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By Joseph Jensen

Recent developments related to petroleum engineering discussed in this paper are: 1. Drilling wells in with oil or the use of chemical compounds or (Imud solvents" for removing rotary mud from wells in order to increase or make possible oil production. 2. Comparison of results of electrical logging methods in locating water, as shown in a recent test on a well in the Los Angeles Basin. 3. A new method for logging formations through casing, known as the Stratagraph. Drilling Wells in with Oil or the Use of Chemical Compounds or Mud Solvents During the time that the California fields showed high gas pressures, the pressure of the gas within the formation was sufficiently great to break down the mud wall or cake formed while the well was drilling. That this did not always occur was demonstrated by the fact that in some of the older fields new wells sometimes had substantially higher initial productions than other wells near by. The explanation seemed to be that some sands were mudded off in the original drilling. Their pressure was then not great enough to break down the mud wall in competition with the higher pressure of the sands, but the situation reversed itself so that a later well benefited by the pressure in these originally weaker sands. As time passed, in wells deeper than 5000 ft. the difficulty of bringing wells on production became more pronounced. This led to a hunt for substitutes, of which a number have been tried. The one that has proved most successful in our experience at Ventura is known as the Nobs solvent. At well No. 1 of the Associated-Ventura Land & Water Co. when it was recompleted in February 1936, about 10 days were spent in trying to bring the well in in the regular manner, but only about 113 bbl. of water could be swabbed from the well, and even this quantity decreased as time passed. The Nobs solvent was spotted in the bottom of the hole opposite the perforations, inverted Guiberson swab rubbers were used on the drillpipe and the hole was down-swabbed in stages, beginning

Jan 1, 1937

By Byron B. Boatright

The energy which causes oil and gas to flow from a reservoir formation into a well depends upon a differential between the formation pressure and the pressure at the well face. This differential pressure may be the result of any one of at least three forces, or a combination of them. Gas under pressure in an oil-producing formation (part of the gas may be in solution and part in contact with the oil) is the principal source of energy for producing oil in most fields. In some fields, however, hydrostatic pressure due to water in contact with the oil and/or the force of gravity may be important factors in causing oil to flow into a well. Still another force affecting oil movement is suggested by some students of the problem; the force dependent upon the phenomenon of capillarity. Hydrostatic pressure is seldom the only source of energy in an oil sand, but it is commonly an adjunct to the compressed gas in the formation. Where this condition prevails, increased production may be obtained provided the water encroachment is properly controlled. In addition to the water-drive effect, the hydrostatic head may tend to maintain pressure in the formation by progressively reducing the volume of the reservoir as withdrawals to the surface are made through the producing wells. The action of the force of gravity on the oil in a formation is of relatively small importance, from an energy standpoint, until the last stage of the productive life of a well is reached. This force is the only remaining natural source of energy in some of the eastern fields, but in most of the deep wells of the Mid-Continent and California districts the force of gravity can be precluded as a source of energy, because the wells reach their economic limit of production before the force of gravity becomes an important factor in moving oil to the wells. Since the majority of fields produce oil chiefly by reason of the gas pressure in the oil horizons, the following treatment deals mainly with factors that influence gas-energy relationships. Gas-energy Relationships Formation Pressures The gas pressures existing in oil-producing formations may be the result of a combination of several contributing factors. All fluids under

Jan 1, 1932

By C. E. Beecher

The application of gas or air under pressure to obtain more oil from a sand which has been practically exhausted by ordinary production methods has been practiced to a limited extent for many years. Until recently such methods were confined to the Eastern fields, principally those of Ohio and West Virginia, where in many cases the production obtained after applying pressure for a few years was nearly equal to the total production prior to that time which had been obtained by the usual production methods. As early as 1917, J. 0. LewisL called attention to this method of increasing the recovery of oil and cited the phenomenal results obtained by H. E. Smith, I. L. Dunn and 0. C. Dunn, who pioneered the application of air or gas pressure recovery methods. With this information available it would appear that other oil-producing sections of the country have been extremely slow to realize the advantages of repressuring. However, after a few successful projects in the Mid-Continent area, the oil producers appreciated t' e value of this method for obtaining further and profitable production from their practically exhausted leases and are now making extensive use of it. In general, it has been the practice to apply pressure to the sands when production has declined to a small yield per well. The purpose of this paper is to discuss some of the advantages which may be expected from returning gas under pressure to the oil sands during the early stages of development, before the rock pressure has been dissipated and the gas exhausted, and to stimulate discussion of this subject on which comparatively little actual field data are available. The Function of Gas Gas associated with or dissolved in the oil is the source of energy causing movement of the oil to the well. When this energy is dissipated production ceases. The exception to this general statement is found in fields where hydrostatic water pressure may supply energy after the gas

Jan 1, 1929

By R. S. Christie

Reservoir pressure is the pressure at which a fluid is held in a state of equilibrium in a porous stratum. This pressure may be a result of the genesis of oil or gas and its subsequent migration into and through an adjacent porous stratum, or of hydraulic head. Reservoir pressure is an indication of the potential energy contained in the reservoir, and when it is known the engineer is in a position to use it to advantage in recovering and lifting the oil. It is important to know the pressures in any type of reservoir, but this knowledge is probably of greater value in a limestone reservoir, as at Hobbs, where producing rates or conditions may be more sensitive to changes in pressures. The Hobbs field is in east central Lea County, New Mexico. The discovery well was completed by the Midwest Refining C I. in 1928, but intensive development did not begin until after the completion by the Humble Oil and Refining Co. of No. 1-A Bowers in February, 1930. There are 143 producing wells on approximately 5500 acres. The field has not been defined to the northwest, but a projection of structural contours indicates that the productive area ultimately may cover 7500 acres. The producing horizon is the White or Crystalline lime of Permian age. The top of the lime is found at an average depth of 4000 ft. and the wells penetrate it an average distance of 200 ft. The main pay zone is an oolitic stratum about 25 ft. below the top, and varies from 2 to 15 ft. in thickness. Other porous or cavernous strata are found lower in the lime but have little saturation. The initial production varied from 100 to 25,000 bbl. per day, depending perhaps to some extent on the structural location but chiefly on the porosity of the pay. The initial gas-oil ratio varied from 325 to 16,000 cu. ft. per barrel. In wells where the top of the White lime was found below 350 ft. below sea level (Fig. 1)) the gas-oil ratio was usually less than 1500 cu. ft. per barrel, while in wells higher than 350 ft. below sea level, the ratio was usually above 2000 cu. ft. per barrel. The water table has been determined at about 620 ft. below sea level, by three wells on the west side of the field. With few exceptions, the wells have been completed with 7-in. casing cemented

Jan 1, 1932

By R. S. Cartwright

TWO types of automatic drilling controls, the Halliburton and the Hild, are now available and are coming into more or less general use in deep drilling. The primary function of both is to maintain a safe limit of torque on the drill pipe, this being accomplished by automatically controlling the weight or pressure on the cutting tool. Neither type will necessarily increase drilling speed, but by permitting advantage to be taken of "breaks" in the hole higher average cutting speed may be maintained. The control is essentially a safety device, and should be considered as such. It is not the purpose of this paper to discuss the merits of drilling controls, although the advantages over manual feed at the brake drum are obvious, but rather to point out some of the limitations. The Halliburton Control The Halliburton control is designed to operate during drilling through the agency of the draw works. Automatic and constant control of the torque on the bit is governed by clutches on the control itself, and the line shaft to drum shaft drives on the draw works. In operations other than drilling the control is simply a jackshaft between prime mover and draw works. It is, of course, adaptable to any type of power. Because control of the torque on the bit is dependent on the various ratios or clutch combinations available on the Halliburton control and the draw works, it follows that there are certain limitations in points of control. Table 1 shows the possible ratios which can be obtained with the control and a popular type of three-speed draw works, it being assumed that the highest possible gear combination—the combination which when engaged will suspend the least amount of weight—has a value of 1.00. According to the table there are "blind spots" in the series. This is true particularly among the lowest ratios, which are most used to suspend the major part of the weight when great depths are reached. It will be noted that there is a difference of nearly three units in the value of the

Jan 1, 1929

By J. M. Flaitz, A. S. Parks

OF the various methods of sampling gas-condensate wells, a method that secures a continuous representative sample of the well stream is desirable. Such a method, consisting of a sampling tube introduced into the well tubing, has proved satisfactory. The method is sufficiently accurate for operating and engineering problems A portable testing apparatus can be used with the sampling tube to obtain data useful in studying the economic and technical aspects of the development and operation of gas-condensate properties. Introduction The recent discovery and development of gas reserves that contain hydrocarbons that condense with reduction of temperature or Pressure, or both, to form a product known as condensate, has brought many new problems to the oil and gas industries. With further discovery of deep, high-pressure fields it is presumable that many more gas fields of this type will be added to the steadily increasing number. Such gas reserves are found either associated with oil as a gas cap or in separate formations. There seems to be no positive correlation between the physical or geological nature of the reservoir, and the chemical composition or phase characteristics of its contents. Knowledge of the chemical make-up and phase behavior of gas-condensate reserves is needed to cope with many problems. A knowledge of the chemical composition and phase characteristics of the reservoir material is necessary to properly design a gasoline or recycling plant, to estimate natural gas and condensate reserves, to enable the operator to study the economic and technical aspects of various methods of operation and development, and to carry Out the plan of operating subsurface and surface lease equipment. This information is often useful in questions of mineral ownership, proration, legal position, and taxation. It is the purpose of this paper to discuss methods used by the writers to determine the chemica1 composition and phase characteristics of the fluids produced from a condensate well. The scope of the paper includes a discussion and description of the method of sampling, the results of tests on the accuracy of the sampling method, a description of a portable testing apparatus used to examine the phase characteristics, typical results of tests on wells from several condensate fields, and some of the applications of these data to production problems. References to previous work on this subject are cited at the end of the paper. The Problem At reservoir conditions of temperature and pressure, the fluids produced from a condensate well exist in a homogeneous vaporous condition. The consequent reduction of temperature and pressure that occurs as this gas enters and flows up the well tube results in condensation of some of the hydrocarbon material to form a liquid. The relative amount of liquid condensed at any point in the flowing system

Jan 1, 1942

By J. M. Flaitz, A. S. Parks

OF the various methods of sampling gas-condensate wells, a method that secures a continuous representative sample of the well stream is desirable. Such a method, consisting of a sampling tube introduced into the well tubing, has proved satisfactory. The method is sufficiently accurate for operating and engineering problems A portable testing apparatus can be used with the sampling tube to obtain data useful in studying the economic and technical aspects of the development and operation of gas-condensate properties. Introduction The recent discovery and development of gas reserves that contain hydrocarbons that condense with reduction of temperature or Pressure, or both, to form a product known as condensate, has brought many new problems to the oil and gas industries. With further discovery of deep, high-pressure fields it is presumable that many more gas fields of this type will be added to the steadily increasing number. Such gas reserves are found either associated with oil as a gas cap or in separate formations. There seems to be no positive correlation between the physical or geological nature of the reservoir, and the chemical composition or phase characteristics of its contents. Knowledge of the chemical make-up and phase behavior of gas-condensate reserves is needed to cope with many problems. A knowledge of the chemical composition and phase characteristics of the reservoir material is necessary to properly design a gasoline or recycling plant, to estimate natural gas and condensate reserves, to enable the operator to study the economic and technical aspects of various methods of operation and development, and to carry Out the plan of operating subsurface and surface lease equipment. This information is often useful in questions of mineral ownership, proration, legal position, and taxation. It is the purpose of this paper to discuss methods used by the writers to determine the chemica1 composition and phase characteristics of the fluids produced from a condensate well. The scope of the paper includes a discussion and description of the method of sampling, the results of tests on the accuracy of the sampling method, a description of a portable testing apparatus used to examine the phase characteristics, typical results of tests on wells from several condensate fields, and some of the applications of these data to production problems. References to previous work on this subject are cited at the end of the paper. The Problem At reservoir conditions of temperature and pressure, the fluids produced from a condensate well exist in a homogeneous vaporous condition. The consequent reduction of temperature and pressure that occurs as this gas enters and flows up the well tube results in condensation of some of the hydrocarbon material to form a liquid. The relative amount of liquid condensed at any point in the flowing system

Jan 1, 1942

By Ionel I. Gardescu

In connection with some of the experiments carried out by the writer on the behavior of gas and oil in a sand reservoir,' an interesting phenomenon was observed which may throw some new light on the problem of recovery of oil from a natural reservoir. The experiments are intended to show the effect of the surface area of the occluded gas masses, originally present in a reservoir, on the further evolution of gas from the oil and its consequent effect upon the rate of production of oil. The apparatus used in the experimental work is shown in Fig. 1. It consists primarily of a sand reservoir R and a displacement chamber D, which is used to induce small variations in volume. The reservoir and displacement chamber form a unit, and a lowering of the plunger D is equivalent to increasing the volume occupied by the oil and gas in the reservoir. The reservoir was first filled with dead oil and maintained under pressure until it was ascertained that most of the free gas had gone into solution. The volume of free gas present in the reservoir was computed from the coefficient of compressibility of the fluids by means of the displacement chamber D, reading to 0.005 c.c. and a special gage J reading to 0.02 lb. per sq. in. The oil was saturated with gas under pressure in reservoir S by circulating the oil for a long period of time through the gear pump B. Subsequently, the saturated oil was circulated through the sand reservoir following the circuit S6, B, S6, R4, the sand reservoir R, R1, R², F4, F1, back to reservoir S. In the following experiments the sand reservoir R was filled with gas-saturated oil at a pressure of 415Ib. per sq. in. with no free gas present. This was ascertained by closing off all the outlet valves and determining the coefficient of compressibility of the system by means of the displacement chamber D. Much difficulty was encountered in eliminating all of the free gas masses from the oil reservoir. The dead oil originally present in the

Jan 1, 1932

By John F. Kendrick, Paul D. Cornelius

This paper is a progress report of a study the authors are making of the sucker-rod pump, considered as a vibrating system with one degree of freedom, with forced vibrations and with viscous damping. Dr. S. Timoshenko's formula is given, defining such a system. Each factor is considered in respect to the problem of operating sucker rods, and the zone is pointed out in which the mathematics do not apply to the sucker-rod pump, because of its variable mass. This general theory is interpreted in the light of nearly two years of testing wells in the field, and correlating the results of other tests. The motion of the pumping mechanism is a vibration. The string of sucker rods vibrates with a natural frequency. The motion of the plunger is the result of adding together these two vibrations, and is modified by a damping or friction factor. The controlling factor appears to be the ratio of the period of the natural vibration of the rod string to the period of the vibration of the pump. The first conclusion is that a definite value of this ratio, which is below resonance and is probably not greater than 0.5, should not be exceeded in order to assure satisfactory performance from the sucker rods. The second conclusion is that the component parts of the pumping equipment should be selected to give the smallest practical period of the natural vibration, and when this does not permit operation at a safe speed and give the required plunger displacement, a longer polished-rod stroke should be used. While the quantitative results are but rough approximations, the qualitative analysis of pumping problems on this basis promises to be of considerable value in diagnosing the cause of poor performance and prescribing suitable remedies. The trouble that results, whenever it becomes necessary to crowd the sucker-rod pump, to take potentials or to handle increasing volumes of water, is responsible for the belief that this type of pump is not equal to present day needs, and that it is only a question of time before some other pumping device will take its place. Of the troubles experienced, it is not surprising that the frequency of sucker-rod failures should

Jan 1, 1937

By Frederic H. Lahee

After abandoning two dry holes, on the Mrs. Daisy Bradford land, C. M. Joiner finally completed his No. 3 on Sept. 8, 1930, at a total depth of 3592 ft. This well is 735 miles somewhat north of west of the town of Henderson, in Rusk County. Between Oct. 2 and Oct. 6, this well made numerous heads which indicated that it would produce about 300 bbl. daily. By Nov. 27, two dry holes,' completed near the Joiner well, taken in conjunction with the small production from this well, served to dampen any enthusiasm among those who hoped for a major pool; but by December 18 three other producers had been completed. On Dec. 28, 1930, E. W. Bateman's Lois Della Crim No. 1 drilled itself in with an estimated daily yield of between 10,000 and 15,000 bbl. from a depth of 3650 ft. This well, 10 miles north of the Joiner well, also in Rusk County, initiated the leasing campaign that led to the later orgy of drilling. On Jan. 25, 1931, Moncrief, Farrell and others completed their J. K. Lathrop 1 as another big producer, 7 miles east of Gladewater in Gregg County and 14 miles N. 20" E. from the Bateman Crim well. The Lathrop well, 3574 ft. deep, flowed 320 bbl. in 1 hr. through a ½in. choke. The first well completed in Smith County was Cook No. 1, drilled by Guy Lewis et al. in the James Jordan Survey, 4.7 miles west of the Joiner discovery well. On Mar. 30, 1931, it flowed 137 bbl. in 33 min, through a ¾-in. choke. The top of the pay sand was found at 3672 ft. Finally, in Upshur County, on May 5, the Mudge Oil Co. et al. completed the Richardson No. 1, which flowed 274 bbl. through a 4 2/64-in. choke in 2 hr. This well is 4 miles northwest of the Lathrop producer. Development It is unnecessary to give a lengthy description of the rapid development of the area discovered in these five far-separated wells, or to discuss the speculations offered as to whether there were several pools or only one.

Jan 1, 1932

By Alexander Anderson

In many oil fields a great variation in the production of adjoining wells has long been observed, and a certain proportion of dry holes, situated between prolific producers, has been regarded as normal without thorough investigation as to cause. Similarly, an occasional prolific producer has been found in a part of a field where all other holes have proven disappointing. Adjoining wells which showed an unreasonable difference in production have been surveyed, and the bottom of the poorest producer has been found to have lost sufficient vertical depth, through its drift, to diminish seriously its penetration in the oil zone. Again, the bottom of the good producer has been found to he more favorably situated by its migration up structure. Surveying of wells in California fields has shown many instances where the dry hole has drifted far off the structure to such a degree that no amount of deepening could ever convert it into an oil well. In other cases, edge wells have been found to drift into the field. At this time, in California, the surveying of oil wells is beginning to he accepted as a routine part of operating procedure. Some operators are surveying all of their new wells and, in some of the recently discovered fields, this practice is providing invaluable assistance in methodical development. The information that has been obtained from the surveying of many wells has convinced most operators that it pays to give careful attention to the drilling of wells. Chews are now usually cautioned to avoid reckless competition with each other. Whereas, formerly, certain companies demanded a large footage from their drillers, they now issue orders that a very moderate speed in drilling shall he maintained and that every care be taken to avoid practices likely to cause excessive deviation of the hole frorn vertical. As a result of these new instructions to drilling crews, a distinct decline in the average drift of the wells drilled by these operators has taken place and fewer dry holes are being drilled from good locations. To the petroleum engineer and the geologist, oil-well surveys provide the necessary data required for the construction of the correct cross-

Jan 1, 1929

By Morris Muskat

In preparing a well for pumping, observations are often made of the fluid level in the well bore or bottom-hole pressures at various times before equilibrium has set in. From a qualitative point of view one may immediately infer that if the rise in the bottom-hole pressure or fluid level is rapid the permeability of the sand about the well bore is large, and converse conclusions may be drawn if the rise is slow. However, a more quantitative estimate will give additional information of value, as will be shown in this paper. To derive such an estimate we may proceed as follows. Let h be the fluid height, above the sand face, at time t, and let yo be the average density of the fluid that enters the bore. The bottom-hole pressure, for a fluid height h will therefore be p = rogh, neglecting, of course, the friction drop in the well bore, while the fluid is rising, as may be justifiably done for most pumping wells. If a is the free area of the open-flow string—assumed to be uniform— the rate of production from the sand during the rise of fluid will be: where the last part of the equation merely indicates that, in general, the production rate Q must be considered as a function of the back pressure, and is determined by it alone. In fact, equation 1 shows that if the rate of rise of the pressure or fluid level is determined as a function of the height of rise, or p, for a number of values of the latter, this functional relation between Q and p will be immediately given. Conversely, if we know this functional relation, the rate of increase of p or h may be predicted, or, by observing the rate of rise of p or h some of the constants of the sand may be determined. Thus we may approximate the production from a well in a pumping state by that of a dead

Jan 1, 1937

By W. H. Echols

An oil-emulsion mud, consisting of a mixture of oil-base mud and bentonitic water-base mud, has been used experimentally in drilling 8 of the 35 wells in the Sivells Bend field, Cooke County, Texas. Experience indicates the oil-emulsion mud can be controlled in much the same manner as a water-base mud, and the "drilling" functions of the two types of mud are comparable. The average water-loss for the oil-emulsion mud was 3.8 cu cm per well. When using oil-emulsion mud to drill the last 2000 ft of 7000 ft wells, the mud costs were approximately 2½ times that of water-base mud. There is nothing to indicate well productivities have been affected through the use of oil-emulsion mud. However, drilling time and bit footages were increased and the holes were maintained more closely to bit guage. The apparent advantages gained through the use of oil-emulsion mud in the Sivells Bend field do not appear to justify the increase in mud costs. Introduction until a comparatively few years ago most of the development of drilling mud was directed toward improving the functions of the mud as related to actual drilling operations. The industry has long recognized that one disadvantage of rotary drilling over cable-tool drilling is the possibility of injury to producing zones through the blocking effect resulting from the infiltration of water or mud into the sands. Recognizing this disadvantage, considerable attention has been diverted toward the development of muds that will improve the quality of well com-pletions through the reduction or elimination of water into the sands, but without sacrificing too many of their "drilling" functions and at a cost commensurate with the benefits derived from their use. This phase of mud research has already found practical application, for example, in the development of the Rangely field, Colorado, it appears the use of oil-base mud during drilling-in operations will contribute appreciably toward making this exploitation more profitable. Much of the discussion to follow will be better understood if a brief sketch of the Sivells Bend field is given. The Sivells Bend field, discovered by The Texas Co. in 1944 and still in the process of development, is in a large bend on the Texas side of the Red River about 85 miles north of Dallas. Geologically, the structure is an unsymmetrical anticline, with faulting having contributed to its development. The productive sands are of the Strawn series of Pennsylvanian age, the sands being lenticular in character and varying considerably in development from well to well. At Present there are 35 producing wells in the field, producing from seven different sand lenses. The productive sand lenses vary from 15 to 50 ft in thickness and the individual sands have average permeabilities of from 75 to 375 md. The presently productive sands are encountered at depths of from 6300 to 7300 ft, but testing has indicated that commercial production might be obtained from other sands as high as 5200 ft. Histories of older Strawn

Jan 1, 1948

By W. H. Echols

An oil-emulsion mud, consisting of a mixture of oil-base mud and bentonitic water-base mud, has been used experimentally in drilling 8 of the 35 wells in the Sivells Bend field, Cooke County, Texas. Experience indicates the oil-emulsion mud can be controlled in much the same manner as a water-base mud, and the "drilling" functions of the two types of mud are comparable. The average water-loss for the oil-emulsion mud was 3.8 cu cm per well. When using oil-emulsion mud to drill the last 2000 ft of 7000 ft wells, the mud costs were approximately 2½ times that of water-base mud. There is nothing to indicate well productivities have been affected through the use of oil-emulsion mud. However, drilling time and bit footages were increased and the holes were maintained more closely to bit guage. The apparent advantages gained through the use of oil-emulsion mud in the Sivells Bend field do not appear to justify the increase in mud costs. Introduction until a comparatively few years ago most of the development of drilling mud was directed toward improving the functions of the mud as related to actual drilling operations. The industry has long recognized that one disadvantage of rotary drilling over cable-tool drilling is the possibility of injury to producing zones through the blocking effect resulting from the infiltration of water or mud into the sands. Recognizing this disadvantage, considerable attention has been diverted toward the development of muds that will improve the quality of well com-pletions through the reduction or elimination of water into the sands, but without sacrificing too many of their "drilling" functions and at a cost commensurate with the benefits derived from their use. This phase of mud research has already found practical application, for example, in the development of the Rangely field, Colorado, it appears the use of oil-base mud during drilling-in operations will contribute appreciably toward making this exploitation more profitable. Much of the discussion to follow will be better understood if a brief sketch of the Sivells Bend field is given. The Sivells Bend field, discovered by The Texas Co. in 1944 and still in the process of development, is in a large bend on the Texas side of the Red River about 85 miles north of Dallas. Geologically, the structure is an unsymmetrical anticline, with faulting having contributed to its development. The productive sands are of the Strawn series of Pennsylvanian age, the sands being lenticular in character and varying considerably in development from well to well. At Present there are 35 producing wells in the field, producing from seven different sand lenses. The productive sand lenses vary from 15 to 50 ft in thickness and the individual sands have average permeabilities of from 75 to 375 md. The presently productive sands are encountered at depths of from 6300 to 7300 ft, but testing has indicated that commercial production might be obtained from other sands as high as 5200 ft. Histories of older Strawn

Jan 1, 1948

By E. L. Davis

There have been many attempts to devise formulas for flowing efficiency and flow friction of oil-gas mixtures in oil-well flow tubes. Actually, however, flowing efficiency is rarely any real concern of the oil producer and flow-friction formulas contain so many unknown variables as to be of little, if any value. The production engineer is generally concerned with producing as much oil as possible with a minimum expense per barrel, and with the lowest possible net gas-oil ratio. These ends frequently are opposed to each other and the gas-oil ratio usually is sacrificed. In competitive operations, such as in town-lot fields, high current production is the sole interest. In conservative operation the greatest possible amount of oil obviously should be produced by natural flow unless the net formation gas-oil ratio can be improved by circulating gas. In practice this condition frequently exists. It would be a great advantage if the flowing condition of a well could be analyzed to determine the best possible producing status. Anticipating the death of a well so that gas-lift could be started immediately after the death, or preferably before, would save both production and expense. Frequently it happens that circulating gas fails to help a flowing well, or will not flow it after it has stopped flowing naturally. A knowledge of the laws governing flow would save considerable expense in testing such cases. A predetermination of probable pressures and amounts of circulating gas needed to flow wells and give best possible producing conditions would help in designing compressor installations. The optimum producing status of an oil well generally may be obtained by the conditions that subject the producing formations to the least possible back-pressure. This pressure is made up of the weight of the fluid column, frictional resistance to flow and the reaction from the acceleration of the fluid mass. A mathematical calculation of these components to arrive at a condition giving a minimum summation is impractical. Formulas would be complex and the results untrustworthy because it is impossible to assign proper values to the many variables involved.

Jan 1, 1931

By Joseph Jensen, J. B. Stevens

The history of the normal oil field is supposed to show an oil graph starting high in flush production, descending more or less steeply into the curve of settled production and dropping gradually to the vanishing point of economical operation. Together with this, somewhere in the early history of the field, there appears from a vanishing point a graph showing the production of water. During the period of settled production this graph rises higher and, toward the close, unless extensive work is done in the line of correction, rises far above the oil graph to the point at which the cost of operation terminates profitable pumping. Fields that start out with a high relative content of water are generally very short-lived. Fields that never develop a water problem are exceedingly rare. The McKittrick oil field, Kern County, California, with 840 acres of proved ground, 300 wells and a present recovery per acre of 94,598 bbl. from 1898 to Aug. 1, 1930, presents a study which is an apparent reversal of the outlined normal history. Though the history of the field now covers over 30 years of operation, it is still too early and the conditions too unique to project the graph of production to completion. The present conditions and directions of change are most interesting, in that the curve of oil production is remarkably flat and the curve of water invasion, after reaching an appalling height, has shown a definite reversal and a continued decline for 10 years. Early drilling in the McKittrick field was in or prior to 1898. Development continued steadily to 1918 when the present limitations of the field were determined. Shut-offs, according to accepted practice of the time, were made by driving the shoe into a shale stratum or into a tamped-in bridge of sand, rosin and clay. Records of early days speak of three waters: (1) surface water which was fresh; (2) an intermediate sulfur water, encountered below the top oil or tar sand; (3) bottom salt water. In different portions of the field any one of these waters let into a well by faulty completion might require immediate correction to obtain satisfactory production. In many wells,

Jan 1, 1931

By R. M. Leibrock, C. W. Ziemer, R. P. Vincent

The Stanolind flowmeter, which employs a hot-wire anemometer connected in a Wheat-stone bridge circuit, has proved useful for determining the relative productive ability of individual sand members of gas wells. The operation of this instrument in measuring gas velocities in the well bore above each producing member has provided both a direct and accurate means of analyzing reservoir performance. Results of tests conducted with the well flowmeter in the Hugoton gas field of western Kansas have indicated some rather unusual production characteristics. In two cases it was found that all or the greater part of the total gas produced was coming from one section in wells where four "pay" sections had been perforated individually. These actual measurements contradict in many instances the indications of data obtained from electric logs and from core analysis; the fact that these latter sources often give incorrect results, demonstrates the necessity of a method, such as is provided by the well flowmeter, for accurately determining the amount of gas coming from each producing member. Introduction In any gas well where a number of pay sections have been perforated individually and are producing to a common outlet, the question arises as to the relative amounts of gas being passed through each set of perforations. In the past it has been the policy to depend on core analysis to estimate relative productivities, or, where the sections were not cored, to obtain some idea of production characteristics from electric-log studies. The weaknesses in these methods are readily apparent and indicate the need for more reliable means of measuring gas flow from each zone. The Stano-lind flowmeter* was developed for this purpose. Preliminary tests were made with the instrument in the Katy gas field near Houston; however, the bulk of the routine work with the well flowmeter has been confined to the Hugoton gas field in western Kansas, where results obtained have been encouraging. A description of the instrument, the field technique employed in testing, and a few of the results obtained in the Hugoton area are discussed in this paper. Description or Instrument The well flowmeter is 1¾ in. od and 7 ft long; it is entirely self-contained, can be run through tubing as small as 2 in. id in wells with high pressure (4500 psi) and temperature (210°F) and is lowered on a wire line commonly used for other instruments of the bottom-hole type at falling rates up to 500 ft per minute. It will detect gas flow as low as 10 ft per minute linear velocity, and yet withstand and record velocities of 1000 ft per minute without damage to the detecting element. Killing the well is not required nor desirable for running a production profile when using the instrument, and it is necessary to stop flow for only a short time. The detecting element of the instrument is a hot-wire anemometer connected in a

Jan 1, 1948

By R. M. Leibrock, R. P. Vincent, C. W. Ziemer

The Stanolind flowmeter, which employs a hot-wire anemometer connected in a Wheat-stone bridge circuit, has proved useful for determining the relative productive ability of individual sand members of gas wells. The operation of this instrument in measuring gas velocities in the well bore above each producing member has provided both a direct and accurate means of analyzing reservoir performance. Results of tests conducted with the well flowmeter in the Hugoton gas field of western Kansas have indicated some rather unusual production characteristics. In two cases it was found that all or the greater part of the total gas produced was coming from one section in wells where four "pay" sections had been perforated individually. These actual measurements contradict in many instances the indications of data obtained from electric logs and from core analysis; the fact that these latter sources often give incorrect results, demonstrates the necessity of a method, such as is provided by the well flowmeter, for accurately determining the amount of gas coming from each producing member. Introduction In any gas well where a number of pay sections have been perforated individually and are producing to a common outlet, the question arises as to the relative amounts of gas being passed through each set of perforations. In the past it has been the policy to depend on core analysis to estimate relative productivities, or, where the sections were not cored, to obtain some idea of production characteristics from electric-log studies. The weaknesses in these methods are readily apparent and indicate the need for more reliable means of measuring gas flow from each zone. The Stano-lind flowmeter* was developed for this purpose. Preliminary tests were made with the instrument in the Katy gas field near Houston; however, the bulk of the routine work with the well flowmeter has been confined to the Hugoton gas field in western Kansas, where results obtained have been encouraging. A description of the instrument, the field technique employed in testing, and a few of the results obtained in the Hugoton area are discussed in this paper. Description or Instrument The well flowmeter is 1¾ in. od and 7 ft long; it is entirely self-contained, can be run through tubing as small as 2 in. id in wells with high pressure (4500 psi) and temperature (210°F) and is lowered on a wire line commonly used for other instruments of the bottom-hole type at falling rates up to 500 ft per minute. It will detect gas flow as low as 10 ft per minute linear velocity, and yet withstand and record velocities of 1000 ft per minute without damage to the detecting element. Killing the well is not required nor desirable for running a production profile when using the instrument, and it is necessary to stop flow for only a short time. The detecting element of the instrument is a hot-wire anemometer connected in a

Jan 1, 1948

By R. J. Schilthuis, T. V. Moore

In a previous paper,' the results of some experimental work on the measurement of slippage in the flow of oil and gas mixtures through vertical pipes were presented. The data obtained were correlated and equations were deduced from which the performance of the experimental gas-lift could be predicted with reasonable accuracy. However, attempts to apply the equations to the calculation of pressure drops in actual flowing wells yielded erroneous results. At the time the results of the experimental work were published, no satisfactory explanation could be offered for the failure of the empirical equations to express properly the performance of wells. However, recent work has led to the development of a new hypothesis which presupposes certain conditions affecting the flow of oil and gas in wells. When the proposed equations are corrected to allow for these conditions, an agreement between the observed and calculated performance of the actual wells is obtained which in most cases is quite satisfactory, although it is subject to certain limitations. In this paper, the method of calculating the pressure drop in actual wells is considered, and the application of the method to the design of tubing is discussed. (For nomenclature used in this discussion, see Table 1.) Factors Affecting Slippage and Efficiency At the outset, a few of the principle factors affecting slippage and efficiency in the gas-lift discussed in the previous paper will be reviewed. In the flow of the mixture of oil and gas in a vertical pipe, slippage is the phenomenon of gas moving upward with a. linear velocity greater than that of the oil. Under steady conditions, if given quantities of oil and gas enter the tubing per unit of time, the same quantities of oil and gas per unit time must, on the average, pass every section of the tubing; otherwise, there would be accumulation or depletion of the oil or gas at some sections, and the flow would be unsteady. Therefore, if the gas is to flow at a greater linear velocity than that of the liquid,

Jan 1, 1933

By R. W. Brauchli

The author has made a statistical analysis of the relations between recovery and length of cores, diameters of cores and of drill pipe, and cost of coring under different contractual conditions. The data are presented in tabular form. The length of the core appears to play a minor part in the percentage recovered, with a tendency to lower percentages with increased core length; approximately 50 per cent of the length cored is normally recovered if the cores are more than 2 in. in diameter. The diarneter of the core has a more pronounced influence on the recovery; 1 3/8-in. cores average 29.1 per cent, 2 1/8 -in. core 53.4 per cent and 3 1/8-in. cores with 6 5/8-in. drill pipe 68.5 per cent. Where 31/8-in cores were taken with smaller diameter drill pipe, i. e., 4 1/2 - in. drill pipe in 8 1/4-in. hole, the recovery dropped to 49.8 per cent, indicating that the more rigid drill pipe favors good core recovery, a conclusion also borne out by the results obtained in using large drill pipe for smaller diame-ter cores. Surprisingly good recoveries were obtained from both the Johnson and Simpson sands; shale, limestone and dolomite each gave less then average recoveries. No serious fishing jobs resulted from coring operations. Attention is called to the need of a core drill which will make it possible to drill a full-sized hole while coring, and thus reduce the cost of cores. Data pertaining to core drilling should be consistently recorded, such as, diameter of drill pipe and collar, diameter of core, recovery, size of cutter heads, type of core-barrel, coring time, speeds of rotation and of pumps, weight on core-barrel, etc.

Jan 1, 1933