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By Benjamin C. Craft, Frank Perkins

The wall-building properties of salt-water muds can be maintained at high temperatures by additions of gum karaya, gum ghatti, gelatinized starch, or commercially prepared starch. A germicide should be used to prevent fermentation. Introduction The behavior of drilling mud has received special attention from the petroleum industry within the past few years in numerous research projects dealing with such subjects as chemical treatment, gelation, and filtration characteristics. The importance and control of filtration, or water loss, is readily apparent* It affects the analysis of side-wall cores and interpretation of electric logs; it controls to a large extent the work of primary cementing, reduces the amount of expensive fishing, and permits the running of long strings of casing. It has been found that among the many factors that have an adverse effect on filtration, the presence of electrolytes, in general, and of salt, in particular, is outstanding. The effect is one of flocculation of the colloids due to neutralization of the negative charges on the clay particles. This reaction is further increased on the Gulf Coast because high temperatures reduce dispersion, to a minimum, causing increased flocculation in both fresh-water and saltwater muds. The problem of reducing water loss in salt-water muds by the addition of gums and starch at atmospheric temperature has been investigated,' and many successful field tests in West Texas indicate its solution. From the work of Byck2 it is concluded that no existing method will permit an approximate determination of the filtration rate at high temperatures from data taken at room temperatures. Filtration should be measured at the ternperature actually anticipated in the well, or at least at a number of lower temperatures and extrapolated over a small range. A laboratory study has been made of the chemicals available for the filtration characteristics of salt-water muds at high temperatures, and the use of germicides to prevent fermentation. Laboratory Investigations Procedure Since the purpose of this investigation was to compare several different gums and starches at elevated temperatures, mud from the same source was used for all the tests. Viscosity was measured in a Stormer viscosimeter at 600 r.p.m. and water loss was determined with a Baroid High-pressure and High-temperature Wall-building Tester3 at temperatures from 80' to 250°F. and at a pressure of 500 lb. per sq. in. for 30 minutes. The samples tested consisted of 150 grams of commercial Louisiana mud, 50

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

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

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

By D. F. Botkin, B. H. Sage, W. N. Lacey

Joule-THomson coefficients for two natural gases were determined at pressures up to 600 lb. per sq. in. throughout the temperature interval between 70" and 310°F. From these primary data and available information relating to the isobaric heat capacities of the components at infinite volume, the heat capacities of these gases were computed throughout the above-mentioned range of pressures and temperatures. The enthalpies of the gases were computed as a function of state and the results compared with values obtained by several methods of prediction currently available. Table i .—Composition of Gas Samples Components Gas A Gas B Carbon dioxide................ 0.0090a 0 .042 0 Methane...................... 0.8255 0.8385 Ethane.......................0.0901 0 .0637 Propane....................... 0.0462 0.0374 Isobutane..................... 0.0074 0.0039 n-butane................ ...... 0. 0126 0 .0095 Isopentane.................... 0.0032 0.0016 n-pentane..................... 0.0022 0.0011 Hexanes and Heavier........... 0.003& 0.0023 Experimentally determined Joule-Thom. son coefficients for natural gases afford a satisfactory means of checking the accuracy of prediction of their thermodynamic properties from the behavior of the components in the pure state and in binary mixtures. Relatively small samples of these natural gases were available, together with their analyses, and the Joule-Thomson coeffi- The Joule-Thomson coefficients were determined by measuring the change in temperature resulting from the passage of the gas through a porous thimble with a known pressure difference and under such conditions that the process was substantially isonthalpic. The details of the apparatus employed for this purpose have been described.' It is believed that the changes in temperature and pressure were ascertained with an uncertainty of not more than 0.3 per cent. However, as a result of deviations from steady flow, it is probable that uncertainties as large as 2 per cent may exist in the measured Joule-Thomson coefficient. The gases utilized in this work were taken from high-pressure separators and were dried prior to use by passage over calcium chloride at pressures in excess of 300 lb. per sq. in. The gases were subjected to the conventional fractionation and Orsat analyses. The results are recorded in Table I. The composition is typical of gases from such sources, with the possible exception of the presence of significant quantities of carbon dioxide in each of the samples. The experimental results obtained for the two natural gases are graphically Portrayed in Figs. I and 2. The experimental

Jan 1, 1943

By W. N. Lacey, D. F. Botkin, B. H. Sage

Joule-THomson coefficients for two natural gases were determined at pressures up to 600 lb. per sq. in. throughout the temperature interval between 70" and 310°F. From these primary data and available information relating to the isobaric heat capacities of the components at infinite volume, the heat capacities of these gases were computed throughout the above-mentioned range of pressures and temperatures. The enthalpies of the gases were computed as a function of state and the results compared with values obtained by several methods of prediction currently available. Table i .—Composition of Gas Samples Components Gas A Gas B Carbon dioxide................ 0.0090a 0 .042 0 Methane...................... 0.8255 0.8385 Ethane.......................0.0901 0 .0637 Propane....................... 0.0462 0.0374 Isobutane..................... 0.0074 0.0039 n-butane................ ...... 0. 0126 0 .0095 Isopentane.................... 0.0032 0.0016 n-pentane..................... 0.0022 0.0011 Hexanes and Heavier........... 0.003& 0.0023 Experimentally determined Joule-Thom. son coefficients for natural gases afford a satisfactory means of checking the accuracy of prediction of their thermodynamic properties from the behavior of the components in the pure state and in binary mixtures. Relatively small samples of these natural gases were available, together with their analyses, and the Joule-Thomson coeffi- The Joule-Thomson coefficients were determined by measuring the change in temperature resulting from the passage of the gas through a porous thimble with a known pressure difference and under such conditions that the process was substantially isonthalpic. The details of the apparatus employed for this purpose have been described.' It is believed that the changes in temperature and pressure were ascertained with an uncertainty of not more than 0.3 per cent. However, as a result of deviations from steady flow, it is probable that uncertainties as large as 2 per cent may exist in the measured Joule-Thomson coefficient. The gases utilized in this work were taken from high-pressure separators and were dried prior to use by passage over calcium chloride at pressures in excess of 300 lb. per sq. in. The gases were subjected to the conventional fractionation and Orsat analyses. The results are recorded in Table I. The composition is typical of gases from such sources, with the possible exception of the presence of significant quantities of carbon dioxide in each of the samples. The experimental results obtained for the two natural gases are graphically Portrayed in Figs. I and 2. The experimental

Jan 1, 1943

By F. C. Oliphant, George H. Fancher

Two samples of drilling mud from the Hastings oil field, Texas, were tested, and the solids in each were separated into small fractions of a limited range in particle size. The mineral composition of each fraction by X-ray analysis is reported, and the results are interpreted in relation to other measured quantities, such as the physical properties of the original samples and the density of the various fractions. It was found that only 7 to 8 per cent by weight of the solids was of colloidal dimensions and that neither of the samples contained montmorillonite but did contain illite. Considerable calcite was also found. These data should be useful to the geologist interested in the origin and history of sedimentary strata as well as to the petroleum engineer. Introduction The questions, What is good drilling mud? What constitutes bad drilling mud? are pertinent, because the proper use and control of drilling fluids has been a factor of great importance in the successful drilling and completion of oil wells since the days of Captain Lucas. Adequate control of the characteristics of drilling fluids has assumed greater significance comparatively recently because of the problems introduced by caving formations in deep wells, costly blowouts and impressive mud bills. Much is known about the solution of some of the problems but, despite extensive research directed toward a better understanding of the physical and chemical properties of clay suspensions, it is difficult to define precisely a drilling mud, and much more difficult to say what constitutes a good mud. It is generally believed that the smaller particles of a drilling mud greatly affect its physical properties. In fact, it is customary to blame the colloids in a mud for nearly everything that goes amiss, because colloidal properties have effects out of all usual proportion on viscosity, filtration rate and reaction to electrolytes. It is germane to know whether drilling muds possess colloids and if so, the quantity and kind. Source oF Samples Two drilling muds from the Hastings oil field, Brazoria County, Texas, were selected because it is generally agreed that in this oil field good natural muds made solely from formations penetrated by the drill can be used until the well is nearly ready for completion. Customary drilling procedure in this field is to spud in with water, set a protective string of pipe, drill to 2500 ft. and set the surface casing. Drilling is continued to 5500 ft. with no treatment of the drilling fluid other than addition of water to

Jan 1, 1943

By F. C. Oliphant, George H. Fancher

Two samples of drilling mud from the Hastings oil field, Texas, were tested, and the solids in each were separated into small fractions of a limited range in particle size. The mineral composition of each fraction by X-ray analysis is reported, and the results are interpreted in relation to other measured quantities, such as the physical properties of the original samples and the density of the various fractions. It was found that only 7 to 8 per cent by weight of the solids was of colloidal dimensions and that neither of the samples contained montmorillonite but did contain illite. Considerable calcite was also found. These data should be useful to the geologist interested in the origin and history of sedimentary strata as well as to the petroleum engineer. Introduction The questions, What is good drilling mud? What constitutes bad drilling mud? are pertinent, because the proper use and control of drilling fluids has been a factor of great importance in the successful drilling and completion of oil wells since the days of Captain Lucas. Adequate control of the characteristics of drilling fluids has assumed greater significance comparatively recently because of the problems introduced by caving formations in deep wells, costly blowouts and impressive mud bills. Much is known about the solution of some of the problems but, despite extensive research directed toward a better understanding of the physical and chemical properties of clay suspensions, it is difficult to define precisely a drilling mud, and much more difficult to say what constitutes a good mud. It is generally believed that the smaller particles of a drilling mud greatly affect its physical properties. In fact, it is customary to blame the colloids in a mud for nearly everything that goes amiss, because colloidal properties have effects out of all usual proportion on viscosity, filtration rate and reaction to electrolytes. It is germane to know whether drilling muds possess colloids and if so, the quantity and kind. Source oF Samples Two drilling muds from the Hastings oil field, Brazoria County, Texas, were selected because it is generally agreed that in this oil field good natural muds made solely from formations penetrated by the drill can be used until the well is nearly ready for completion. Customary drilling procedure in this field is to spud in with water, set a protective string of pipe, drill to 2500 ft. and set the surface casing. Drilling is continued to 5500 ft. with no treatment of the drilling fluid other than addition of water to

Jan 1, 1943

By G. D. Monk, W. C. Krumbein

The relation between permeability and the size parameters of unconsolidated sand is approached by considering sands as logarithmic frequency distributions having the basic parameters mean size and standard deviation. Sieve separates were mixed in accordance with the normal logarithmic probability law, so that the mean and standard deviation could be varied at will. Experiments were conducted in which one parameter was kept fixed and the other varied; in this manner the dependence of permeability on the individual parameters was evaluated. It was found that permeability can he expressed as the product of a power function of the mean size and an exponential function of the standard deviation. Earlier studies of the effect of size of particles on the permeability of uncon-solidated sand have shown that the permeability varies with the square of some average diameter. This was first pointed out by Hazenl in 1892 and verified by Slichter2 in 1898. Hazen's mean size was defined as the 10 percentile of the cumulative curve (i.e., size that is smaller than 90 pel cent of the distribution and larger than 10 per cent). Slichter's effective size, on the other hand, was found by Wilsey3,4 to agree with the 31 percentile. Fair and Hatch6 found that the geometric mean size of sieve separates yielded the same power function; Hulbert and Feben6 found that the permeability of sieve separates varied as the 1.89 power of the median diameter (i.e., the size associated with the 50 percentile of the cumulative curve). Relatively few studies included the effect of the "sorting" of the sediment on the permeability. It was recognized that the nature of the size distribution, in terms of the spread of the particles about the mean, affects the permeability, but no systematic investigations of this effect are known to the writers. Cloud7 demonstrated that the effect of the grain-size distribution on permeability is definitely measurable. In the present paper the authors investigate this relation analytically, and show that the effects of the size parameters on permeability may be predicted for at least a restricted set of conditions. Properties OF Sediments Recent investigations have shown that essentially all the geologically important characteristics of sediments may be expressed in terms of six measurable quanti-tities possessed by each clastic sedimentary particle. These attributes are: (I) size, (2) shape (sphericity), (3) roundness (angularity) , (4) mineralogical composition (density), (5) surface texture, (6) orientation. Each of these characteristics may be defined in several manners. Size may be expressed in terms of sieve mesh, settling velocity, volume, etc. Sphericity is a shape concept introduced by Wadell;8 it is essentially a measure of the ratio of the surface area of an equivalent sphere to the surface area of the particle. The same

Jan 1, 1943

By G. D. Monk, W. C. Krumbein

The relation between permeability and the size parameters of unconsolidated sand is approached by considering sands as logarithmic frequency distributions having the basic parameters mean size and standard deviation. Sieve separates were mixed in accordance with the normal logarithmic probability law, so that the mean and standard deviation could be varied at will. Experiments were conducted in which one parameter was kept fixed and the other varied; in this manner the dependence of permeability on the individual parameters was evaluated. It was found that permeability can he expressed as the product of a power function of the mean size and an exponential function of the standard deviation. Earlier studies of the effect of size of particles on the permeability of uncon-solidated sand have shown that the permeability varies with the square of some average diameter. This was first pointed out by Hazenl in 1892 and verified by Slichter2 in 1898. Hazen's mean size was defined as the 10 percentile of the cumulative curve (i.e., size that is smaller than 90 pel cent of the distribution and larger than 10 per cent). Slichter's effective size, on the other hand, was found by Wilsey3,4 to agree with the 31 percentile. Fair and Hatch6 found that the geometric mean size of sieve separates yielded the same power function; Hulbert and Feben6 found that the permeability of sieve separates varied as the 1.89 power of the median diameter (i.e., the size associated with the 50 percentile of the cumulative curve). Relatively few studies included the effect of the "sorting" of the sediment on the permeability. It was recognized that the nature of the size distribution, in terms of the spread of the particles about the mean, affects the permeability, but no systematic investigations of this effect are known to the writers. Cloud7 demonstrated that the effect of the grain-size distribution on permeability is definitely measurable. In the present paper the authors investigate this relation analytically, and show that the effects of the size parameters on permeability may be predicted for at least a restricted set of conditions. Properties OF Sediments Recent investigations have shown that essentially all the geologically important characteristics of sediments may be expressed in terms of six measurable quanti-tities possessed by each clastic sedimentary particle. These attributes are: (I) size, (2) shape (sphericity), (3) roundness (angularity) , (4) mineralogical composition (density), (5) surface texture, (6) orientation. Each of these characteristics may be defined in several manners. Size may be expressed in terms of sieve mesh, settling velocity, volume, etc. Sphericity is a shape concept introduced by Wadell;8 it is essentially a measure of the ratio of the surface area of an equivalent sphere to the surface area of the particle. The same

Jan 1, 1943

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

The compositions of coexisting phases in the methane-propane-n-pentane system were determined at 160° and -2 20°F. throughout the two-phase region, at pressures above 500 lb. per sq. in. The experimental results permitted the calculation of gas-liquid equilibrium constants as well as the establishment of the critical behavior of this ternary system. Although many binary paraffin hydrocarbon systems have been investigated, the experimental work relating to the phase behavior of ternary paraffin hydrocarbon mixtures at elevated pressures is relatively scarce, being limited to a study of the meth-ane-propane-PL-pentane system at 100°F.l,2 However, Guter and co-workers have studied the phase behavior of the methane-ethane-ethylene system at relatively low temperatures. Information concerning the phase behavior of ternary systems is of value in predicting the behavior of the components in multicomponent systems, since the influence of pressure, temperature, and concentration may be individually ascertained. In the light of the importance of such information, the study of this ternary system was extended to higher temperatures in order to increase the field of temperature in which the data could be applied. Since all states encountered in this investigation are above the critical temperature of methane, the details of its phase behavior are not of direct significance. The properties of propane in the heterogeneous region were taken from a correlation3 based upon recently published data. The corresponding information for n-pentane was taken from experimentally measured vapor pressures and volumetric data.4 The rnethane-propane system has been studied throughout the two-phase region at temperatures above 70°F.,5 while the phase behavior of the propane-n-pentane system has been established for temperatures above 160°F.6 The volumetric and phase behavior of the methane-72-pentane system has been studied in detai1.7,8 The experimental measurements serve to establish with adequate accuracy the phase behavior of the components and of the constituent binary systems for this ternary system. It is believed that, with the exception of the measurements for the methane-propane system, the uncertainties in the earlier data relating to the pure substances and the binary mixtures are probably less than those associated with the values reported here. Method The methods and apparatus employed in this investigation have been described.137 In principle, the method involved the withdrawal of samples of the coexisting gas and liquid phases from a vessel containing a heterogeneous mixture of methane, propane and n-pentane. Provision was made so that

Jan 1, 1943

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

The compositions of coexisting phases in the methane-propane-n-pentane system were determined at 160° and -2 20°F. throughout the two-phase region, at pressures above 500 lb. per sq. in. The experimental results permitted the calculation of gas-liquid equilibrium constants as well as the establishment of the critical behavior of this ternary system. Although many binary paraffin hydrocarbon systems have been investigated, the experimental work relating to the phase behavior of ternary paraffin hydrocarbon mixtures at elevated pressures is relatively scarce, being limited to a study of the meth-ane-propane-PL-pentane system at 100°F.l,2 However, Guter and co-workers have studied the phase behavior of the methane-ethane-ethylene system at relatively low temperatures. Information concerning the phase behavior of ternary systems is of value in predicting the behavior of the components in multicomponent systems, since the influence of pressure, temperature, and concentration may be individually ascertained. In the light of the importance of such information, the study of this ternary system was extended to higher temperatures in order to increase the field of temperature in which the data could be applied. Since all states encountered in this investigation are above the critical temperature of methane, the details of its phase behavior are not of direct significance. The properties of propane in the heterogeneous region were taken from a correlation3 based upon recently published data. The corresponding information for n-pentane was taken from experimentally measured vapor pressures and volumetric data.4 The rnethane-propane system has been studied throughout the two-phase region at temperatures above 70°F.,5 while the phase behavior of the propane-n-pentane system has been established for temperatures above 160°F.6 The volumetric and phase behavior of the methane-72-pentane system has been studied in detai1.7,8 The experimental measurements serve to establish with adequate accuracy the phase behavior of the components and of the constituent binary systems for this ternary system. It is believed that, with the exception of the measurements for the methane-propane system, the uncertainties in the earlier data relating to the pure substances and the binary mixtures are probably less than those associated with the values reported here. Method The methods and apparatus employed in this investigation have been described.137 In principle, the method involved the withdrawal of samples of the coexisting gas and liquid phases from a vessel containing a heterogeneous mixture of methane, propane and n-pentane. Provision was made so that

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 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. 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. 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 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 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 George Fancher, R. L. Whitting

A typical drilling mud from the Hastings oil field, Brazoria County, Texas, containing only 8 per cent (dry basis) of material of colloidal dimensions, which is largely illite, was concentrated to a density of 10.2 lb. per gal. and used in this study. The effects of water dilution, treatment with complex polyphos-phates, temperature and the time of heating upon the rheological properties of the mud were investigated. It was found that water plays an important part in chemical treatment and that sodium acid pyrophosphate and sodium tripolyphosphate were more efficient than other complex polyphosphates for chemical treatment. Muds treated with either of these chemicals manifested maximum reduction in viscosity and minimum filtration rates at low concentrations. Furthermore, .mud treated to minimum viscosity with either of these two chemicals was virtually unaffected by heat-treatment. Introduction The drilling of deep wells is dependent upon the use of drilling mud, and problems frequently arise concerning the effects on mud of temperature, prolonged heating and aging. The use of chemicals to control the rheological properties of mud is a well-established practice. Salts of weak organic acids such as sodium tannate or gallate were used at first until the complex phosphates of sodium were found to be more efficient. Consequently, it seemed important to investigate the reaction of a mud to chemical treatment with phosphates, temperature, heat-treatment and aging, particularly since previous work in the laboratory at the University of Texas had provided the particle-size distribution and mineral composition of Hastings mud. Properties or Mud Used in Experiments A large sample of the mud from a drilling well in the Hastings field, Brazoria County, Texas, was obtained directly from the circulatory system. Some of the general physical characteristics of the mud and other data are presented in Table I. Table i.—General Properties of Hustings Drilling Mud Alex- Cur-ander keet Well Well Depth when sample was taken, It.. 5720 5700 Weight. lb. per gal............... 9.5 0.8 Viscosity, sec. A.P.I.............. 47 60 Viscosity, Stormer, grams......... 80 Viscosity, centipoises............. 13 Filtration rate, c.c. per 30 min.a. . . 19.6 22.8 Salt content (chlorides), per cent... 0.13 0.12 pH............................. 8.9 8.9 The Alexander mud was used for the experimental work. Comparison with Curkeet mud indicates a considerably greater dilution but otherwise suggests similarity. The mineral composition and particle-size distribution of Curkeet mud (Table 2) are available (Fancher and Oliphant6). It is suggested that Alexander mud would have a similar composition.

Jan 1, 1943

By R. L. Whitting, George Fancher

A typical drilling mud from the Hastings oil field, Brazoria County, Texas, containing only 8 per cent (dry basis) of material of colloidal dimensions, which is largely illite, was concentrated to a density of 10.2 lb. per gal. and used in this study. The effects of water dilution, treatment with complex polyphos-phates, temperature and the time of heating upon the rheological properties of the mud were investigated. It was found that water plays an important part in chemical treatment and that sodium acid pyrophosphate and sodium tripolyphosphate were more efficient than other complex polyphosphates for chemical treatment. Muds treated with either of these chemicals manifested maximum reduction in viscosity and minimum filtration rates at low concentrations. Furthermore, .mud treated to minimum viscosity with either of these two chemicals was virtually unaffected by heat-treatment. Introduction The drilling of deep wells is dependent upon the use of drilling mud, and problems frequently arise concerning the effects on mud of temperature, prolonged heating and aging. The use of chemicals to control the rheological properties of mud is a well-established practice. Salts of weak organic acids such as sodium tannate or gallate were used at first until the complex phosphates of sodium were found to be more efficient. Consequently, it seemed important to investigate the reaction of a mud to chemical treatment with phosphates, temperature, heat-treatment and aging, particularly since previous work in the laboratory at the University of Texas had provided the particle-size distribution and mineral composition of Hastings mud. Properties or Mud Used in Experiments A large sample of the mud from a drilling well in the Hastings field, Brazoria County, Texas, was obtained directly from the circulatory system. Some of the general physical characteristics of the mud and other data are presented in Table I. Table i.—General Properties of Hustings Drilling Mud Alex- Cur-ander keet Well Well Depth when sample was taken, It.. 5720 5700 Weight. lb. per gal............... 9.5 0.8 Viscosity, sec. A.P.I.............. 47 60 Viscosity, Stormer, grams......... 80 Viscosity, centipoises............. 13 Filtration rate, c.c. per 30 min.a. . . 19.6 22.8 Salt content (chlorides), per cent... 0.13 0.12 pH............................. 8.9 8.9 The Alexander mud was used for the experimental work. Comparison with Curkeet mud indicates a considerably greater dilution but otherwise suggests similarity. The mineral composition and particle-size distribution of Curkeet mud (Table 2) are available (Fancher and Oliphant6). It is suggested that Alexander mud would have a similar composition.

Jan 1, 1943

By H. K. Livingston

A technique has been developed which makes it possible to determine the spreading pressure of liquids and solids, for simple systems. Data for surface tensions, interfacial tensions, spreading pressures, and contact angles for water, heptane, and silica are tabulated.' These results can be applied to the evaluation of capillary rise and displacement pressure in a petroleum reservoir. Appropriate equations are presented and the application of these equations is discussed. The presence of surface-active components affects both capillary rise and displacement pressure and also seems to influence the rate of fluid flow. The purpose of this paper is to supplement and bring up to date the last article on the subject of the surface chemistry of petroleum reservoirs, that of Garrison in the 1935 Oil and Gas Journa1.1 A discussion of the "adhesion tension" concept used by Garrison has been presented in another publication,2 together with the reasons for the recommendation that the term "adhesion tension" be abandoned. In view of the fact that some of the data used by Garrison have been superseded by more recent work, it seemed advisable to call attention to this fact and present the more important data currently believed to be correct. In the earlier paper, Garrison set up the equations that 'relate solid-oil and solid-water interfacial tensions to each other, and applied data from Bartell and Miller3 to these equations. However the adhesion tension measurements made by Bartell and Miller involved a confusion of symbols, so that they did not actually measure the spreading pressure, ?s — ?sf.2 The spreading pressure is a convenient method of indicating the amount by which the surface energy of a solid surface is lowered on immersion in a liquid or vapor. Since the initial value of the free surface energy is represented by the symbol ?s and the final value is ?sF, the spreading pressure is ?s — ?SF. A technique has now been developed4 that makes possible the determination of ?s — ?sF for simple systems. This method would be very difficult to carry out with a multicomponent system such as exists in the petroleum reservoir. However, already results have been obtained for ?s — ?sF for water and heptane in contact with silica and graphite. These values will be of the same order of magnitude as those in the petroleum reservoir. Accordingly, it is possible for the first time to discuss the surface-energy relations of the petroleum reservoir on a semi-quantitative basis. Preliminary Generalizations A petroleum reservoir may contain the following four phases: gas, hydrocarbon liquid, aqueous liquid, and solid. The three fluid phases are dispersed through the solid reservoir rock. If gravity were the only force acting, it is obvious that the

Jan 1, 1943