This is a presentation of the diffusivity theory for the calculation of the water drive on an oil reservoir in which the history of reservoir pressure with time are the essential parameters for the determination of the rate and cumulative water encroachment into a field. The main body of the paper is essentially the application of the principles underlined here to actual field data. It consists of the work plots of the radial-flow case, and includes a discussion of an illustrated problem for which the water-drive calculations are treated in conjunction with the volumetric-balance equation. The appendix is a mathematical treatment of the linear, radial, and spherical cases of water influx into a reservoir. Introduction The evaluation of oil reserves and the prediction of pressure behavior with different rates of production are related to the volumetric balance of the fluids entering and leaving the space occupied by the oil and gas originally present in the formation; that is to say, important information can be gleaned from a volumetric study of the oil, gas, and water produced from a formation as it affects the extent of change in volume of oil zone, the gas cap, and the amount of water influx from the adjoining water sands. It is not the purpose of this paper to enter into a discussion of the equation of volumetric balance, in which such pertinent information as subsurface sampling and the measurement of reservoir pressures play a predominant part, as this has been discussed in detail by others.1,2 However, there is an inherent difficulty that has limited the general application of this equation to a study of oil reservoirs; that is, the insufficient knowledge of the analytics for expressing the water drive on a field as a function of reservoir pressure. This to a large degree has been overcome and it is the purpose of this paper to present this theory in such form as to be applicable for reservoir calculations. Water Drive If the amount of oil originally in place and the gas space are known, it is a relatively simple matter to determine, by the volumetric equation, the cumulative water influx into a reservoir from the adjoining water sands. Often, however, the oil reserve as well as water influx must be 'determined, and in order to be able to make this calculation it is essential to assign a mathematical relationship for the varying water term that is compatible with conditions known to exist in the formation and gives an accuracy acceptable for engineering calculations. Various equations have been employed empirically by different investigators in making reservoir studies of water drive. One form used by Schilthuis2 expresses the rate of water influx into a reservoir at any time as proportional to the pressure

Jan 1, 1943

By W. A. Bruce

This paper presents the essentials of a mathematical method of studying the pressure behavior of an oil reservoir as the fluids are withdrawn. Methods are shown Whereby the behavior of a reservoir can be used to predict the future relationship between withdrawals and pressure. The oil reservoir is considered as a small part of a large porous continuum, which contains for the most part water. The expansion of this water resulting from a decrease of pressure in the oil zone causes a movement of water that is an important factor in the relationship between fluid withdrawals and reservoir pressure. Examples are given to illustrate the methods of pressure prediction for a circular reservoir containing undersaturated crude, the pressure distribution over a field that has a uniform production rate, the effect of a fault line near a field, the mutual interference of near-by fields, and the perturbing influence of a gas cap. Applications of the analysis to well-spacing problems are shown. Introduction The pressure-prediction methods to be described here are based upon the conception of an oil pool as a small part of a large porous continuum, containing for the most part water. The formation containing this water may be thought of as extending over an area of many square miles and having one or more small bodies of oil or gas trapped in high spots or reservoirs. It will be treated as having the genera1 aspect of a thin, flat sheet with an over-all tilt to the horizontal and with numerous small high spots, tight zones, and irregularities This porous continuum will be treated as being much more extensive than the oil or gas zones, but will be recognized as terminating at such large boundaries as a general fault, outcrop, unconformity, or pinch-out. Throughout the greater part of this limited porous continuum it is likely that there is a hydraulic connection. If this is true, the removal of fluid in one place will cause a disturbance that eventually will travel to all parts of the continuum. This picture has led to the recognition of water as the major fluid in the porous continuum and in many cases the expansive nature of this water as the main driving force producing the oil. The next step is the solution of the general problem of compressible liquid behavior in porous media. The works of Hurst I and Muskat2 introduced the idea of using heat-flow mathematics to consider the problem of compressible liquid flow in a porous medium. Before their reports, it had been thought sufficient to use the incompressible fluid-flow work of S1ichter.3 Law Muskat4 pointed out in detail how far the incompressible-fluirl assumption, deviated from fact even for water, of which the compressibility is about 3 X 10-6 volumes per unit volume per pound per square inch. He showed that this deviation increased with increases of distance. For example, the incompressible-fluid formula might show good agreement with the

Jan 1, 1943

By R. E. Old

Through the use of pressure and production records, formation properties and bottom-hole sample data, the performance of an oil reservoir may be studied analytically to define and evaluate the natural forces acting on and within the reservoir. Use is made of material-halance methods and the equations for natural water encroachment. to estimate reserves. Methods for calculation of pressures are given. A study of the Jones sand, Schuler field, Arkansas, has been made and is given here to illustrate the value of the methods discussed. Introduction With the decreasing rate of discovery of new oil reserves, attention is necessarily focused on the efficient development, evaluation, and production of existing reserves. From the nation's viewpoint, the necessity of conserving resources is obvious. From the operator's viewpoint, the problem is to lengthen the period of profitable operation, in an attempt to increase the return on his investment. To do this the operator must take advantage of the natural forces acting on and within the reservoir. Natural water encroachment, the nemesis of profitable operation in the past, can be and is being harnessed to produce a greater oil recovery during the stage of flowing production. Proper evaluation of water encroachment rates and a fuller under- standing of reservoir behavior dictate the appropriate production procedures. Complacency in hit and miss production is obsolete. Oil production must and will approach the efficiency of other businesses, such as manufacturing. A manufacturer will not place an article on the market until he has fully investigated the processes involved, additional investment in equipment, costs of production, and expected profits. These may be modified by actual experience at a later date, but at least he begins with an idea of expected return. It is just as logical that an oil operator should investigate these same factors during the development and the early period of production of an oil reserve. The complexity of the problems existing in oil reservoirs should not be underestimated. Conversely, they should not be regarded as insoluble. Many completely defy solution, but there are others that can be solved completely or attacked intelligently to yield approximate results. The petroleum engineer has many tools, both figuratively and literally, at his disposal. Physical data such as core analyses, electrical logs, bottom-hole sample analyses, and bottom-hole pressures are accumulated extensively. Advances in the analytics of fluid flow have kept pace with the advances in measurement of physical data. It is the purpose of this paper to show how some of these records may be analyzed to define certain phases of reservoir behavior.

Jan 1, 1943

By J. M. Bugbee

The engineer and the conservationist agree that effective water drive is the desirable reservoir production mechanism. Water drive may result either from the expansion of edge water, the reservoir water bordering an oil pool, or from the artesian flow of edge water from the outcrop. Thus, the extent of the reservoir has an important bearing upon both the rate and the ultimate quantity of water influx to an oil pool. Lens-type reservoirs are generally recognizable, but the complete structure of the more important domal types, having possible limitations from crestal and synclinal faulting, is not well understood. The delineation from cores, electrical logs and exploitation phenomena of the crestal portions of reservoirs is increasingly exact. This paper suggests that inference from these factual pictures, combined with the scattered well and geophysical data of the synclines and with consideration of the dynamics of structural formation, may be applied to solving the complete geologic structure. Since faulting on the domes and in the synclines may effectively seal and thus limit the size of a reservoir and bar additional water influx, consideration of geologic structure and its possible effects is essential to complete analysis and prediction of reservoir performance. Introduction Implicit in reservoir studies is the fact that the oil must be displaced from the reservoir rock by some other fluid, either gas or water, and this understanding yields the terms descriptive of the major reservoir production mechanisms, gas expansion and water drive' Three recent papers1-2-3 make clear the economic and conservation preeminence of Water drive as a production mechanism; in fact, the title of the latest of these is " Production under Effective Water Drive as a Standard for Conservation Practice." There appears to be an assumption at times among analysts that the effectiveness of a water drive is solely dependent on the rate of oil production; that is, if water drive appears to be insufficient or lacking, a lower oil-recovery rate would increase or reveal it. This assumption might result from the fact that the analysis has been wholly developed during the period of production curtailment; that is, since 1929. The writer takes it that the recurrent phrase in De Golyer's paper,3 "some degree of water drive," is related to this assumption. In California, an extraordinary phrase, "inactive water drive," is rather common and the connotation of uncertainty regarding our knowledge of reservoir performance is evident. Wyckoff2 speaks of the type of reservoir and performance as follows: "In general, reservoirs may be any one or a combination of domal, faulted, lenticular, or stratigraphic traps. Insofar as the dynamic performance of such reservoirs is concerned, the particular type merely determines whether regional flow is symmetrical as in a uniformly developed domal or lenticular type, or one-sided as in many stratigraphic or faulted traps." But whether the flow is

Jan 1, 1943

By W. A. Bruce

This paper covers the theory and present state of development of an apparatus for the nonmathematical analysis of complex problems of reservoir and well behavior. At the present stage of development of this apparatus, it is capable of solving the water-drive problem of any reservoir performance for which a mathematical solution has been presented in the literature, either on the basis of steady or unsteady-state flow analysis. The theory is presented for the extension of the scope of this analyzer along the lines of the present development. The resulting apparatus should be able to solve reservoir-performance problems previously thought too difficult for practical solution by mathematical means. As an illustration of its operation and present scope, the analysis of a reservoir problem and synthesis of expected performance is presented. Introduction In this method† of analyzing problems of petroleum-reservoir and well behavior, the porous continuum of the reservoir is assumed to be divided into small blocks, or units. Each block is assumed to be small enough so that for a material balance on the fluids in the block an average pressure for the block can be used. In analyzing reservoir behavior from this point of view by mathematical means, a set of simultaneous difference equations would be obtained (two for each block), which must be solved or combined into a partial differential equation. In the method to be described here, instead of solving these sets of equations analytically, electrical units are constructed, which will behave in respect to the flow of electricity exactly as the reservoir units behave under various conditions of fluid flow. The electrical units are then wired together in the same way that the reservoir units are connected naturally by virtue of their geometrical locations and shapes. Fluid-Flow Equations Consider a block in a reservoir. Assume that reservoir fluid (or fluids) is flowing in at one face and out at the opposite face, and that the block is small enough so that at all points the stream lines are within one degree of perpendicular to the face. Furthermore, assume that the pressure, pi, at the upstream face (Fig, I) is not more than one per cent greater than P2 the pressure at the downstream face. A material balance will show that the mass of fluid flowing out less the mass of fluid flowing in will equal the change in density times the fluid volume. This is expressed in the equation:

Jan 1, 1943

By R. C. Earlougher

Based on laboratory tests conducted with the use of fresh core samples as well as a considerable amount of field data obtained from numerous water floods in northeastern Oklahoma, it appears that for any given oil saturation there is a critical maximum velocity above which the oil-recovery efficiency falls off very rapidly. In effect, when a water flood is operated above this critical velocity, the injected water-oil ratio rises extremely fast, thus shortening the economic life of the flood and reducing the ultimate oil recovery. This critical velocity apparently varies considerably with the percentage of oil saturation of the sand, so that in effect the higher the oil saturation at the beginning of a flood the higher the velocity that can be used successfully. In reviewing several of the earlier floods in the Mid-Continent area, it is concluded that most of the failures were due to two things: (I) too low an oil saturation, such as 30 per cent, and (2) too high water-injection rates, Although considerably more field data are necessary to establish definite limits, it would seem that the proper field injection rate for a 330 by 330 or 440 by 440-ft. spacing varies from approximately I bbl. per foot of sand per day where the oil saturation is as low as 30 per cent up to 5 bbl per foot of sand per day when the oil saturation is as high as 45 to 50 per cent, Introduction With secondary recovery by water-flooding receiving more and more attention throughout the industry, a greater working knowledge of multiphase flow under field conditions becomes more and more necessary A great deal of research has been carried on in highly idealized laboratory conditions, from which certain trends have been indicated, but with few exceptions no direct application to field use has been reported. widely varying conclusions have been drawn from the mass of idealized laboratory experiments and often this divergence apparently was due to the neglect of connate or interstitial water. Since interstitial water is such an important factor in water-flooding operations, it then follows that any laboratory flooding experiment must necessarily take it into account; and since it is difficult to set up laboratory models to allow for interstitial water, the next best procedure is to use fresh core samples for such tests. Even this procedure has its difficulties, inasmuch as it is possible to run only one flooding test on each sample, as each sample differs somewhat in character from all other samples. However, this disadvantage can be overcome to a large degree by the use of an extremely large number of samples. The next question that arises is: "IS it possible to get uncontaminated core samples having a true oil and water saturation like that existing in the reservoir?" If the sand under consideration is still in the primary stage of production, with a normal or relatively high amount of gas still in solution in the oil, probably it is not possible to get a nonflushed core. On the other

Jan 1, 1943

By R. F. Stahl, W. A. Martin, R L. Huntington

A marked gravitational segregation of liquid has been observed to take place in a number of volumetric fields toward the later stages of their oil-producing periods. This phenomenon has been pronounced in thick, highly permeable sand formations such as those of the wilcox zone in Oklahoma City. This observation has prompted considerable research directed toward the semiquantitative determination of the equilibrium saturation distribution of oil vertically throughout a formation at final depletion. In this paper, data are also presented showing the transient distribution of liquid at different stages of the depletion period. Other experimental results show the effect of temperature on the drainage rates of water, Wilcox crude oil, and a close-cut heptane fraction. Intermittent drainage of liquid produced saturation gradients that might well be expected from the flow theories involved, Yields of the various liquids varied from 50 to 75 per cent of the original fluid content of the sand-packed (4 in. by 8 ft.) vertical tube. Introduction In certain volumetric Oil fields the performance of the reservoir during the latter part Of its producing life is governed to a large extent by the downward movement of liquid due to the force of gravity. This is especially true of formations having thick or tilting beds of uniformly high permeability, free of shale breaks. Laverett4 and Katz3 have presented original data and discussed the theory relating to the capillary and gravitational forces acting On liquids contained in a sand body. These investigators have pointed out the importance of such studies in the estimation of future reserves as well as the original fluid content of a reservoir. In this previous work, no data have been reported showing the history of saturation distributions during the drainage period. Since a knowledge Of these transients is helpful in obtaining crude Oil from such a reservoir, the authors have obtained these data during this investigation. Experimental Apparatus The drainage tests were carried out in two vertical tubes, 8 ft. high and consisting of 2-in. and 4-in. standard wrought-iron pipe, respectively. Each tube was equipped with a water jacket, which could be kept virtually isothermal ( ± 1.0ºF.). A diagrammatic sketch of the 4-in. tube and its auxiliaries is shown in Fig. 1. At 6 in. above the base of the tube, and at every foot above this point, core nipples were inserted through the water jacket. These nipples were closely fitted with steel-plug inserts during each drainage run. At the end of the run, these inserts were removed so that cores could be obtained from the sand-packed tube.

Jan 1, 1943