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By R. R. Angel

Drilling rate is a parameter that should be considered in determining the volume requirements for air and gas drilling. The use of past methods which ignore the effects of the solids content upon the pressure and velocity of the annulus flow stream can result in undercalculation of the required volurne by as much as 50 per cent. A vertical-flow equation is presented for determining volume requirements. This equation includes the effect of the solids that are transported up the annulus in the flow stream by incorporating the drilling rate as one of the parameters. The effect of down-hole temperature on required circulation rates is also ana-lvzed. A simple approximate method of determining volume requirements is presented. This method is more accurate than the methods used in the past. Hole cleaning difficulties are analyzed for a recent air drilling job where past methods indicated that - excess air was being used. Sample curves of calculated boitom-hole pressures are presented for air and gas drilling in several hole sizes. INTRODUCTION In certain areas the use of air or natural gas as a circulating medium for drilling oil and gas wells is becoming a common practice. Large increases in penetration rate and bit life are achieved through the use of these media in preference to mud or water. Drilling rates as high as 90 ft/hr have been obtained in shales. The importance of maintaining adequate circulation rate is generally recognized; however, much disagreement exists among drilling operators as to what constitutes "adequate" circulation rate. In quarry drilling, where annular velocities can be accurately determined, an annular velocity of 3,000 ft/min of standard air is required for best results in rocks having approximately the same density as those commonly penetrated in drilling oil or gas wells'. Although this standard air velocity has proven satisfactory for quarry drilling, some oil and gas well drilling operators believe that an equivalent annular velocity of more than 4,000 ft/min is required; others believe that as little as 2,000 ft/min . is sufficient. Much of this disagreement results from determining the required circulation rates with methods which fail to incorporate the drilled solids in an equation which is applicable to vertical flow. Hughes Tool Co. Bulletins No. 23' and 23-A3 present data for determining circulation rates based on the Weymouth formula. These data do not include the drilling rate as a parameter and, therefore, neglect the effect of the solids being transported up the annulus. In spite of this apparent defect and the fact that the Weymouth formula is not applicable to vertical flow, the Hughes data have well served the drilling industry in many areas and are important and timely contributions to the science of air and gas drilling. The Hughes data purposely omit a correction for increasing down-hole temperature. At slow drilling rates this effectively compensates for the use of a formula which is not valid for vertical flow; however, volumes determined by the Hughes method are not sufficient to support rapid drilling rates at moderate and great depths. For example, Phillips Petroleum Co.'s Cauthorn "D" No. l in the Vinegarone field for Val Verde County, Tex., was air drilled from 1,500 to 9,300 ft using a compressor delivering 1,400 cu ft/min. The 8 3/4-in hole was drilled with 5-in. drill pipe, and drilling rates as high as 90 ft/hr were obtained between 7,000 and 9,300 ft. No water or caving hole was encountered. At 7,728 ft it was necessary to wash-out 60 ft of cuttings to reach bottom after a trip to change bits. At 8,130 ft a twist-off occurred and the drill col-lars were stuck in drill cuttings. These difficulties indicate that the 1,400 cu ft/min of air was not sufficient to keep the hole clean. Hughes data indicates that 1,180 cu ft/min is sufficient to produce an annular ve-

Jan 1, 1958

By Blake M. Caldwell, Harrold D. Owen

The continued use of permanent-type, we11 completion Iras pointed LIP the need for more powerful through-tubing perforating equipment. A new expendable shaped charge perforator has been developed in which the charges are run through the tubing in a vertical position and then opened out to a horizontal position when at the desired shooting zone. The performance of this new tool is comparable to that of conventional casing type perforators. This paper describes the new tool and its applications. Performance data in targets rind under various actual well conditions are presented. INTRODUCTION The general acceptance and increasing use of pernianent-type well completion by the oil industry has indicated the need for through-tubing perforating equipment with performance comparable to that of conventional casing type perforators.'.' To achieve the performance desired, a new, expendable, shaped charge perforator has been developed with adequate power for effectively perforating both 51/2-in. and 7-in. casing below tubing. This has been accomplished without resulting severe damage to the casing and can he obtained under extremes of pressure and temperature. The design of this new tool is a radical departure from previous concepts of tubing guns since it was felt that the two major limitations imposed by previous designs severely handicapped performance. The first of these limitations was the restriction imposed upon the length of the charges by the necessary small inside diameter of the carrier. This resulted from the necessity for compromises in designing a hermetically sealed gun small enough to allow free passage through 2-in. tubing, yet with sufficient wall thickness to withstand some minimum pressure. In an effort to overcome this limitation, the charges were in some cases placed at an angle with the axis of the well with resulting loss in effective depth of penetration. The second limitation concerned the extreme distance of the charges from the casing when the gun was fired. An example of the latter situation is demonstrated by the fact that a conventional 13/4-in. tubing gun centralized in 51/2-in., 17-lb casing has a clearance of more than 1-9/16-in. on all sides. This means that a considerable portion of the force from each charge must be expended in penetrating this 1-9/16-in. of well fluid before it even reaches the casing. With the gun centered in 7-in., 23-lb casing, the amount of fluid penetration required of each jet is in excess of 21/4-in. In a situation where the 13/4-in. gun is touching one side of the 51/2-in., 17-lb casing, the jets from the charges on the opposite side have more than 3%-in. of fluid to penetrate. A similar situation in 7-in., 23-lb casing necessitates the penetration of more than 4-9/16-in. of fluid. The penetrating effect of the charges is severely impaired in passing through so much fluid. Under such conditions, there is usually insufficient force left to penetrate the casing. Previous studies have shown the decided disadvantage of having to shoot through such an excessive quantity of well fluid.'.' The problem. then, was how to position large powerful charges close to the casing prior to firing and still manage free passage through 2-in, tubing. The solution appeared to be in some method of folding sealed charge units in an open type, expendable. 13/4-in. carrier for travel through the tubing, and unfolding them upon their arrival at the shooting zone in the casing. It was desired to control the mechanism electrically from the surface through the regular shooting cable, making the release of the charges independent of the physical characteristics of the well, yet with a provision to prevent the gun from firing until the

Jan 1, 1955

By Leendert de Witte, Fred J. Radd

In many areas caring failures can be directly related to electrical currents observed in the casings. It is the thesis of this paper that the observed casing currents are mainly due to electrochemical potentials of the type in evidence on spontaneous potential curves of electrical logs. The general nature of these potentials are discussed and an equivalent circuit is given for current and potential distributions around open holes. The casing forms a short circuit to these potentials and tends to average the effects of local cells. The case of casing corrosion opposite the Dakota water sands in the salt-mud area of Kansas is discussed anil used us a qualitative, illustration of the relation between SP's and casing currents. A method of quantitative derivation of casing current distribution frorn electric log SP curves, using linear transform theory, is described and results are compared with a measured current profile. The effects of hydrogen over-potentials at the cathodic portions of the pipe are considered and some laboratory data are given in support of conclusions regarding the over-1.01tuge.s. INTRODUCTION To date an appreciable amount of work has been done on the measurement of oil well casing currents and on the correlation of the anodic portions of the current profiles with corrosive casing failures. Speculations on the origin of the casing currents have, however, remained rather vague; and although almost every plausible cause has been mentioned, there is to the writers' knowledge no clear-cut expose' on the details of the causes of the corrosive currents in the literature. A study of current surveys and casing failures in the N.W. Burnett field, Ellis County. Kan.. indicated the probability that concentration cell emf's between the Wellington salt section and the relatively fresh waters in the Dakota sands were a major cause of the corrosion currents. A more general concept evolved upon analysis of the severe corrosive conditions in the Pleistocene sands in the Ventura Avenue and San Miguelito fields in California. In this area no major variations in the salt content of the formation waters occur and yet large casing currents are observed. An explanation is found in the fact that the local spontaneous potentials which are set up due to concentration contrast between the drilling fluid and the connate water are short circuited when casing is set. The very conductive path through the casing increases the magnitude of the currents and has the tendency to average local sources over fairly large intervals. Current will flow between the sections that are predominently shaly and the sections that are mostly sandy. At the places where the current leaves the pipe, corrosive attack will occur. This same phenomenon will be present wherever unprotected pipe is set through sections that show large SP kicks on the electric logs over reasonably thick interval~. GENERAL- NATURE OF THE SPONTANEOUS POTENTIALS When a sequence of sedimentary rocks is penetrated by a drill hole filled with a mud which has a different salt concentration from that in the formation waters, various types of electrochemical potentials are established between the formations and different parts of the mud column. Opposite clean sand sections. a simple liquid-liquid junction potential will be observed; while opposite argillaccous formations, a membrane potential, often referred to as shale potential, will be established. The first quantitative analysis of these emf's in terms of liquid junction and membrane potentials is due to Wyllie.1

Jan 1, 1956

By R. E. Hurst, D. E. Ramsey, J. M. Moore

The "frac" method of well stimulation has been applied successfully to all producing formations in the Permian Basin area. During the five years since its development, many changes and improvements have been made in treating materials. procedures, and equipie11t. A number of fluid carrying agents, having different physica1 and chemical properties, have been developed to meet variorus well requirements. The current trend is toward larger gallonage treatments, employing higher injection rates. The use of "down-the-casing" techniques has greatly reduced high surface working pressures, attributable to friction losses resulting from injection throrugh tubing. Petrographic studies of various Permian Basin formations, coordinated with laboratory and well log data, have been found a valuable guide in planning frac treat111o1t.s. A knowledge of the extent (and orientation of naturally occurring fractures and planes of weakness in the formation, aid in predicting the ultimate drainage pattern resulting from the frac treatment. INTRODUCTION The South Permian Basin covers an area in Wcst Texas and New Mexico about onc-half the size of the state of Texas, This vast region has been called the "Permian Basin" for so long that the term will he used here. It includes an area south of the Matador Arch. approximately 250 miles wide and 300 miles long. Structural features of importance within the basin are the Northwest Shelf, Eastern Platform, Midland Basin, Central Basin Platform, and Delaware Basin. The principal producing formations include sand, limestone and dolo-mite, with lesser amounts of shale, anhydrite. chert. and various silicates. All of the producing formations in the Permian Basin have responded to some type of frac treatment. Essentially, a frac treatment may be defined as the injection, into a formation. of a fluid carrying agent containing a particulated solid (usually sand), for the purpose of increasing production. The application of this method of well stimulation to many differing Permian Basin reservoirs has necessitated numerous changes and improvements in carrying agents, solids, service equipment. well equipment. and treating techniques. CARRYING AGENTS A number of different types of fluid carrying agents have been developed since the introduction of the frac method of well stimulation. These agents have different physical and chemical properties, and in many cases the extent of production increase derived from the frac treatment depends on the choice of fluid carrier. Unfortunately, due to many different systems of nomenclature used in the oil field, these differences are not always recognized by the oil Operator. In general, carving agents may he divided into the following broad classi-

Jan 1, 1956

By R. A. Cunningham, A. S. Murray

If a dense fluid such as mud or water is used for circulation, the formation drilled is influenced by a hydrostatic pressure. This pressure depends on hole depth arid drilling fluid density. Laboratory tests indicute that drilling rates in many forri~ations are decreased with increased pressure,—in some cases as much as 90 per cent. A comparison between laboratory and field tests indicates that drilling fluid head affects drilling rates in the field approximately the, same as in the laboratory. Drillirrg rates of many formations are increased by reducing drilling fluid head. INTRODUCTION For many years it has been noted that field and laboratory drilling rate tests did not agree even when the formations tested were the same. For instance, tests of some shales by the Hughes Tool Co. laboratory indicated drilling rates approximately 20 to 30 ft/hour, whereas in the ground this shale would drill only 3 to 5 ft/hour. A possible reason for this discrepancy is the effect of the high pressure which the drilling fluid exerts against the formation at the bottom of the hole. Consider a small element of rock (Fig. II that is to be removed by a rock bit. If the hole is filled with mud or water. the upper surface of the rock element is subjected to a pressure which depends on hole depth and fluid density. The mass of earth around this rock element presses against the circumferential surface and the lower surface. Because of the probability of shearing stresses between the rock element and the surrounding rock, this element is not under true hydrostatic stress. However, as a first approximation for test purposes the rock element was assumed to he under hydrostatic stress. The effect of hydrostatic pressure on some physical properties of rock has been studied.1,2,3 These tests show that the "differential" compres-sive stress:': necessary to cause rup- ture in rock cylinders is greater when tested under high hydrostatic pressure than when tested under atmospheric conditions. These tests were made with pressures greater than 20,000 psi which is in excess of those normally encountered in oil well drilling. Similar tests were made by the Bureau of Reclamation' using pressures equivalent to those encountered in oil well drilling. Again the "differential" compressive stress necessary to produce failure increased with increasing hydrostatic pressure. These tests indicated that drilling rates would probably decrease. Correlation between these tests and drilling tests was not practical. The purpose of this work is to study the effect of mud column pressure on drilling rate, assuming that the material drilled is in a state of hydrostatic strcss. This problem was initially investigated in the laboratory using variable bit loads and confining pressure;. Confirmation of laboratory results was obtained in the field from a series of carefully controlled drilling tests. Because of the necessity of testing many different types of formations. only results from representative formations will be presented here.

Jan 1, 1956

By T. O. Allen, J. H. Atterbury

Laboratory and field tests during the past five years indicated considerable variation in the penetrating power of commercially available gun perforators. Many of the guns which achieved inadequate penetration in these tests have since been improved. However, recent productivity tests indicated the possibility of inadequate penetration or, at least, ineffective penetration in some wells. Laboratory experiments under simulated well conditions have demonstrated considerable plugging of the perforations, apparently as a result of factors associated with the shooting process and/or the drilling mud in the well at the time of perforating. The restrictions to flow per unit of hole depth caused by this plugging appears to be greater for jet perforators than for bullet guns of comparable diameter; however, because of the greater depth of penetration obtained with the jet guns, the total flow rates appear to he approximately equal. Limited testing with an experimental shaped charge suggests that less shot hole restriction and greater flow rates may result from larger-diameter perforations or other factors related to charge design. INTRODUCTION Gun perforating has been accepted for a number of years as a routine well completion method which is often preferred since it permits more selective operation of producing zones. Nevertheless, questions have continued to arise as to the effectiveness of the communication paths established between the productive formation and the interior of the casing. The basis for these questions has generally been failure to obtain anticipated fluid production rates through gun perforated completions in specific wells. These low productivities, together with the frequent recovery of bullets from well bores, were considered strong evidence of inadequate penetration. Laboratory investigations of the penetration performance of many of the bullet guns available as late as 1948 gave support to these indications. Subsequent electrical analog studiesl,2,3 indicated that the depth of penetration required to provide productivities equivalent to open hole was beyond the capacity of most bullet perforators evaluated in the early laboratory penetration tests. These results, together with the advent of the shaped charge in the field of oil well perforating, stimulated the interest of both oil operators and service companies in gun development. Improvements in gun design resulted in jet and bullet guns which appeared to be capable of providing sufficient penetration for most perforating jobs. However, some wells failed to yield satisfactory fluid production even after being perforated with the more powerful guns, again raising the question as to the effectiveness of the perforating operation. This fact, together with preliminary shooting into targets prepared with formation cores, indicated that factors associated with the perforating process and/or the fluids in the well bore at the time of shooting may reduce effective formation penetration and thereby decrease well productivity. These laboratory and field data prompted another phase in the investigation of the effectiveness of gun perforating: a program to determine the extent and seriousness of perforation plugging under simulated well conditions.

Jan 1, 1955

By J. D. Sudbury, J. E. Landers, D. A. Shock

The external corrosion of casing is one of the most important problems facing the present day production man. A 1953 NACE report' estimated the annual cost of casing corrosion at $2,200,000 in 22 fields studied. The fields represented only 10 per cent of the wells in the United States. It was significant that 77 per cent of the failures reported were due to external corrosion. A variety of means for combatting the casing corrosion problem have been discussed in papers such as the NACE survey' mentioned previously. No attempt to revicw these will be made in this paper. Thc scope of this paper has been limited to a discussion of the following major items: (I) an instrument for studying external electrolytic corrosion; (2) use of this instrument to determine the quantity of protective current required to prevent corrosion of casing; and (3) problem of accelerated external corrosion of the oil string at the base of the surface string. ELECTROCHEMICAL MECHANISM OF CORROSION It IS gcncrally belleved that one major cause of external corrosion is the existence of electrolytic cells operating between various formation waters. A theoretical discussion of the role of earth potentials in casing corrosion has been presented by L. de Witte and F. J. Radd.2 A brief picture of the electrolytic corrosion action between two differcnt formations (A and B) is presented in Fig. I. This picture is a review to many but is given to insure clarity. In the anode area, oxidation takes place as iron ions go into solution in formation A as a product of corrosion. In the cathode area. reduction takes place and hydrogen atoms are formed at the boundary between the pipe and formation B. The flow of electrons. as indicated. is into the pipe at the anode or corroding area and out of the pipe into the formation at the cathode. In order to conform with regulations of this journal, the flow of a conventional current (I! is also indicated in this sketch. All subsequent references will be to this so-called conventional current flow and will be indicated by the symbol (I). As this action takes place the layer of hydrogen developed on the cathode offers a resistance to the flow of current in the cell. It is said (hat the cathode has been polarized. This polarizing film can be rcmoved by addition of a so-called dcpolarizing agent which reacts with and removes this hydrogen film. Such an agent must be present in ordcr for this corrosion reaction to go at a rate sufficient to cause a severe corrosion problem. The two common depolarizing agents are: (I) oxy-sen. which readily reacts with hydro gen to form water, and (2) certain bacteria which use atomic hydrogen as part of their life process. It is not difficult to explain the presence of these agents. Oxygen may be present in some very shallow formations. Sulfate reducing bacteria are found to exist in nearly any ground where mud pits might be dug. THE CASING POTENTIAl-PROFILE Instrumentation A sketch of the equipment* uscd in determining casing potential profiles is shown in Fig. 2. The tool is run in the hole using a hoist truck with a three-conductor cable. This tool must be run with tubing and rods out of the hole and should be run with the flow line disconnected. By proper choice of electrode size it can be run in any size casing. The electrodes must be run in an open hole or a hole filled with oil. Measurements cannot be made while immersed in water. The tungsten carbide-tipped knives serve as the electrical robes and arc spaced 25 ft apart. The potential difference along a 25-ft section of casing is measured with a potentinmeter to an accuracy of about 5 mv. Current flowing in the pipe can then

Jan 1, 1956

By E. E. Anderson, R. L. Newacheck, J. Kohl

Radioactive materials were used underground before the advent of the nuclear reactor. Radium containing ores have been mixed with cements and other materials for later location in oil wells by gamma ray logging since 1940.1 Perforating bullets have been marked with radium salts,, and radioactive materials have been added to drilling muds to find the cause of "lost circulation."' More recently colloidal suspensions of radioactive cobalt-60 and silver-1103 and solutions of 1-1314 have been used in waterflooding operatiorns to determine injection profiles, flow paths and water velocities. In this paper a recent and interesting underground tracer application is discussed. Development work and field engineering were carried out under the direction of Tracerlab, lnc., with assistance from personnel of the client. A gaseous tracer, argon-41, was used in an attempt to determine the cause of leakage from an underground gas storage reservoir. STATEMENT OF PROBLEM This gaseous tracer application was carried out for the Natural Gas Storage Co. of Illinois. This company has developed an underground gas storage field 1,750 ft below the surface of the earth near the village of Herscher, Ill., about 60 miles south of Chicago. The total volume of gas stored in the field was estimated to be about 13 billion cu ft in the spring of 1954. The field has a maximum estimated storage capacity of 90 billion cu ft. The gas is contained in the Galesville sandstone, previously a water bearing formation of about 25 per cent porosity. The water as it is pushed out by the gas forms a barrier for the gas around the edge of the reservoir. Over the top and beneath the bottom of the reservoir are located several layers of impervious rock, which barring cracks or unplugged and unknown wells should act as seals. Twenty-one injection and withdrawal wells were drilled into the Herscher reservoir and gas injection was begun during the summer of 1953. After a few weeks of gas injection, evidence of gas leakage was detected at the surface; water wells began bubbling and losing prime, and dry spots in the fields indicated gas leakage from uncharted oil wells. In every case, the leakage could not be traced back any further than the water bearing formations a few hundred feet below the surface. An extensive search was made to locate uncharted oil wells which were believed to be possible channels for the gas from the storage formation to the water containing formation. Long-time residents in the area assisted in the location of several abandoned oil wells. The wells when located were cleaned out and either used as vent wells to relieve the gas pressure in the water formations, or were plugged with cement. None of the wells even approached depths which would endanger the soundness of the storage reservoir. All of the injection wells were tested for leaks in the casings by conducting neutron surveys and by other techniques. To detect any leakage up through the cement-filled annulus surrounding the casing, a section of the casing wall in one well was milled out. Then, plugs were installed above and below the cut-out section and pressure applied to the annulus, which proved conclusively that the cement was sound in that well. The well was then plugged with cement and abandoned. In another well, ammonia was injected into the well and a temperature log was made. It was hoped that a leak would be re-

Jan 1, 1956

By C. O. Bundranl, Peter Dehlinger, W. H. Browne

Brief laboratory investigations are described which attempt to determine optimum .sand concentrations in gel-sand and oil-sand1 well-treatments. The investigations apply to the case where sand acts as a propping agent in formation fractures. Both analytically and experimentally it is demonstrated that optimum sand concentrations can be defined. It is difficult to translate laboratory results to field treatments, however, since the relative distribution of sand and fluid in fractures may not be the same as injected. This is because fluid may penetrate the furtherest narrow portions of fractures, which would not pass sand. Optimum concentration of a monolayer of Ottawa sand in fractures of 0.025-in. width at the usual range of pressures encountered in treatments appears to be about 95 to 2 lb/gal. of gel. An investigation of abrasion of rock-walls by sand in treatments, described in the Appendix, shows that such abrasion is not probable in significant amounts. INTRODUCTION Experience in the Spraberry formation of West Texas, as well as in other formations, has shown that. sand is a necessary and vital part of gel-sand and oil-sand treatments. Many observers of treatments have also concluded that there seems to be an optimum range of sand concentration for these injections. Brief laboratory investigations were made at Battelle Memorial Institute to study flow in fractures with different sand concen- trations. To investigate the existence and range of optimum concentrations in the laboratory, however, necessitates knowledge of the mechanism by which the sand aids in increasing subsequent production. The action of sand in fractures is usually thought to be either that of a propping agent, thus providing a greater effective formation permeability; that of an abrasive in eroding fill material in fractures; or that of an abrasive eroding rock-wall irregularities along fracture surfaces. Investigations described in the Appendix show that sand does not appear to erode rock-wall materials appreciably. In a subsequent paper it is reasoned, at least for the Spraberry formation of West Texas, that the primary action of sand is not in removing fill materials in fractures. In this formation, and probably others, too, the main effect of sand appears to be that of a propping agent. Both analytical and experimental investigations were made for the case of a monolayer of sand acting as a propper, in which sand concentrations were determined that would, after treatment, permit flow of the maximum quantities of oil from the formation into a well. If too few sand grains are injected into fractures in which the bottom hole pressure has decreased appreciably below the original formation pressure, the confining pressure in the formation may become relatively large, thus compress the rock-walls around the sand grains, essentially close fractures, and so decrease the subsequent flow of oil. Similarly, if too much sand is used, the flow of oil will he impeded by the volume of sand present. THEORY Although an analytical approach to determining optimum sand concentrations involves gross assumptions.

Jan 1, 1955

By L. E. Wilsey, W. G. Bearden

This paper presents results of analysis of the effect of fracturing on initial flow rates and on ultimate recoveries from low capacity oil formations. This analysis shows that even in formations of permeability as low as 0.1 md, large fracture treatments can yield oil recoveries and production rates approaching those of high permeability formations. Field production information is shown which supports the analytical work. INTRODUCTION Often hydrocarbon bearing formations are discovered which, while they are known to contain large quantities of oil, will not produce at commercially attractive rates without special well stimulation. Attempts to solve this problem led to the development of such techniques as underreaming, shooting, acidizing, and recently hydraulic fracturing. These methods of stimulation have been highly successful in many fields. All of these treatments, however, affect only the pay section near the well bore and therefore owe their success to circumventing and overcoming local permeability reduction about the well bore. It has been the belief that in treating wells to stimulate production in which there is no permeability reduction near the well, the maximum possible production rate increase would be of the order of two or fourfold. Hence, it has been concluded that fracture treatment of uniformly low capacity (permeability times thickness) formations could meet with but limited success. It is the purpose of this paper to show that the use of fracture treatments much larger than usually used can yield commercially attractive producing rates and high recoveries even in formations of permeability less than 0.1 of a md. PROCEDURE In order to illustrate the effects of fracturing, an analytical study of some hypothetical systems was made in which one factor at a time was varied to show what is important in recovering oil from fractured wells. It was assumed that a horizontal fracture of relatively high fluid-carrying capacity extended from a well bore. The presence of such a fracture will cause a marked influence on the flow pattern and pressure distribution in the formations, with the net effect being to reduce tremendously the resistance to flow into the well bore. A diagram of the resulting flow pattern and pressure distribution is illustrated in Fig. 1. Immediately after production commences, the principal flow of fluid is vertically from the formation flanking the fracture, into the fracture, and then into the well. After sufficient oil and gas have been produced to lower the pressure in the formation adjacent the fracture, oil and gas will begin to flow in a radial manner into the fracture from the formations beyond the end of the fracture. In calculating the performance under such conditions. the material balance or conservation of matter equation and equations of flow were solved simultaneously by a stepwise method of calculation. Flow rates were found by determining the pressure distribution, as illustrated

Jan 1, 1955

By C. C. Nathan

Data are resented on the physical properties of five waxes obtained from fields in Texas and Louisiana in which "parafin" troubles are being experienced. The crude parafin was fractionated into three components, voluble in cold acetone, soluble in boiling acetone, and insoluble in boiling acetone. The acetone insoluble fraction was found to consist essentially of straight chain parafin hydrocarbons in the molecular weight range 525 to 700. Solubilities of the purified high molecular weight parafins were determined in a number of solvents. It was found that in hydrocarbon solvents, including crude oil, solubilities could be calculated satisfactorily by use of ideal solubility relations. In chlorinated, and oxygenated solvents, large deviations from ideal behavior were observed. These deviations could be partially correlated with the internal pressure of the solvent. INTRODUCTION A problem encountered in many producing oil fields is that of "paraffin" deposition. The problem refers to the deposition of material from the crude oil onto tubing, pumping rods, flow lines, or other material contacted by the crude. This problem has been recognized for nearly a hundred years, and numerous investigations have been reported on its causes and prevention or alleviation. One of the more comprehensive of such investigations was published by Reistle1 in 1932. A few of the salient findings of his report are briefly as follows: The term "paraffin" as used to describe this problem refers to the deposit of carbonaceous material which is not soluble or dispersible by the crude oil under the conditions where deposition occurs. The "paraffin" normally consists of high molecular weight paraffin hydrocarbons, both straight chain and branched, resins and asphaltic materials of undetermined nature, occluded oil and water, and possibly sand. In consistency, the deposit may vary from a soft, sticky material, to one which is hard and brittle. Deposits are usually black, although lighter colors are sometimes observed. Under the conditions of temperature, pressure, and crude oil composition occurring in the underground reservoir, the paraffin is in suspension or solution in the crude. As the oil flows to the surface, there is generally a reduction of temperature, pressure, and the amount of dissolved gases contained in the oil. Reduction of temperature and gas break-out were shown by Reistle to be factors causing reduced solubility of the paraffin in the crude. Thus, as the crude containing paraffin rises to the surface and flows to storage tanks at atmospheric temperature, the solubility of the paraffin may be exceeded. Deposition will begin at the point in the system where the temperature of the system falls below its cloud point, and continue as long as there is a further drop in the solution power of the crude for the paraffin. The severity of the deposition as well as the location of the bulk of the deposition, i.e., in subsurface or surface equipment, will depend on the amount of paraffin originally in the crude, the manner in which pressure and temperature of the crude

Jan 1, 1956

By C. J. Rodgers

The present day success of gravel packs to prevent or retard the migration of unconsolidated sands into the well bore is due to: (I) the use of a saline or non-aqueous, nonsolids drill fluid, (2) proper preparation of the well bore prior to gravel packing, and (3) pressure placement of the gravel. The experience gained from the "pressure pack" method of gravel packing indicates that sand-free fluid production can be maintained for a length of time sufficient to make the operation economically attractive. Data pertaining to the first 15 wells so completed by Gulf indicate that for each dollar spent to effect the completion, there will be a return of more than $2.92. The pressure pack technique of gravel packing is essentially the placing of gravel in and adjacent to the producing formations. This is done with fluid pressure and by the use of a drill fluid that will permit partial or complete loss of returns to the formation during placement. This technique was first intentionally used by Gulf in May, 1950, and since that time has been applied in more than 90 wells. Other advantages claimed for this type of completion are that the pressure placement of the gravel has a scouring effect on the casing perforations, that additional drainage channels to the well bore are created, and that the possibility of shifting of the formations adjacent to the casing is minimized and possibly prevented. During the past few years, the use of gravel to prevent or retard the migration of unconsolidated sands into the well bore has met with a favorable degree of success. Numerous methods and techniques of "gravel packing" have been used, each having its own relative merits, and with varying results. M. L. Cashion1 in 1939 ably reviewed the history of gravel packing to that time. As stated in his paper, ". .. the idea of gravel packing wells is not new." During the period 1939 to 1949, very little if any progress or change in technique in this type of completion was made. However, it was noted in some cases that during the placement of gravel, if there was a loss of drill fluid to the formation, there was a corresponding loss of gravel to the formation. Also, it was noted that in those gravel-packed completions (opposite casing perforations) that "sanded up," there was found to be an absence of gravel in the annular space between the liner and casing, although gravel had previously been placed in this space and no gravel had been removed from the well at the surface. These findings resulted in the placement of gravel with fluid pressure and by the use of a drill fluid that would permit partial or complete loss of returns to the formation during placement. Pressure placement of gravel became an accepted practice in late 1949 and early 1950. Another fact brought to light that has contributed to the current success of gravel pack completions is that drilling fluids containing solids will to some extent cause plugging of the screening medium or blocking of the producing section. The removal of these solids by chemical action, mechanical action, or a combination of the

Jan 1, 1955

By R. L. Perrine

The rise of drain holes drilled from a well to improve productivity is becoming increasingly common. This paper presents data on the productivity increase that may he expected. The data were obtained by use of an electrolytic tank mode1 of a reservoir. Parameter varied in the study to show their effect on productivity include the length, number, and arrangement of drain holes, formation thickness, and damage near the well-hore. The most important results are that very large increases in productivity can be expected only ill damaged wells. The distance, to which drain holes penetrate is of primary importance. Additional length is more effective than increasing the number of drain holes. INTRODUCTI O N In planning the use of drain holes to improve productivity, it is important to he able to estimate the increase in production that can be obtained for a given expenditure. It is also important to know what combination of parameters related to the use of drain holes can he chosen to give the largest production increase. This paper presents data on the productivity increase that may be expected, as obtained by use of an electrolytic tank model of the reservoir. In this study, :! number of parameters were varied to show their effect on productivity. These included the length, number, and arrangement of the drain holes. The presence or absence of a damaged zone of low permeability around the well-bore and the thickness of the producing formation were also considered. The productivity increase that might be expected due to drain holes is presented as the ratio: productivity of a well after drain holes are drilled and completed to the productivity of the same well in an undamaged state without drain holes. The symbol Q/Qo is used to represent this productivity ratio. Thus, the comparison in each case is with a formation of uniform and undamaged permeability. Additional notation includes I;, for the radial extent of the damaged zone, which is assumed to be cylindrical and concentric with the wellbore. Thus the effect of an actual block is approximated by a discontinuous varia-tion in permeability. For purposes of this paper, the permeability within the damaged zone, denoted by kb, is assumed to be 1/25 that in the remainder of the formation, or k. A necessary assumption in making comparative tests using an electrolytic model is that reservoir flow behavior can be approximated by single-phase, steady-\tate flow according to Darey's Law. In addition, the formation must be assumed to be homogeneous with equal horizontal and vertical permeability. The well-hore diameter in this study is assumed to be 11¾ in. and the drainage radius of the well equal to 500 ft. The drain holes are considered to have been completed without damage. THE ELECTROLYTlC MODEL 'She producing formation was modeled by forming a sheet of phosphor-bronze into a cylinder 40% in, in diameter to represent the boundary of the drainage area. This was enclosed in a waterproofed plywood box, and the box filled to an appropriate level with a dilute sodium chloride solution. Solution concentration was adjusted to give a total resistance from

Jan 1, 1956

By J. B. Clark

The oil industry has long recognized the need for increasing well productivity. To meet this need, a process is being developed whereby the producing formation permeability is increased by hydraulically fracturing the formation. The "Hydrafrac" process, as it is now being used, consists of two steps: (1) injecting a viscous liquid containing a granular material, such as sand for a propping agent, under high hydraulic pressure to fracture the formation; (2) causing the viscous liquid to change from a high to a low viscosity so that it may be readily displaced from the formation. To date the process has been used in 32 jobs on 23 wells in 7 fields, resulting in a sustained increase in production in 11 wells. INTRODUCTION Need For Process Although explosives, acidizing, and other methods have long been used, there still exists a need for artificial means of improving the productive ability of oil and gas wells, particularly for wells which produce from formations which do not react readily with acids. This paper discusses the development of a hydraulic fracturing process, "Hydrafrac", which shows distinct promise of increasing production rates from wells producing from any type of formation. The method is also considered applicable to gas and water injection wells, wells used for solution mining of salts and, with some modification, to water wells and sulphur wells. Requirements of Process In considering such a possible process, it appeared that certain requirements must be met. Some of these are as follows: A. The hydraulic fluid selected must be sufficiently viscous that it can be injected into the well at pressure high enough to cause fracturing. B. The hydraulic fluid should carry in suspension a propping agent, such as sand, so that once a fracture is formed, it will be prevented from closing off and the fracture created will remain to serve as a flow channel for oil and gas. C. The fluid should be an oily one rather than a water-base fluid, because the latter would be harmful to many formations. D. After the fracture is made, it is essential that the fracturing fluid be thin enough to flow hack out of the well and not stay in place and plug the crack which it has formed. E. Sufficient pump capacity must be available to inject the fluid faster than it will leak away into the porous rock formation. F. In many instances, formation packers must be used to confine the fracture to the desired level, and to obtain the advantages of multiple fracturing. Development of Process As a necessary step in the development of this process, it was deemed advisable to determine if the Hydrafrac fluids were actually fracturing the formation or whether these special fluids were merely leaking away into the surrounding formation. To determine this, a shallow well, 15 feet deep, was drilled into a hard sandstone. Casing was set, the plug drilled, and the well deepened in the conventional manner. A fracturing fluid dyed a bright red was used to break down the formation. Sand mixed with distinctively colored solids was injected into the well with the fracturing fluid to prop open any fracture made in the formation. A simulated gel breaker solution dyed a bright blue was then pumped into the well to determine if the gel breaker would follow the first solution. The results are shown in Figure 1. It was noted that a fracture was formed about the well bore, that the propping agent was transported back into the break, and that the breaker solution did actually follow the fracturing gel out into the fracture. While it is realized that this shallow well test is probably not exactly equivalent to a deep test, the results were interpreted as being a definite indication of what happens down the hole during a Hydrafrac job. Of interest in this connection is an investigation reported by S. T. Yuster and J. C. Calhoun, Jr.' This study, re~orted after the Hydrafrac work was under way, presents some excellent field data supporting the theory of fracturing a formation with hydraulic pressure. METHOD Steps of Hydrafrcu: Process Figure 2 shows a simplified cross-sectional view of a well treated by one version of the process. The first step, formation breakdown, is done with a viscous fluid, usually consisting of an oil such as crude oil or gasoline, to which has been added a bodying agent. Due to availability and price, war-surplus Napalm has been used in the majority of experiments to date. Napalm is the soap which was used in the war to make "jellied gasoline". The next step consists of breaking down the viscosity of the gel by injecting a gel-breaker solution and then after several hours, putting the well back on production. Figure 3 shows diagram-matically, a typical field hookup. The oil or gasoline is unloaded into the 10 bbl. tank shown on the left rear of the truck. This base fluid is picked up by the mixing pump and pumped through the jet mixer, where the granular soap is added. Next it goes into a small mixing tub, from which the high-pressure pump takes suction. The solution is then pumped into the well. The breaker solution is then taken from an extra tank and is displaced into the well immediately following the gel. When required, additional trucks may

Jan 1, 1949

By J. B. Clark

The oil industry has long recognized the need for increasing well productivity. To meet this need, a process is being developed whereby the producing formation permeability is increased by hydraulically fracturing the formation. The "Hydrafrac" process, as it is now being used, consists of two steps: (1) injecting a viscous liquid containing a granular material, such as sand for a propping agent, under high hydraulic pressure to fracture the formation; (2) causing the viscous liquid to change from a high to a low viscosity so that it may be readily displaced from the formation. To date the process has been used in 32 jobs on 23 wells in 7 fields, resulting in a sustained increase in production in 11 wells. INTRODUCTION Need For Process Although explosives, acidizing, and other methods have long been used, there still exists a need for artificial means of improving the productive ability of oil and gas wells, particularly for wells which produce from formations which do not react readily with acids. This paper discusses the development of a hydraulic fracturing process, "Hydrafrac", which shows distinct promise of increasing production rates from wells producing from any type of formation. The method is also considered applicable to gas and water injection wells, wells used for solution mining of salts and, with some modification, to water wells and sulphur wells. Requirements of Process In considering such a possible process, it appeared that certain requirements must be met. Some of these are as follows: A. The hydraulic fluid selected must be sufficiently viscous that it can be injected into the well at pressure high enough to cause fracturing. B. The hydraulic fluid should carry in suspension a propping agent, such as sand, so that once a fracture is formed, it will be prevented from closing off and the fracture created will remain to serve as a flow channel for oil and gas. C. The fluid should be an oily one rather than a water-base fluid, because the latter would be harmful to many formations. D. After the fracture is made, it is essential that the fracturing fluid be thin enough to flow hack out of the well and not stay in place and plug the crack which it has formed. E. Sufficient pump capacity must be available to inject the fluid faster than it will leak away into the porous rock formation. F. In many instances, formation packers must be used to confine the fracture to the desired level, and to obtain the advantages of multiple fracturing. Development of Process As a necessary step in the development of this process, it was deemed advisable to determine if the Hydrafrac fluids were actually fracturing the formation or whether these special fluids were merely leaking away into the surrounding formation. To determine this, a shallow well, 15 feet deep, was drilled into a hard sandstone. Casing was set, the plug drilled, and the well deepened in the conventional manner. A fracturing fluid dyed a bright red was used to break down the formation. Sand mixed with distinctively colored solids was injected into the well with the fracturing fluid to prop open any fracture made in the formation. A simulated gel breaker solution dyed a bright blue was then pumped into the well to determine if the gel breaker would follow the first solution. The results are shown in Figure 1. It was noted that a fracture was formed about the well bore, that the propping agent was transported back into the break, and that the breaker solution did actually follow the fracturing gel out into the fracture. While it is realized that this shallow well test is probably not exactly equivalent to a deep test, the results were interpreted as being a definite indication of what happens down the hole during a Hydrafrac job. Of interest in this connection is an investigation reported by S. T. Yuster and J. C. Calhoun, Jr.' This study, re~orted after the Hydrafrac work was under way, presents some excellent field data supporting the theory of fracturing a formation with hydraulic pressure. METHOD Steps of Hydrafrcu: Process Figure 2 shows a simplified cross-sectional view of a well treated by one version of the process. The first step, formation breakdown, is done with a viscous fluid, usually consisting of an oil such as crude oil or gasoline, to which has been added a bodying agent. Due to availability and price, war-surplus Napalm has been used in the majority of experiments to date. Napalm is the soap which was used in the war to make "jellied gasoline". The next step consists of breaking down the viscosity of the gel by injecting a gel-breaker solution and then after several hours, putting the well back on production. Figure 3 shows diagram-matically, a typical field hookup. The oil or gasoline is unloaded into the 10 bbl. tank shown on the left rear of the truck. This base fluid is picked up by the mixing pump and pumped through the jet mixer, where the granular soap is added. Next it goes into a small mixing tub, from which the high-pressure pump takes suction. The solution is then pumped into the well. The breaker solution is then taken from an extra tank and is displaced into the well immediately following the gel. When required, additional trucks may

Jan 1, 1949

By C. R. Dale

The need for instruments to measure the movement of fluids and gas in wells has been recognized by engineers for many years. Information regarding flow in the producing interval has a direct bearing on completion practices in new wells and also provides information on the production characteristics of the well. Many hours of engineering time are spent in planning and completing wells but knowledge as to whether or not the original planning has produced the desired results has not always been complete. Many questions such as the following often arise: Why is it that two wells are completed under supposedly identical conditions, yet one well is a good one and the other is a poor one? Are the sands that look the best on the electric log contributing to the production? These and many other conditions in the producing well need to be under- stood in order to develop more efficient production practices and to improve on methods of completing new wells. It is the purpose of this paper to briefly describe one type of instrument, outline the methods of running the equipment and show the results of surveys made under various conditions. With an understanding of the use of this type of survey its importance can be evaluated in relation to the problems encountered by the operator. DESCRIPTION OF INSTRUMENT The instrument is a velocity recorder employing a clock-controlled 16mm film for recording the rpm of an extremely sensitive rotor which is rotated by the flow of fluids or gas in a well. The helical-vaned rotor and shaft, weighing one-half of one ounce are an integral unit exposed to the well fluids and are the only moving parts not enclosed in the fluid-tight housing. No packing or fluid seal of these parts is necessary and the shaft is mounted top and bottom on special jeweled bearings. Fig. A is the lower part of the instrument showing rotor and shaft with the protecting housing sleeve removed. The rpm of the rotor is recorded on the moving film by a combination electrical and optical system. The record is a series of dashes on the film, each dash and space representing twenty (20) revolutions of the rotor. (Film record of survey made in California well showing station recordings at various depths.) As the movement of the film is controlled by the clock the number of dashes and spaces in one minute of film travel represents the rpm of the rotor. The range of the instrument is from 0 to 2,500 rprn. The barrel or housing is 1-11/16 in. OD and seven feet long. Various types of expanding fluid traps are attached to the lower end of the instrument to direct the flow through the 1 in. orifice containing the rotor. The fluid trap for upward flow is shown in Figs. B and C. This assembly consists of eight arms with light spring

Jan 1, 1949

By C. R. Dale

The need for instruments to measure the movement of fluids and gas in wells has been recognized by engineers for many years. Information regarding flow in the producing interval has a direct bearing on completion practices in new wells and also provides information on the production characteristics of the well. Many hours of engineering time are spent in planning and completing wells but knowledge as to whether or not the original planning has produced the desired results has not always been complete. Many questions such as the following often arise: Why is it that two wells are completed under supposedly identical conditions, yet one well is a good one and the other is a poor one? Are the sands that look the best on the electric log contributing to the production? These and many other conditions in the producing well need to be under- stood in order to develop more efficient production practices and to improve on methods of completing new wells. It is the purpose of this paper to briefly describe one type of instrument, outline the methods of running the equipment and show the results of surveys made under various conditions. With an understanding of the use of this type of survey its importance can be evaluated in relation to the problems encountered by the operator. DESCRIPTION OF INSTRUMENT The instrument is a velocity recorder employing a clock-controlled 16mm film for recording the rpm of an extremely sensitive rotor which is rotated by the flow of fluids or gas in a well. The helical-vaned rotor and shaft, weighing one-half of one ounce are an integral unit exposed to the well fluids and are the only moving parts not enclosed in the fluid-tight housing. No packing or fluid seal of these parts is necessary and the shaft is mounted top and bottom on special jeweled bearings. Fig. A is the lower part of the instrument showing rotor and shaft with the protecting housing sleeve removed. The rpm of the rotor is recorded on the moving film by a combination electrical and optical system. The record is a series of dashes on the film, each dash and space representing twenty (20) revolutions of the rotor. (Film record of survey made in California well showing station recordings at various depths.) As the movement of the film is controlled by the clock the number of dashes and spaces in one minute of film travel represents the rpm of the rotor. The range of the instrument is from 0 to 2,500 rprn. The barrel or housing is 1-11/16 in. OD and seven feet long. Various types of expanding fluid traps are attached to the lower end of the instrument to direct the flow through the 1 in. orifice containing the rotor. The fluid trap for upward flow is shown in Figs. B and C. This assembly consists of eight arms with light spring

Jan 1, 1949

By Albert D. Brokaw

The accompanying charts are presented to extend and improve a chart published under the title "A Chart to Provide Approximate Correction for Temperature and Deviation from Boyle's Law."' The applicability of this earlier chart was limited by the fact that it was based on the work of Burke and Keyes² and Kvalnes and Gaddy3 whose experiments were conducted with pure methane, the adjustments suggested for natural gases of higher specific gravity were unsatisfactory except within limited ranges of temperatures and pressures, and precise interpolation was difficult. The extensive work of G. G. Brown, D. L. Katz and their associates on the heavier natural gases has provided better bases for the needed corrections, and the present charts. which are based largely on their work, are intended to simplify the computations involved. The design of the charts has been changed by plotting temperatures as a function of pressure and correction factor, on a semilogarithmic or "ratio" grid, which gives fairly even spacing of the graphs and simplifies interpolation. Charts have been prepared for natural gas with specific gravities of .60, .65, .70, .75 and .80. The standard computation for use in estimating the quantity of gas in a reservoir may be expressed as follows: _ PA X 520 X VR ZT where: Q is the volume of gas at 60°F and one atmosphere pressure PA is the absolute formation pressure in atmospheres

Jan 1, 1949

By Albert D. Brokaw

The accompanying charts are presented to extend and improve a chart published under the title "A Chart to Provide Approximate Correction for Temperature and Deviation from Boyle's Law."' The applicability of this earlier chart was limited by the fact that it was based on the work of Burke and Keyes² and Kvalnes and Gaddy3 whose experiments were conducted with pure methane, the adjustments suggested for natural gases of higher specific gravity were unsatisfactory except within limited ranges of temperatures and pressures, and precise interpolation was difficult. The extensive work of G. G. Brown, D. L. Katz and their associates on the heavier natural gases has provided better bases for the needed corrections, and the present charts. which are based largely on their work, are intended to simplify the computations involved. The design of the charts has been changed by plotting temperatures as a function of pressure and correction factor, on a semilogarithmic or "ratio" grid, which gives fairly even spacing of the graphs and simplifies interpolation. Charts have been prepared for natural gas with specific gravities of .60, .65, .70, .75 and .80. The standard computation for use in estimating the quantity of gas in a reservoir may be expressed as follows: _ PA X 520 X VR ZT where: Q is the volume of gas at 60°F and one atmosphere pressure PA is the absolute formation pressure in atmospheres

Jan 1, 1949

By W. E. Bergman, P. G. Carpenter, H. B. Fisher

The conditions under which barium carbonate can be used to remove sulfates from drilling muds are limited The amount of sulfate remaining in solution in the system after treatment with barium carbonate is shown to be a function of the concentration of the carbonate and barium ions and the concentration of other electrolytes. Barium hydroxide may advantageously replace barium carbonate when the contamination is not entirely due to anhydrite (calcium in the system is then stoichiometrically less than sulfate) or when the carbonate concentration is high. The effect of substances such as quebracho, phosphates, and chromates, which form complexes or precipitates with barium, is discussed. INTRODUCTION As the complexity of the operations in drilling for oil has increased, more attention has of necessity been directed to the problems pertaining to the maintenance of good drilling mud properties. As a result, chemical treatment of muds has become an important factor in recent years. Some of these treatments have been designed to eliminate the deleterious effects of contaminants in aqueous mud systems by precipitation or other means. The most common of substances encountered during drilling include sodium chloride, cement, and calcium sulfate while various other contaminants: usually in small amounts, may be introduced from the water, clays, and other materials used in preparation of the mud. In certain cases, for example where continued salt-water flow is encountered or massive anhydrite is drilled, special muds may be used so that the physical properties of the mud will remain satisfactory for drilling. In other cases, it is desirable to remove the contaminants so that soluble electrolytes in the system are maintained at low values. For sulfate contamination, the conlmon practice in the field is to add barium carbonate to precipitate the sulfate as barium sulfate Ordinarily such a procedure gives satisfactory results. There have been important instances, however, where addition of barium carbonate was not effective in removal of soluble sulfates from drilling muds. and it is to these cases that the present paper is directed. While it is generally known that barium carbonate is not always effective in removing soluble sulfates from drilling muds, certain inconsistencies appear in the literature as to the limitations of its use, and little explanation for the limitations are given. Varnell and Kimbrel state that "the treatment (with barium carbonate for removal of sulfate) is simple and consists in maintaining a pH of 9 with caustic soda and quebracho." They caution that concentrations of quebracho greater than 1 lb./bbl. may inhibit the reaction. In another publication', a pH of 10.5 is considered "the maximum desirable," and the indication is that as much as 2.5 lb. quebracho per barrel may be present in the particular mud under discussion. Lancaster and Mitchell5 state that appreciable amounts of phosphates in the mud will inhibit the reaction with barium carbonate and that the phosphate treatment should be discontinued at least 24 hours before addition of the carbonate. Experimental work was initiated to ascertain the factors involved in using barium carbonate for the removal of sulfate contamination in drilling muds. While the experimental data herein reported are limited, they focus attention on the pertinent factors which must be considered for successful treatment. These factors are discussed from a practical and a theoretical view, the latter being supported by equilibrium data found in the literature. Further, it will be appreciated that the factors involved in this specific study will be closely analogous to those in certain of the other chemical treatments which involve a precipitation of the soluble contaminant. A thorough comprehension of these factors should result in a more fruitful application of this type of chemical reaction to the treatment of drilling muds. EXPERIMENTAL A. Reagents Two muds were used during this investigation. For one series of tests, bentonite suspensions were prepared by dilution of a stock suspension containing 8 per cent by weight of bentonite (Aquagel). For another series, a 6.4 per cent ben-tonitic mud weighted to 9.7 lb./gal. with barium sulfate (Mag-cobar) was used. Distilled water was used in all preparations. The quebracho (72% tannin extract) was obtained from the Thompson-Hayward Co. of Tulsa and contained 11.4 per cent moisture (105 C.). All other materials were reagent grade, and concentrations were corrected for water of crystallization, if any. All concentrations are expressed in pounds per barrel (42 gallons). B. Technique The systems — either mud or water — were contaminated with either sodium or calcium sulfate after treatment with the desired amounts of sodium hydroxide and quebracbo. For treatments with barium carbonate an approximately 3-fold excess (5 lb./bbl.) was used over that computed to be required to precipitate all the sulfate as barium sulfate. Barium hydroxide was used in concentrations of 2 lb./bbl. — about

Jan 1, 1949