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By Jan Law

Problems of oil recovery are attacked from the approaches dictated by the two strikingly dissimilar complexes that comprise an oil reservoir—the fluid complex and the interstitial complex. Knowledge of the fluid complex, due to labors in the fields of fluid mechanics and physical chemistry, has far outdistanced knowledge of the interstitial characteristics of the sand complex. This paper is concerned with the latter and applies the technique of statistics to petrographic facts—namely, porosity and permeability—dealing with what might be called petrometry. Statisticians have long worked within the problem of reconstruction of a universe oi variables by means of samples that comprise a small percentage of the universe from which the samples were drawn. Core-analysis data comply with the requisite of random sampling as stipulated by theoretical statistics. A basic concept of statistics employs t.he following substitution: 1. The results of sampling are arranged as a frequency distribution. 2. The observed frequency distribution is compared with a mathematically precise distribution. 3. If a sufficiently good agreement is found between the two, the precise distribution is substituted in all subsequent operations involving characteristics of the sampled material. This mathematically precise distribution is also known as the normal curve, curve of error, the probability, the Gaussian, and the bell-shaped curve and is describable with but two figures. Further, these two figures, the arithmetic average and the standard deviation, are subject to mathematical manipulation. This paper demonstrates that, in some cases in the Dominguez field of Southern California, if sufficient core-analysis samples are taken over not too great a thickness of sediments, the resultant permeability and porosity assemblages give satisfactory agreement with ilormal curves. It is shown that the indications are strong that oil wells wherein a satisfactory agreement is found are predictable as to productivity. Since the predictions are made by employing the laws of chance that are operative within sedimentation, it follows that the mechanism by which the predictions were made is a basic concept of reservoir mechanics. Therefore, tentative examples are given of the application of normal curves to the solution of problems of primary and secondary recovery. Nature of Permeability Frequency Distributions Core-analysis data are made available as a tabulated depth vs. permeability profile. The nature of the distribution of permeability values within a given strati-graphic interval may be approximated from an array constructed with samples plotted in the order of their appearance with depth (accession number) against their permeability value in millidarcys. A wide variation in the nature of the distribution of K (permeability) values for

Jan 1, 1944

By Rex W. Woods, Morris Muskat

A leastmsquare analysis procedure has been developed and applied for the study of the deviations in estimations of oil in place as given by the material-balance equations. The data used were those obtained from field observations on the Jones sand in the Schuler pool, Arkansas, and the Monroe dolomite in the Reed City pool, Michigan. Possible effects of water intrusion were taken into account by expressing the cumulative water influx in terms of various functions previously proposed in the literature. Formulas were developed and values calculated for the minimum deviations and minimal percentage deviations in the calculated volumes of oil in place from the average values, as could be obtained by suitable choice of the water encroachment and initial gas-cap volume parameters. The results show that the fluctuations in these calculated volumes are very insensitive to the values chosen for the rate of water intrusion and initial gas-cap volume, and hence cannot be safely used in discriminating between spurious values for these parameters and such as actually pertain to the producing reservoirs. Moreover, the exact form of the water-intrusion function seems to have but little effect on the fluctuations in the computed oil in place. Accordingly, it is concluded that the material-balance method does not of itself provide a satisfactory criterion for determining the basic physical unknowns of producing reservoirs or in making conclusive decisions regarding the production mechanism, unless independently established geological control data are available for eliminating unreasonable values for the reservoir parameters, even though they may still satisfy the material-balance formulas. If, however, from core or logging data the initial oil in place and the gas-cap volume can be established in advance, the material-balance formulas can be inverted to find the water intrusion. Moreover, by determining by such calculations the water-intrusion coefficient, the iuture production performance can then be predicted by the aid of the materiaI-balance formulas for specified operating conditions. This type of application may be of particular value in predicting the results of Pressure-maintenance operations. Introduction The evaluation of the forces acting upon an oil reservoir is a problem of considerable interest to the operator as an aid in determining the proper method of operation for the reservoir to obtain an optimum recovery of oil. In many pools, the nature and magnitude of the forces acting upon the reservoir remain unknown until an appreciable amount of ultimate recovery is obtained. To be of value to the operator, a reliable interpretation of reservoir performance should be available in the early life of the pool to permit an optimum plan of operation. Progress has been made in an understanding of reservoir behavior and the importance of the different factors involved. The material-balance method of estimating oil in place has been proposed as a tool in analyzing reservoir-performance problems.l The solution of such problems by this method ordinarily involves two or more unknown values relating to the nature of the reservoir, and the results

Jan 1, 1945

By J. E. Sherborne, P. H. Jones, E. C. Babson

A study of the Chapman zone in the Richfield field, Orange County, California, indicates that the quantity of oil recovered by present methods will be only a small portion of the oil originally in place. Since the volume of residual oil is believed to be of large magnitude, an experimental water-flooding operation has been initiated in order to determine whether water-flooding offers promise as an economical method of recovering some of this residual oil. A single injection well was drilled between old producing wells, and a water-treating plant using alum flocculation and chlorination was designed and built. Water has been injected into the input well for six months at rates in excess of 100 bbl. per day. Production from one of the neighboring wells has increased materially, the oil production having risen from 7 to 30 bbl. and the water From I to 40 bbl. per day. While definite conclusions regarding the economic success of water-flooding in the Chapman zone are not justified at this time, it has been demonstrated that water can be injected into the zone on a sustained basis and that this water will displace appreciable quantities of oil from the sand. Introduction As a result of an investigation of subsurface conditions in the Chapman zone of the Richfield field, it was concluded that ultimate oil recovery from this zone would probably be low and that natural water encroachment was so localized as to be of little importance from a recovery stand- point. Furthermore, it was found that in many portions of the zone the wells were approaching an unprofitable level of production. When these data were presented to the management of the Union Oil Co.; their reaction was that an attempt should be made to develop methods of recovering at least a portion of the large quantity of oil remaining in this zone. After some investigation, it was decided that wafer-flooding offered the most likely means of accomplishing this end, but reservoir conditions in the Chapman zone differ so widely from those encountered in any of the flooding projects described in the literature that it was difficult to evaluate the probability of success. Despite encouraging results from laboratory tests, it was not even certain that water would displace an appreciable volume of oil from the Chapman sand under reservoir conditions. Therefore, it was decided to initiate a small-scale project, for two purposes: first, to determine whether water would displace oil from the Chapmall sand and, second, to obtain information and experience for future operations if water-flooding appeared to be a promising method of secondary recovery. Reservoir Data The Chapman zone is the upper of the two producing zones in the Richfield field, being found at depths from 3000 to 3700 fi.. The productive portion of the zolle consists of a large irregularly shaped sand body, which is more than 400 ft. thick at the top of the structure. As the margin of the field is approached, the sand is replaced

Jan 1, 1945

By R. U. Fitting, A. C. Bulnes

Field experience with limestone and sandstone production indicates the existence of wide differences between the reservoir behavior of these two types of formation. Little attention appears to have been given to the separate study of the flow of fluids and the retention of fluids in limestones. This paper presents data and arguments to demonstrate the existence of a difference between the two types of formation, and urges the separate intensive investigation of limestone reservoirs. AH experimental data presented pertain to dolomitic limestone formations in west Texas and New Mexico. Two kinds of Porous media are recognized— intergranular and intermediate. Intergranular rocks are those in which the porosity and permeability are determined by the geometrical properties and the sorting of the sedimentary units; intermediate rocks, those in which there is no direct relationship between grain properties and the porosity and permeability. Limestones in general are intermediate media. The partial relationship between porosity and permeability of any class of Porous media is represelried by an area of .finite extent and definite shape on the permeability-porosity plane. The horizontal and vertical variations of porosity and of permeability in limestone and sandstone formations are discussed and compared. Comparisons are made of connate-water content, the relative permeability-saturation relationship, and capillary phenomena in the two kinds of rocks. A number of tentative conclusions are drawn relative to the reservoir properties of lime- stones; in particular, (I) dolomitic limestones are oil bearing and apparently are oil productive in zones of permeability less than 0.1 millidarcyj and (2) primary depletion (by gas expansion) oil saturations may be lower in dolomitic limestones than in sandstones. Introduction It is well known that the reservoir performance of limestones displays numerous irregularities when compared with that of sandstones, and that the departures from "normal" behavior of limestones are more frequent and generally more marked than in sandstones. This is particularly true of fractured limestones and those that have undergone considerable development of secondary porosity' A review of the literature of production research published during the past 15 years reveals a startling absence of theoretical and experimental investigations directed specifically toward explaining and predicting the performance of limestone reservoirs, even. though such problems as the prediction of water encroachment and the estimation of ultimate recoveries continue at the "inspired guess" stage. By far the greater part of the experimental data reported pertain to measurements on sandstone core samples, while the theoretical studies, almost without exception, are developed from the assumption of an ideal porous medium and therefore seldom are applicable to limestone formations. The chief cause of this situation appears to be the common belief that, to all practical intents and purposes, sandstones and the majority of producing limestone formations

Jan 1, 1945

By D. L. Katz, M. J. Rzasa

The derivations of three methods of computing the static pressure gradients in natural gas wells have been presented to show the assumptions made. Charts were developed from which the pressure gradients may be read when the well-head pressure, the well fluid gravity, depth, and the average well temperature are given. A chart for estimating the well fluid gravity from the condensate content and separator gas gravity is included. The effect of the increased average well temperature after flow on the calculation of the static pressure gradient is discussed. Introduction Reservoir pressures have been calculated from well-head pressures for gas wells for many years. As the pressure measurements become more accurate, the need for a reliable calculation of the static pressure gradient often arises. This paper will develop the several methods for computing the pressure gradient in gas wells and make a comparison between them. The method of calculating static pressure gradients in common use is Eq. I (ref. I) or its counterpart which includes a factor for the deviation of the gas from the ideal gas law. P2 - P1 = P1(e0.0000347GX _ I) Eq. [I] in which P1 = pressure at well head, lb. per sq. in. abs. PP = pressure at bottom of well, Ib. per sq. in. abs. G = gas gravity X = depth of well, ft. An alternate method is to compute the average density of the gas in the well and multiply by the well depth in a manner similar to that used for liquid gradients. Derivation of Formulas A static pressure gradient is a special case of the general fluid-flow equation. Consider a pound of fluid flowing in a vertical column from point I to point 2, Fig. I. By an energy balance for fluid flowing from I to 2: U1 + P1V1 + u12/2g + X1 + q = U2 + P2V2+ u22/2g+X2 +W [2] in which U = internal energy, ft-lb. per lb. P = pressure, lb. per sq. ft. V = volume, cu. ft. per lb. u = average linear velocity, ft. per sec. X = height above datum, fl. q = heat absorbed by fluid, ft-Ib. pcr lb. W = work done by system, ft-lb. per lb. An energy balance on the fluid itself gives: U = ?TdS - ?PdV + etc. [3] in which T = temperature, deg- R- S = entropy, ft-lb. per deg. R. per lb.

Jan 1, 1945

By H. H. Kaveler

A summary of the reservoir engineering and related geologic data on the Schuler field, Union County, Arkansas, is presented here in a manner intended to interest both technical and nontechnical readers. The Cotton Valley formation and the Reynolds oolite are oil-productive formations in the Schuler field, but the Jones sand pool, at a depth of 7500 ft., developed with 146 wells on zo-acre spacing, is the reservoir of principal interest. The Jones sand sandstone reservoir is an anticlinal trap typically gas-drive or depletion type in performance. The core analyses from 88 per cent of the wells drilled, together with drilling time and electric-log data, yield an accurate estimate of the "productive" sand thickness and its areal distribution over the pool. Accurate production statistics, monthly reservoir-pressure surveys, and bottom-hole sample analyses when correlated by the "material-balance equation" show unusually good agreement with that principle. Estimates of oil initially in place made by the material-balance method and the sand-volume method are in good agreement at 116 to rzo million barrels. The reservoir-pressure history of the pool reflects the reaction of a reservoir to production, proration and secondary-recovery practices. The cost of the extensive program of reservoir study in the Jones sand pool has been estimated, in order to emphasize the value derived from such an investment through better understanding of a reservoir's reaction to production practices. Unit operation of 140 of the 146 Jones sand wells made possible an effective unitized gas-injection pressure-maintenance program. Res-ervoir-pressure decline was arrested, natural flow was maintained, and pumping and lease equipment were conserved. An increased ultimate recovery of zo million barrels beyond the estimated 34 million barrels primary recovery is indicated at present. Extension of the Jones sand unit to include the undeveloped Cotton Valley formation will permit additional recovery of otherwise uneconomic reserves of oil through wells no longer required in the Jones sand operations. Introduction The Schuler field comprises approximately 4000 acres in and about sec. 18, T. 18 S., R. 17 W. in west central Union County, Arkansas. Three reservoirs are procluctive of oil and gas: the Cotton Valley formation, the Jones sand, and the Reynolds oolite section of the Smackover limestone. The Jones sand pool is the most important reservoir from an engineering viewpoint. It possesses the traditional and somewhat classic characteristics usually associated with an anticlinal trap. Development and operations have followed the dictates of advanced engineering practices. The pool has attracted attention because of the unusually detailed reservoir data obtained, its interesting production history, and the success of the unitized gas-injection pres-sure-maintenance operation now being carried out. The purpose of this paper is to present a summary of the engineering data relating to the field, with particular reference to the more interesting general applications of

Jan 1, 1944

By H. H. Kaveler

A summary of the reservoir engineering and related geologic data on the Schuler field, Union County, Arkansas, is presented here in a manner intended to interest both technical and nontechnical readers. The Cotton Valley formation and the Reynolds oolite are oil-productive formations in the Schuler field, but the Jones sand pool, at a depth of 7500 ft., developed with 146 wells on zo-acre spacing, is the reservoir of principal interest. The Jones sand sandstone reservoir is an anticlinal trap typically gas-drive or depletion type in performance. The core analyses from 88 per cent of the wells drilled, together with drilling time and electric-log data, yield an accurate estimate of the "productive" sand thickness and its areal distribution over the pool. Accurate production statistics, monthly reservoir-pressure surveys, and bottom-hole sample analyses when correlated by the "material-balance equation" show unusually good agreement with that principle. Estimates of oil initially in place made by the material-balance method and the sand-volume method are in good agreement at 116 to rzo million barrels. The reservoir-pressure history of the pool reflects the reaction of a reservoir to production, proration and secondary-recovery practices. The cost of the extensive program of reservoir study in the Jones sand pool has been estimated, in order to emphasize the value derived from such an investment through better understanding of a reservoir's reaction to production practices. Unit operation of 140 of the 146 Jones sand wells made possible an effective unitized gas-injection pressure-maintenance program. Res-ervoir-pressure decline was arrested, natural flow was maintained, and pumping and lease equipment were conserved. An increased ultimate recovery of zo million barrels beyond the estimated 34 million barrels primary recovery is indicated at present. Extension of the Jones sand unit to include the undeveloped Cotton Valley formation will permit additional recovery of otherwise uneconomic reserves of oil through wells no longer required in the Jones sand operations. Introduction The Schuler field comprises approximately 4000 acres in and about sec. 18, T. 18 S., R. 17 W. in west central Union County, Arkansas. Three reservoirs are procluctive of oil and gas: the Cotton Valley formation, the Jones sand, and the Reynolds oolite section of the Smackover limestone. The Jones sand pool is the most important reservoir from an engineering viewpoint. It possesses the traditional and somewhat classic characteristics usually associated with an anticlinal trap. Development and operations have followed the dictates of advanced engineering practices. The pool has attracted attention because of the unusually detailed reservoir data obtained, its interesting production history, and the success of the unitized gas-injection pres-sure-maintenance operation now being carried out. The purpose of this paper is to present a summary of the engineering data relating to the field, with particular reference to the more interesting general applications of

Jan 1, 1944

By M. G. Arthur

This paper is a theoretical analysis of fingering of water and coning of water and gas in homogeneous sand. Investigation of this idealized case illustrates the relative magnitude of the factors involved in actual conditions. The body of the report presents equations, example calculations, and charts that facilitate solution of such problems. Derivation of the equations introduced in this paper and a discussion of previously published equations are included in the appendix. Introduction Production of water from oil wells as a result of the pressure gradients established by flow of fluids through oil-~roducing sands is a common occurrence, which influences the cost of oil production, the degree of depletion and the efficiency of expulsion of oil from naturally occurring reservoirs. Control of water production and encroachment are important both in primary and secondary phases of of exploitation in order to produce oil and gas at lowest cost and in order to achieve the greatest ultimate recovery of the oil in the reservoir. Although many actual oil reservoirs present a multitude of variables that influence fingering and coning of water and gas, an inspection of the relationship and magnitude of the forces involved in the case of a homogeneous sand may indicate satisfactory methods of controlling water production. Application of equations relating the variables may indicate the geometric type of drainage that exists in a particular reservoir or in the vicinity of a particular well. A homogeneous sand body is assumed within the portion of the reservoir influenced by the well. Two geometric types of drainage are considered theoretically. The first is water fingering into an oil sand that is relatively thin compared with the lateral extent of the sand. This sand may represent the entire oil-producing reservoir or it may represent one interval in an oil reservoir, which is separated from other producing intervals by competent lithologic barriers to flow of fluids. For the condition of complete penetration of a well in such a sand body, it may be assumed that no flow occurs across bedding planes. A mathematical relation is developed between the limit of approach of a water finger to the well without being drawn into the well and the corresponding operating pressure drawdown. The second condition considered is that of water or gas entry into an oil well as the result of coning through bedding planes. The theory and graphical solution developed by Muskat' for the limit of approach of a water or gas cone to a well, without its entry into the well, related to the corresponding maximum pressure drawdown, is reviewed and amplified, Charts are presented, which facilitate graphical solution of the problem. A method is presented for the extension of this type of graphical solution to the case where gas and water coning occurs simultaneously~

Jan 1, 1944

By M. G. Arthur

This paper is a theoretical analysis of fingering of water and coning of water and gas in homogeneous sand. Investigation of this idealized case illustrates the relative magnitude of the factors involved in actual conditions. The body of the report presents equations, example calculations, and charts that facilitate solution of such problems. Derivation of the equations introduced in this paper and a discussion of previously published equations are included in the appendix. Introduction Production of water from oil wells as a result of the pressure gradients established by flow of fluids through oil-~roducing sands is a common occurrence, which influences the cost of oil production, the degree of depletion and the efficiency of expulsion of oil from naturally occurring reservoirs. Control of water production and encroachment are important both in primary and secondary phases of of exploitation in order to produce oil and gas at lowest cost and in order to achieve the greatest ultimate recovery of the oil in the reservoir. Although many actual oil reservoirs present a multitude of variables that influence fingering and coning of water and gas, an inspection of the relationship and magnitude of the forces involved in the case of a homogeneous sand may indicate satisfactory methods of controlling water production. Application of equations relating the variables may indicate the geometric type of drainage that exists in a particular reservoir or in the vicinity of a particular well. A homogeneous sand body is assumed within the portion of the reservoir influenced by the well. Two geometric types of drainage are considered theoretically. The first is water fingering into an oil sand that is relatively thin compared with the lateral extent of the sand. This sand may represent the entire oil-producing reservoir or it may represent one interval in an oil reservoir, which is separated from other producing intervals by competent lithologic barriers to flow of fluids. For the condition of complete penetration of a well in such a sand body, it may be assumed that no flow occurs across bedding planes. A mathematical relation is developed between the limit of approach of a water finger to the well without being drawn into the well and the corresponding operating pressure drawdown. The second condition considered is that of water or gas entry into an oil well as the result of coning through bedding planes. The theory and graphical solution developed by Muskat' for the limit of approach of a water or gas cone to a well, without its entry into the well, related to the corresponding maximum pressure drawdown, is reviewed and amplified, Charts are presented, which facilitate graphical solution of the problem. A method is presented for the extension of this type of graphical solution to the case where gas and water coning occurs simultaneously~

Jan 1, 1944

By C. R. Dodson, W. T. Cardwell

This paper presents the results of a theoretical and experimental study of the effect of preperforated liners on well productivity. The analysis concerns the rectangular type of slot, either machine or torch cut, which is common in California. Muskatla treated this problem recently in a mathematical analysis of the flow of oil or gas from natural reservoirs into both gun-perforated and slotted liners. This paper presents additional and simplified analytical considerations and conclusions for the slotted liner, the solutions being applicable in the laboratory as well as in the field. An application of the analytical methods to permeability measurements on mounted core samples is given, to show the effects of sealing wax or other obstructions on the end faces of the cores. Results Fig. I 'Ompares the results of some theoretical calculations with the results of electrical analogy experiments performed in the Standard Oil Company of California's Production Technology Laboratory at La Habra, California. Fig. I indicates that the flux into short, "three-dimensional slots" of the relative dimensions encountered in practice is approximately equal to that into full-length, "two-dimensional slots" having the same open fraction of pipe. (The same numbers of slot rows, and the same radius ratio are also implied.) It can be seen from physical considerations that the closeness of this approximation must improve as the ratio of the external radius to the internal radius increases. Therefore, it is possible to calculate the flow into a slotted liner using a simple modification of the Darcy equation: where N is .the number of slot rows and O is the open fraction of the pipe. Fig. 2 shows the results of calculations . using Eq. 28. The most remarkable features of Fig. 2 are the high flux values for very small open fractions of pipe. For instance, with six slot rows and a radius ratio of 500, 74 per cent of the open-hole flux may be obtained with only o.I per cent of pipe Open. Fig. 2 shows that for a given open frac tion of pipe, the flux is greater, the greater

Jan 1, 1945

By G. L. Hassler, E. Bruner

An apparatus and method is described whereby the relation between saturation and capillary pressure under decreasing saturation can be quickly determined for small core samples. The initially saturated core is cen-trifuged at increasing rates and the average saturation is measured at each rate with the aid of a stroboscope device. A theory and calculation procedure is given whereby the accelerations and saturation values can be converted into a true curve of capillary pressure versus saturation. The present work differs from previously described use of the centrifuge to obtain capillary-pressure curves of core samples3 in that the core is centrifuged alone, so that the whole range of saturations required by the properties of the sample and the radially varying centrifugal force occurs within the sample. The calculation procedure nevertheless secures correct results from simply obtained values of the average saturation. The apparatus described was developed in connection with studies of capillary pressure and wetting of oil-field rocks, and the paper provides the apparatus background for a previous publication' dealing more fully with the uses and implications of the data in petroleum engineering. The method is applicable, however, to general combinations of immiscible fluids and porous or comminuted solids, and may be useful in other fields. Introduction The importance of capillary phenomena in determining the behavior of liquids in porous media has long been recognized. The concept of capillary Pressure was early formulated, and in recent Years discussions of the application of the laws of capillarity to oil field problems have appeared.l-3 One reason why progress in the application of capillary phenomena to the solution of problems of reservoir mechanics has not been more rapid has been the lack of a, satisfactory technique for measuring the capillary pressures in reservoir rocks. It is the principal purpose of this paper to describe a method by which the relation between capillary pressure and saturation can be determined for small consolidated core samples which have been extracted and resaturated, Capillary Diaphragm Perhaps the most direct way to measure the capillary pressure in a rock is to make piezometric contact with the wetting liquid through a diaphragm of porous material with high displacement pressure saturated with the liquid in question.3-6 The liquid in the diaphragm assumes the pressure of the liquid in the core, which can then be measured with a manometer, while the atmospheric air is prevented by capillarity from entering the diaphragm and affecting the pressure measurements as long as the displacement pressure of the diaphragm is not exceeded. With an apparatus of the type illustrated schematically in Fig. I, the relation between capillary pressure and saturation can be measured for a small core sample by starting with the core saturated 100 per cent, applyillg successively greater suctions

Jan 1, 1945

By P. E. Fitzgerald, Dana G. Hefley

An apparatus has been developed which permits selective acidizing of producing formations and determination of the relative permeability of a formation by fluid injection. This apparatus, known as the "Electric Pilot," is an electrical fluid-interface locator, the electrical circuit of which is completed when the elec-tcodes in the well are in contact with a conductive fluid, but is not completed when immersed in a nonconductive fluid. Results are given for a number of typical acidizing applications in which the interface locator was used to control the acid. Description of the method used in making a permeability survey and the data obtained are also included. Introduction Early in the development of the acidizing industry it was recognized that one of the most important problems to be solved in the chemical treatment of any well was the determination of what part of the exposed section in the well should be treated and the selection of the technique that would insure treatment of the desired section. One of the first techniques adopted for assisting in proper placement of the acid, which is still widely used, is the method of confining the acid to the producing section by means of a column of oil, which is known as the Carr1 method of treatment, named for its inventor. In the Carr method it is not possible to selectively acidize a specific horizon in a multiple pay zone, so many improvements and modifications of the basic Carr technique were devised to accomplish this result. In order to overcome the possibility of the acid entering an undesirable section at the bottom of the well, organic gel plugs2 were introduced into the bottom of the well, which served to halt the entrance of the treating solution into these zones.3 These chemical gels later liquefied because of bacterial action and were removed from the well with the produced fluid. In fields where a gas cap existed, as in the Goldsmith field of Ector County, Texas) it was imperative that a treating technique be evolved that would confine the acid to the oil-producing zone below the gas cap. By so doing the oil-productive capacity of the wells could be improved without greatly increasing the gas production and this would lower the gas-oil ratio of the well. ~h, technique employed4 to achieve this effect utilized two pumps, one for pumping the chemicals down the tubing, the other to simultaneously force oil down the annular space to confine the acid to the oil pay, thus preventing the chemicals from entering the upper gas-bearing zones. Experience has indicated that gas wells and certain types of oil wells respond better to ''stage treating.'' This technique utilizes the introduction of a certain volume of acid and then allows the well to ''clean up99 before introduction of the next and usually successively larger stages. Where such methods are employed steps must be taken to keep a disproportionate share of the acid from entering the most permeable and previously treated Zones. A special tool

Jan 1, 1944

By P. E. Fitzgerald, Dana G. Hefley

An apparatus has been developed which permits selective acidizing of producing formations and determination of the relative permeability of a formation by fluid injection. This apparatus, known as the "Electric Pilot," is an electrical fluid-interface locator, the electrical circuit of which is completed when the elec-tcodes in the well are in contact with a conductive fluid, but is not completed when immersed in a nonconductive fluid. Results are given for a number of typical acidizing applications in which the interface locator was used to control the acid. Description of the method used in making a permeability survey and the data obtained are also included. Introduction Early in the development of the acidizing industry it was recognized that one of the most important problems to be solved in the chemical treatment of any well was the determination of what part of the exposed section in the well should be treated and the selection of the technique that would insure treatment of the desired section. One of the first techniques adopted for assisting in proper placement of the acid, which is still widely used, is the method of confining the acid to the producing section by means of a column of oil, which is known as the Carr1 method of treatment, named for its inventor. In the Carr method it is not possible to selectively acidize a specific horizon in a multiple pay zone, so many improvements and modifications of the basic Carr technique were devised to accomplish this result. In order to overcome the possibility of the acid entering an undesirable section at the bottom of the well, organic gel plugs2 were introduced into the bottom of the well, which served to halt the entrance of the treating solution into these zones.3 These chemical gels later liquefied because of bacterial action and were removed from the well with the produced fluid. In fields where a gas cap existed, as in the Goldsmith field of Ector County, Texas) it was imperative that a treating technique be evolved that would confine the acid to the oil-producing zone below the gas cap. By so doing the oil-productive capacity of the wells could be improved without greatly increasing the gas production and this would lower the gas-oil ratio of the well. ~h, technique employed4 to achieve this effect utilized two pumps, one for pumping the chemicals down the tubing, the other to simultaneously force oil down the annular space to confine the acid to the oil pay, thus preventing the chemicals from entering the upper gas-bearing zones. Experience has indicated that gas wells and certain types of oil wells respond better to ''stage treating.'' This technique utilizes the introduction of a certain volume of acid and then allows the well to ''clean up99 before introduction of the next and usually successively larger stages. Where such methods are employed steps must be taken to keep a disproportionate share of the acid from entering the most permeable and previously treated Zones. A special tool

Jan 1, 1944

By E. Brunner, G. L. Hassler, T. J. Deahl

The capillary effects in reservoir rock are discussed in terms of the pressures they cause in sandstones and dolomites. Data for the two-phase case (oil-gas or water-gas) and for the three-phase case (oil, water and gas in rock) are used to demonstrate that in one sense the wetting preference of a rock depends on its saturation. The nature of capillary hysteresis is described for partially stable conditions, and the concept is enlarged. Reproducibly measurable pressures include the "capillary pressure," which is the pressure difference between any two phases that are each interconnected; the "threshold pressure," necessary to force a nonwetting phase through partially saturated rock; the "displacement pressure," which is that special case of the threshold pressure in which both phases fully saturate separate portions of the rock. Displacement pressure is equal to the minimum value of the "capillary pressure." The theory of flow including capillary forces is developed at the producing surface of a well to reveal the presence there of a pressure discontinuity in the gas (or other nonwetting) phase that can be controlled to the end that more oil may be poduced from an oil field. Experiments with packed sand-flow tubes having artificial producing surfaces support the theory. Introduction The basic surface quantities acting in an oil field are two: namely, surface tensions and contact angles. These are the quantities, variously expressed, and particularized as spreading forces, adhesion tensions, heats of wetting, etc., which are measured in the laboratory by techniques mostly confined to flat or circularly cylindrical surfaces. Such measurements have not had the extensive engineering application they seem to deserve because in most practical cases they are unavoidably compounded with the complex and unapproached subject of the internal shape of the interstices of rock. In this paper it is intended that the pressure differences developed in rock by capillarity be examined, defined, and given some engineering use in terms of some new measurements that have been made. Such pressure differences—namely, the capillary pressure, the displacement pressure and the threshold pressure—seem to provide a proper contact between the basic molecular quantities and the oil field. While certain modifications of usage will be undertaken, the present effort rests upon the background of work by the U. S. Geological Survey,l by Versluys, and especially by W. 0. Smith, 3,4,5 which has been reviewed recently in papers by Leverett.=s7 The most important concept of pressure difference is the capillary pressure, a function of saturation that expresses the pressure difference between the interconnected phases in a rock. It is often measured when water and air are the fluids present, but it can be measured with other fluids. A number of curves of capillary pressure have recently been measured by a method which it is intended shall be published in a later paper. Since heretofore capillary-pressure measurements upon rock have not been

Jan 1, 1944

By G. L. Hassler, E. Brunner, T. J. Deahl

The capillary effects in reservoir rock are discussed in terms of the pressures they cause in sandstones and dolomites. Data for the two-phase case (oil-gas or water-gas) and for the three-phase case (oil, water and gas in rock) are used to demonstrate that in one sense the wetting preference of a rock depends on its saturation. The nature of capillary hysteresis is described for partially stable conditions, and the concept is enlarged. Reproducibly measurable pressures include the "capillary pressure," which is the pressure difference between any two phases that are each interconnected; the "threshold pressure," necessary to force a nonwetting phase through partially saturated rock; the "displacement pressure," which is that special case of the threshold pressure in which both phases fully saturate separate portions of the rock. Displacement pressure is equal to the minimum value of the "capillary pressure." The theory of flow including capillary forces is developed at the producing surface of a well to reveal the presence there of a pressure discontinuity in the gas (or other nonwetting) phase that can be controlled to the end that more oil may be poduced from an oil field. Experiments with packed sand-flow tubes having artificial producing surfaces support the theory. Introduction The basic surface quantities acting in an oil field are two: namely, surface tensions and contact angles. These are the quantities, variously expressed, and particularized as spreading forces, adhesion tensions, heats of wetting, etc., which are measured in the laboratory by techniques mostly confined to flat or circularly cylindrical surfaces. Such measurements have not had the extensive engineering application they seem to deserve because in most practical cases they are unavoidably compounded with the complex and unapproached subject of the internal shape of the interstices of rock. In this paper it is intended that the pressure differences developed in rock by capillarity be examined, defined, and given some engineering use in terms of some new measurements that have been made. Such pressure differences—namely, the capillary pressure, the displacement pressure and the threshold pressure—seem to provide a proper contact between the basic molecular quantities and the oil field. While certain modifications of usage will be undertaken, the present effort rests upon the background of work by the U. S. Geological Survey,l by Versluys, and especially by W. 0. Smith, 3,4,5 which has been reviewed recently in papers by Leverett.=s7 The most important concept of pressure difference is the capillary pressure, a function of saturation that expresses the pressure difference between the interconnected phases in a rock. It is often measured when water and air are the fluids present, but it can be measured with other fluids. A number of curves of capillary pressure have recently been measured by a method which it is intended shall be published in a later paper. Since heretofore capillary-pressure measurements upon rock have not been

Jan 1, 1944

By W. N. Lacey, R. H. Olds, B. H. Sage

Samules of liquid and gas were obtained from the primary separator of a well in the Paloma field. The volumetric properties of the samples and of six systematically chosen mixtures of the samples were experimentally determined at 100°, 190°, and 250°F. at pressures up to 5000 lb. per sq. inch. From these data the influence ,of pressure and temperature upon the composition and specific volume of the bubble-point liquid and of the retrograde dew-point gas was established, The formation volumes and gas-oil ratios of the rnixtures investigated were calculated on the basis of the plant-product oil, which is defined as the isobutane and less volatile portion of each mixture. The results are presented in graphical and tabular form. The volumetric behavior of the mixture corresponding to that produced by the well at the time of sampling was determined for 235ºF., the reported reservoir temperature, by graphical interpolation of the experimental data with respect to composition and temperature. The results indicate that the well-production mixture probably existed as a gas at its retrograde dew point under the conditions of temperature and pressure believed to prevail in the producing zone at the time of sampling. The effect upon the phase behavim occasioned by the omission from the well-production mixture of certain components of intermediate molecular weight was investigated. In the first case, all of the isobutane and 11-butane, and substantially all of the iso-pentane, were removed from the mixture of trap samples corresponding to the well production. In the second case, all the propane, isobutane and n-butane, and substantially all of the isopentane, were removed. Both modifications led to considerable increases in the retrograde dew-point Pressure at 235ºF.; an increase of 558 lb. Per sq. in. above that of the unmodified well-production mixture in the first case, and an increase of 1208 lb. Per sq. in. in the second. It was concluded that the material? remaining after the removal of certain components of intermediate molecular weight could not be injected back into the reservoir in the saqe proportion in which they were produced without entailing appreciable loss of liquid material through condensation within the formation. Introduction Under the usual conditions of production practice, petroleum arrives at the surface of the earth in a physical state considerably different from that in which it existed in the underground reservoir. The relative rates of production and the properties of oil and gas measured at surface conditions do not constitute, in general, even a qualitative description of the fluids existing in the reservoir. The estimation of reserves and the attainment of optimum efficiency with regard to rate, quantity, and cost of production require accurate data concerning the physical properties of petroleum throughout large changes in pressure and temperature. Many schemes have been devised for predicting the behavior of propane, as it is encountered in nature? but the experimental work upon which these predictions are based has not, for the most part, been extended to the higher pressures that occur in practice, nor do these methods permit, as yet, the estima-

Jan 1, 1945

By Norris Johnston, Carrol M. Beeson

For many years the permeability of reservoir sands has been measured by flowing air through a cleaned and dried core sample. This differs from the true reservoir permeability in one important respect: the rock particles in the reservoir are surrounded by interstitial water, not air, and their physical shape and condition of hydration are greatly dependent thereon. Permeability as defined must be measured with a single-phase fluid. Since no means exist for removing the oil and gas from a core sample by simply flowing water through it, the sample must be cleaned and then resatu-rated with water before testing. The present discussion attempts to show that after the cleaning process a considerably different permeability is determined with salt or fresh water than is obtained with air. The postulate is made that the salt-water permeability is probably closer to the true reservoir permeability than is the measurement with air. This is discussed in relation to both physically possible and economically feasible measuremerits. Data On more than 1200 core samples are given to show the nature of the effects observed, and a plea is made for others to consider water permeability measurements as a routine necessity, eventually replacing air permeability in regions where the differences are great. Introduction Permeability is defined1 as a "a measure of the capacity of a porous medium to transmit fluids, when there is no interaction between the solids and the fluid." Darcy's law of liquid flow in porous media states: kA?P QµL/A?L [I] where Q represents milliliters of liquid of viscosity p centipoises passed per second through a porous medium of permeability k darcys and cross-sectional area A sq. cm. under a pressure gradient ?P/L atmospheres per centimeter, the flow being understood to be laminar or viscous, not turbulent. This equation defines the darcy. For the case of radial flow in a uniform sand, such as usually exists in the neighborhood of a well in an oil or gas sand, Darcy's law becomes:2 Here h is the net sand thickness in feet, Pe and Pw are pressures at the drainage radius4 and well radius, and re and rw are these radii, respectively. The productivity index3 is defined as the barrels of liquid produced per day per pound per square inch mean pressure differential between ferences and well bore, and is thus: By further definition, the specific productivity index is: or in terms of practical units, and allowing for shrinkage:

Jan 1, 1945

By A. W. WALKER

All branches of production engineering showed steady and definite progress during 1941. Most of it has been of the slower and more conservative type rather than the sensational. To a large degree the changes have been influenced by the expanding war economy, and this tendency will probably be even more marked during the coming year. The stress of the times is placing more emphasis on the principles of engineering and conservation, with the object of obtaining the greatest possible recovery with a minimum waste or expenditure of equipment. Also available material supplies are often being turned to new uses.

Jan 1, 1942

By W. Henry Weimer

A successful surface coal operation requires the combined efforts of engineering and operating personnel. In the planning for a mine, machines should be selected to do the best work in getting the coal uncovered, loaded, and transported to the preparation plant. The best system and extent of cleaning will be determined by the market. After the fundamentals of operation have been established, the operating personnel should see they are carried out. There is no simple solution to some of the every day problems facing the operating officials. Here the production engineer with the technical approach, time studies, control methods, past experience, and available records can help in detecting causes of inefficient phases of the operations. With these studies, a careful analysis can be made in setting up the expected standards to be followed. Management can then compare the job under study with the standards and make corrections to solve the problems. 5.2-1. Annual or Daily Coal Production. Once the production cycle has been established, it is paramount that coal sales keep the productivity of the mine as high as possible. A successful company does this by what they call "the control approach." The daily tonnage report is one of the things that is a potent control tool in attaining the goals to be achieved. If production is falling short of the goal, the daily tonnage report will reveal what has to be done in the remaining days of the month or year to achieve the expected schedule. When goals are reached or exceeded, then budgeted tonnages and costs will be reached or exceeded and thus assure attainment of a profit. Failing to keep to the scheduled pace shows up quickly and prominently, facilitating any necessary action to get things back to the projected plans. The sales target is usually set a little higher than the operating production. The sales tonnage is scheduled and sales are made accordingly, slightly

Jan 1, 1968

By J. S. Woodward, F. B. Plummer

The measurement of the rate of flow of liquids through sands dates back to 1856, when H. d Arcyb, a French physicist, carried out his classic experiments on the flow of water through sand layers. The earliest recorded data on relationships of pressure to flow of fluids through porous rocks in this country are those of Newell 23 in 1885. The first comprehensive studies of flow were made in 1898 by King15, who measured the rate of flow of water and air through consolidated and uncon-solidated sands and published the results. From 1900 to 1920 there appears to have been little interest in permeability. In 1920 the increase in demand for oil led the U. S. Bureau of Mines to begin a series of experiments to determine subsurface relationships of oil and water and the characteristics of their flow. Mills18 studied the relationship of flow of liquids to text- and structure of the sands, and Melcher17 in 1925 made a quantitative study of effect of changes in pressure on rate of flow of crude oil through Oklahoma oil sands. Since 1930 the importance of flow measurements to production of oil and gas has been emphasized by a large number of excellent investigations. Among these the works of Fettke9.10, BarbI.2, Cloud6, Nutting24-", Bot-set4, Nevin22, Tickell32.33, Fancher, Lewis and Barnes8, Moore, Schilthuis and Hurst19, and Wyckoff, Botset and Muskat"-39 have contributed much to our knowledge of the technique of permeability measurements and to the laws of liquid and gas flow through porous sands. The application of their work has led to the establishment of laboratories for measuring the permeability and porosity of oil sands by most of the large companies. All the investigations, except those of Wyckoff, Botset and Muskat, and Moore, Schilthuis and Hurst deal with linear flow; that is, flow in a more or less straight line through a given cross-sectional area of sand. Three years ago, at the University of Texas, experiments were started to measure radial flow of liquids through sands; that is, flow from all directions toward a central opening—the conditions that operate in a

Jan 1, 1937