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By Robert R. Boyd

The gravity discussed here is that of the clean oil produced. Gravities of fluids containing water, free or in the form of emulsion, sand, drilling mud or mineral salts of a nonbituminous nature do not represent the gravity of crude oil as considered in this paper. During recent years it has become a frequent occurrence for operators to be called upon to explain to landowners the reasons for variations in gravity on shipments of oil from wells in which they are interested as royalty owners. In regard to single well leases it has been noted that marked changes in gravity frequently have occurred for no apparent reason. Data collected on the subject and correlated with production methods reveal interesting facts. It is the purpose of this paper to present some of the highlights on the subject. These gravity changes in the natural crude oil are with a few exceptions the result of the liberation under varying conditions of the volatile hydrocarbons from the natural oil-gas solution contained within the pool. The subject of the liberation of gases from natural oil-gas solution has been investigated by Ben E. Lindsly, of the U. S. Bureau of Mines, and the observations recorded here are in the main consistent with his conclusions. Investigators have recognized two methods of liberation of gas from solution—flash and differential. In the latter method the vapors are removed from the liquid as rapidly as formed and have no opportunity to come to a condition of equilibrium with the oil. In flash liberation an equilibrium condition between the oil and the gas exists at the pressure of separation. Mr. Lindsly has found that the method of liberating the gas from the oil has a pronounced effect on the final gravity and that differential liberation results in a higher A.P.I. gravity due to the higher ratio of gasoline producing hydrocarbons left in the oil. Under actual production practices with high velocities in flow strings, it is our contention that conditions of perfect equilibrium between gas and the oil rarely exist, and that gas separation is made under varying conditions, sometimes approaching that of equilibrium and at other times departing from it.

Jan 1, 1937

By Morgan Walker

Intermittent injection of gas in gas-lift pumping is a variation of the common practice in that the gas is delivered to the well for a short period, called the "on time," followed by a period during which none is admitted, called the "off time," instead of being admitted continuously at a constant rate or by intermittent flowing in which it is occasionally delivered to the well in just sufficient quantity to flow off the accumulated head of fluid. The term "gas" is used throughout this discussion but it should be remembered that in so far as the operation is concerned either air or natural gas may be used. The equipment at the well is the same as commonly used in gas-lift installations and gas may be admitted to either the tubing or the casing. It seldom occurs that all the wells on a lease can be pumped economically by intermittent injection from one header. Wells that have flow characteristics which permit their being handled together have their intake lines grouped at a central compressor station. Well groups may consist of two or more wells. The total volume of gas delivered by each group of compressors goes to one well at a time through a quick opening valve, each well connected to the header receiving its charge of gas in turn. Special cases may require a deviation from this arrangement. The distribution of the gas to the different wells is effected by an automatic timing device which operates quick-opening valves on the intake lines. The timing mechanism may be actuated by electricity, liquid or gas pressure, The essential factor in the operation of the timing mechanism is that as one intake valve is closed another must be opened. Water-operated Timing Device Timing devices operate the intake valves either directly, or indirectly by pilot valves. Of the former type one that is operated by water and has given satisfactory service is shown in Fig. 1 and can be made on the lease. The horizontal cylinder is a piece of 10-in. casing about 7 ft. long, closed at each end and free to oscillate about a fulcrum at the center.

Jan 1, 1929

By D. Silverman, A. R. Brown

EquipmENT and methods for locating the points of entry of salt water into oil wells are described. These techniques make it possible to delineate accurately the top and bottom boundaries of water zones whether bottom water or intermediate zones of production, Data are given on tests by this survey method on a number of producing wells, Complete results were obtained on wells shelving water percentages ranging from high values to as Little as 10 pct salt water. A number of the wells tested were plugged back and the results are reported in detail. While not all the work-overs were successful, evidence, including the results of reruns by this survey method, points to failure of the plugback operations. The data provided in the tests discussed show, contrary to general opinion, that a large percentage approaching 50 pct of the wells showed intermediate water instead of bottom water. Furthermore, approximately a third of the wells tested showed multiple zones of water production. The equipment comprises a long pipelike assembly carrying 10 pairs of electrodes spaced apart a distance of 4 ft. A surface-controlled solenoid-operated switch is provided to connect each of the individual pairs of electrodes in turn to a single-conductor steel-armored cable by means of which the conductivity of the fluid in the vicinity of each of the electrode pairs can be continuously recorded at the surface. Any number of electrode pairs and any spacing can be used. This assembly is lowered on tubing and placed in position opposite the section of the well to be studied. A conventional rod pump is used to produce the well for the survey. The pump inlet is placed below the lowest electrode pair. The well is conditioned by pumping Out the salt water normally standing in the well and introducing fresh water into the annulus at the surface. When the resistivity of the water standing in the well has been increased to a sufficiently high value, the inflowing fresh water is stopped and the drawdown operation of the survey is started. As the fluid head is lowered by pumping, fluids flow into the well and the entry Of salt water is indicated by the change in resistivity of the fresh water opposite the 'Ones Of water entry, The process can be repeated as Often as necessary with little effort and without moving any well equipment to be sure that the fluids produced from each zone are representative Of the true reservoir content. Introduction The oil industry has been concerned from its inception with the control of fluids entering its wells. In order to effect the greatest economy of operation and to get the greatest total production of petroleum liquids out of the ground, the flow of gas and water must be controlled and often extensive workovers are planned and carried Out for this purpose. This has become even more important in recent Years because of the need for the conservation of natural resources. Whereas producing operations concerned with the original completion of a well are assisted to a great extent by a wide variety of instruments developed and perfected for that purpose, workover operations on oil wells have been greatly hindered by a lack of suitable instrumentation. The industry has searched for many years for a satisfactory instrument and process that

Jan 1, 1948

By A. R. Brown, D. Silverman

EquipmENT and methods for locating the points of entry of salt water into oil wells are described. These techniques make it possible to delineate accurately the top and bottom boundaries of water zones whether bottom water or intermediate zones of production, Data are given on tests by this survey method on a number of producing wells, Complete results were obtained on wells shelving water percentages ranging from high values to as Little as 10 pct salt water. A number of the wells tested were plugged back and the results are reported in detail. While not all the work-overs were successful, evidence, including the results of reruns by this survey method, points to failure of the plugback operations. The data provided in the tests discussed show, contrary to general opinion, that a large percentage approaching 50 pct of the wells showed intermediate water instead of bottom water. Furthermore, approximately a third of the wells tested showed multiple zones of water production. The equipment comprises a long pipelike assembly carrying 10 pairs of electrodes spaced apart a distance of 4 ft. A surface-controlled solenoid-operated switch is provided to connect each of the individual pairs of electrodes in turn to a single-conductor steel-armored cable by means of which the conductivity of the fluid in the vicinity of each of the electrode pairs can be continuously recorded at the surface. Any number of electrode pairs and any spacing can be used. This assembly is lowered on tubing and placed in position opposite the section of the well to be studied. A conventional rod pump is used to produce the well for the survey. The pump inlet is placed below the lowest electrode pair. The well is conditioned by pumping Out the salt water normally standing in the well and introducing fresh water into the annulus at the surface. When the resistivity of the water standing in the well has been increased to a sufficiently high value, the inflowing fresh water is stopped and the drawdown operation of the survey is started. As the fluid head is lowered by pumping, fluids flow into the well and the entry Of salt water is indicated by the change in resistivity of the fresh water opposite the 'Ones Of water entry, The process can be repeated as Often as necessary with little effort and without moving any well equipment to be sure that the fluids produced from each zone are representative Of the true reservoir content. Introduction The oil industry has been concerned from its inception with the control of fluids entering its wells. In order to effect the greatest economy of operation and to get the greatest total production of petroleum liquids out of the ground, the flow of gas and water must be controlled and often extensive workovers are planned and carried Out for this purpose. This has become even more important in recent Years because of the need for the conservation of natural resources. Whereas producing operations concerned with the original completion of a well are assisted to a great extent by a wide variety of instruments developed and perfected for that purpose, workover operations on oil wells have been greatly hindered by a lack of suitable instrumentation. The industry has searched for many years for a satisfactory instrument and process that

Jan 1, 1948

By C. O. Rison

HIGH explosives, particularly nitroglycerin, have been used in torpedoes for the purpose of shooting oil and gas wells for more than 60 years. The early history of the oil industry in Pennsylvania is not clear as to who actually torpedoed the first well, although in 1865 the Roberts Torpedo Co. procured a patent covering the process. Gunpowder was first used, although nitroglycerin was substituted shortly afterwards. Wells are shot for the purpose of increasing the flow of oil and gas A shot-hole in the producing horizon, with its contributory fissures and fractures, increases the area of and stimulates drainage into the hole. The shot-hole also acts as a collecting basin from which the oil is pumped. As a rule, hard or close-grained sands or limes are shot, other more or less porous and soft formations usually do not require shooting. and might be injured by blasting. Shooting is also resorted to in mechanical trouble such as straightening crooked holes, sidetracking pipe or tools, and for severing frozen strings of casing or drill pipe. Explosives arc also used sometimes to extinguish oil or gas-well fires although that work, which involves unusual conditions and methods, does not properly come within the classification of oil-well shooting. Some Factors to Be Considered in Shooting Wells Although nitroglycerin has been used extensively for more than half a century in shooting oil and gas wells, there is still a great deal of uncertainty as to the proper method of shooting or the amount of explosive required to produce best results in a particular formation. The possibility of shooting unproductive or cavey formations above or below the productive horizons, shooting into lower water, destroying casing seats, and the splitting or collapsing of casing strings, are factors that require consideration. The engineering departments of a number of the larger oil companies are making a study of methods of shooting, and the amounts of liquid nitroglycerin or other explosives required in shooting various productive

Jan 1, 1929

By Hallan N. Marsh, Bruce H. Robinson

It is now generally recognized that to secure the greatest ultimate recovery of petroleum from a field it is necessary to maintain at all times the lowest possible ratio of gas to oil production. The numerous ways of securing low ratios are not so generally understood or practiced. To many operators, reduction of gas-oil ratio simply means "beaning back" wells, with resultant reduced production rate. This postponement of production is often considered and spoken of as "lost" production, with the result that control of gas-oil ratio is in disfavor with some operators. Various methods are herein discussed by which gas-oil ratio may be reduced, some of which invoLve no curtailment of current production, while others are accompanied by an actual increase of daily production. It is further shown that in cases where rate of production is reduced to conserve gas, the indicated ultimate recovery is generally increased. Principles involved are discussed, and conclusions are illustrated by data from the operation of wells. General Principles The rate and ratio in which oil and gas enter a well are solely dependent, so far as the operation of that well is concerned, upon the pressures maintained in the well opposite the producing strata at various times and at various depths. The method of getting the oil out of the hole, whether by natural flow, gas-lift, or pumping, has no effect upon either rate of production or ultimate recovery except through its effect upon pressures. Oil apparently enters wells according to some such equation as the following: R = KC(Pf - Pw)n Where R = rate of production. K = well coefficient, depending upon thickness of sand, and size and number of pores in the sand. C = fluid coefficient, depending upon viscosity, surface tension, etc.

Jan 1, 1929

By K. C. Sclater, B. R. Stephenson

Recent progress in oil-recovery methods has brought into prominence gas-energy relations in oil sands. The greater the effort made to utilize this gas-energy relationship to the best advantage in oil recovery, the greater becomes the need for more precise information concerning physical conditions as they actually exist in an oil well. The intelligent use of gas-oil ratios when considering production efficiency has been the subject of much recent discussion. It has been stressed that the pressure as well as the volume of gas must be known when considering the efficiency of a producing well on an energy basis. When methods of production are compared on an energy basis it implies a knowledge of pressure, temperature and physical properties of the fluids at the bottom of the well. In questions concerning gas-lift and the pressure control of wells usually there is a wide variance of opinion among engineers when energy relations come up for discussion. Perhaps this difference f opinion can be traced to erroneous assumptions made with regard to the physical conditions existing within the well. If erroneous assumptions are made it follows that computations based on these assumptions will give results which also will be in error. That erroneous assumptions are made is not to be wondered at because when handling a fluid composed of gas and oil, we are dealing with a complexity of hydrocarbon components each varying to some degree in physical and chemical properties. This means that the physical state of the gas and oil will depend not only on temperature and pressure but that it will be influenced also by the relative amounts of the various hydrocarbon components present. If water is present the problem becomes still more complicated. From these considerations alone it would appear that we can well afford to give some thought to devising more positive methods or means for obtaining data on physical conditions within the well rather than depend entirely on computations from casinghead data. If these data

Jan 1, 1929

By L. L. Gray, D. W. Reed, F. Morgan

A flowMeter has been developed at Gulf Research and Development Co. and tested in the field for measuring the flow of gas in well bores. It has been used in a study of the injection capacity of different horizons in gas injection wells in Oklahoma. The flow sensitive element of the meter is a semi-conductor having a very high temperature coefficient of resistance. Advantages possessed by this meter are the result of that property and the high specific resistance of the element. The instrument possesses a sensitivity considerably higher than any reported previously. In the application described here the element is heated to a temperature considerably above ambient by an electric current, which is supplied by a voltage source at the surface. When fluid flows through the meter the rate of dissipation of heat is increased and the temperature of the element decreases. Because of the negative temperature characteristics of the resistance element such a decrease of temperature will be accompanied by an increase of resistance which, under flow conditions ordinarily found in wells, is of such a magnitude that it can be directly measured or recorded in terms of a change in voltage at the surface. In practice, rate of flow is measured in terms of the drop in voltage in the resistance element. All the metering and control apparatus remains at the surface while the thermal element is lowered into the well on a single conductor cable, consisting of an insulated wire and sheath. The meter is calibrated by passing known quantities of gas through it either at the surface or in the hole at a point immediately above the region in which gas is lost to the formation. In case calibration is made at the surface, the ambient temperature in the hole may readily be obtained by a second resistance element which is operated at a current so low that effectively no heating occurs. The instrument has been adapted to con-tinuous recording, but the velocity of the meter relative to that of the gas must be low unless corrections are made. Curves giving data obtained in actual field tests are shown' The meter can also be used to determine the distribution of flow capacity in a gas producing well. A differential form of the meter has been designed and built in which the local flow or injection capacity of the formation is obtained directly. Introduction When fluid is injected into a well in a secondary recovery or pressure-maintenance operation the question of its most effective use invariably arises. Although the core log, when available, will show the regions of good permeability and oil saturation, there is normally no assurance that the fluid actually enters the formation in zones where injection is deemed desirable. In view of the uncertainties involved in such programs, it is generally conceded that measurements of permeability for a formation in place are more significant than those obtained by the core-sampling technique. A subsurface meter has been developed at the Gulf Research and Development Co. for measuring flow of fluids at different horizons in a well bore, and field tests have been made on the instrument in Cooperation with the Tulsa Division of the Gulf Oil Corp. In this paper the meter is de-

Jan 1, 1948

By F. Morgan, L. L. Gray, D. W. Reed

A flowMeter has been developed at Gulf Research and Development Co. and tested in the field for measuring the flow of gas in well bores. It has been used in a study of the injection capacity of different horizons in gas injection wells in Oklahoma. The flow sensitive element of the meter is a semi-conductor having a very high temperature coefficient of resistance. Advantages possessed by this meter are the result of that property and the high specific resistance of the element. The instrument possesses a sensitivity considerably higher than any reported previously. In the application described here the element is heated to a temperature considerably above ambient by an electric current, which is supplied by a voltage source at the surface. When fluid flows through the meter the rate of dissipation of heat is increased and the temperature of the element decreases. Because of the negative temperature characteristics of the resistance element such a decrease of temperature will be accompanied by an increase of resistance which, under flow conditions ordinarily found in wells, is of such a magnitude that it can be directly measured or recorded in terms of a change in voltage at the surface. In practice, rate of flow is measured in terms of the drop in voltage in the resistance element. All the metering and control apparatus remains at the surface while the thermal element is lowered into the well on a single conductor cable, consisting of an insulated wire and sheath. The meter is calibrated by passing known quantities of gas through it either at the surface or in the hole at a point immediately above the region in which gas is lost to the formation. In case calibration is made at the surface, the ambient temperature in the hole may readily be obtained by a second resistance element which is operated at a current so low that effectively no heating occurs. The instrument has been adapted to con-tinuous recording, but the velocity of the meter relative to that of the gas must be low unless corrections are made. Curves giving data obtained in actual field tests are shown' The meter can also be used to determine the distribution of flow capacity in a gas producing well. A differential form of the meter has been designed and built in which the local flow or injection capacity of the formation is obtained directly. Introduction When fluid is injected into a well in a secondary recovery or pressure-maintenance operation the question of its most effective use invariably arises. Although the core log, when available, will show the regions of good permeability and oil saturation, there is normally no assurance that the fluid actually enters the formation in zones where injection is deemed desirable. In view of the uncertainties involved in such programs, it is generally conceded that measurements of permeability for a formation in place are more significant than those obtained by the core-sampling technique. A subsurface meter has been developed at the Gulf Research and Development Co. for measuring flow of fluids at different horizons in a well bore, and field tests have been made on the instrument in Cooperation with the Tulsa Division of the Gulf Oil Corp. In this paper the meter is de-

Jan 1, 1948

By Graham P. Crutchfield

The W. I. Cook pool in Shackelford County, Texas, has been the subject of a number of papers and articles. Its unique position both as to operation and development has made it an ideal location for unit repressuring. The major portion of the pool is located on the W. I. Cook ranch and most of the oil leases are owned by Roeser & Pendleton, Inc. and the Continental Oil Co. and operated by Roeser & Pendleton, Inc. The Humble Oil & Refining Co. and Tom James operate producing leases which have a vital bearing on the unity of the pool. Both have cooperated in the repressuring project. Practically the entire royalty is owned by Mrs. W. I. Cook and she has given the operators her entire cooperation in all phases of unit repressuring.

Jan 1, 1931

By M. W. Strong

The technique of handling drilling muds varies somewhat, partly because of personal factors but mainly because of differences in formation, the type of problems, and the general drilling conditions in different localities. The much greater depths to which bore holes are now carried have made necessary closer attention to and great modifications of all aspects of drilling-mud technique. Increased depth means smaller hole, smaller drill pipe, smaller clearances, higher pumping pressures, higher differential pressures between shows and the mud column, less accurate control of the weight of the mud column, delayed receipt of formation data, and poorer samples. It means longer delays and greater hazards in rectifying mistakes or dealing with accidental occurrences. Equipment on a larger scale is necessary and more pains must be taken with layout. Lastly, the budget costs of raw materials have risen to high figures and economy of time and of direct monetary expenditure have come to mean much more than formerly. A mud laboratory is now part of the essential establishment of a modern oil field and to it current problems can be submitted for the most thorough investigation. The detailed chemical properties of all materials purchased or quarried have to be investigated. Detailed data on the physical properties have to be ascertained and research on improvement of material and its most efficient use has to be carried out. In this paper will be discussed the main mud problems of Iran, some of which are peculiar to local conditions while others are of the general type common to all workers in this subject. Underground Conditions In deep wells in Iran the normal overburden may consist of: (1) up to several thousand feet of marls with interbedded sandstones and limestones of varying porosity and permeability; (2) beneath this a chemical series of rock salt and anhydrites, containing various marls and thin limestones,

Jan 1, 1939

By M. W. Strong

The technique of handling drilling muds varies somewhat, partly because of personal factors but mainly because of differences in formation, the type of problems, and the general drilling conditions in different localities. The much greater depths to which bore holes are now carried have made necessary closer attention to and great modifications of all aspects of drilling-mud technique. Increased depth means smaller hole, smaller drill pipe, smaller clearances, higher pumping pressures, higher differential pressures between shows and the mud column, less accurate control of the weight of the mud column, delayed receipt of formation data, and poorer samples. It means longer delays and greater hazards in rectifying mistakes or dealing with accidental occurrences. Equipment on a larger scale is necessary and more pains must be taken with layout. Lastly, the budget costs of raw materials have risen to high figures and economy of time and of direct monetary expenditure have come to mean much more than formerly. A mud laboratory is now part of the essential establishment of a modern oil field and to it current problems can be submitted for the most thorough investigation. The detailed chemical properties of all materials purchased or quarried have to be investigated. Detailed data on the physical properties have to be ascertained and research on improvement of material and its most efficient use has to be carried out. In this paper will be discussed the main mud problems of Iran, some of which are peculiar to local conditions while others are of the general type common to all workers in this subject. Underground Conditions In deep wells in Iran the normal overburden may consist of: (1) up to several thousand feet of marls with interbedded sandstones and limestones of varying porosity and permeability; (2) beneath this a chemical series of rock salt and anhydrites, containing various marls and thin limestones,

Jan 1, 1939

By H. S. Gipson

A process that has come to be known locally as "multistage stabilization" has been developed in the Haft Kel field of the Anglo-Iranian Oil Co. in southwest Iran, for the recovery of casinghead gasoline. It consists in releasing the dissolved gases from the crude by stages, a practice common in many fields, but which, so far as is known, has nowhere been carried to the extent to which it is employed in Iran. It has been in use there for nearly nine years, during which time some 200 million barrels of crude have been handled by the process. This process of gasoline retention consists in preventing the greater part of the casinghead gasoline hydrocarbons (the butanes and pentanes) from ever leaving the crude, instead of allowing them to be vaporized and then recovered from the lighter gases by the usual compression or absorption processes. Its efficiency is fully equal to that obtained by the absorption process; its disadvantage is that it increases the quantities of ethane and propane in the crude sent to the refinery, but with the growing demand for propane this drawback is vanishing. When casinghead gasoline is recovered as a separate liquid in the Iranian fields, it is blended with the crude, as the only outlet is through the refinery, and the crude-oil pipe line offers the cheapest means of transportation. It is under these conditions that the retention of the butanes and pentanes in the crude by multistage stabilization is a most attractive process, possessing as it does the following advantages: (1) extreme simplicity, (2) low first cost, (3) easy installation! (4) practically 100 per cent operating-time efficiency, (5) no operators required, (6) no water or other services required, (7) negligible maintenance, (8) once established, very little routine testing is necessary. The one essential for reasonably efficient multistage stabilization is that the flowing pressures of the wells should be relatively high; i.e., they should not be less than about one-third the saturation pressure of the crude in the reservoir. This is a very general statement, of course, and much depends on the type of crude and its temperature.

Jan 1, 1940

By H. S. Gipson

A process that has come to be known locally as "multistage stabilization" has been developed in the Haft Kel field of the Anglo-Iranian Oil Co. in southwest Iran, for the recovery of casinghead gasoline. It consists in releasing the dissolved gases from the crude by stages, a practice common in many fields, but which, so far as is known, has nowhere been carried to the extent to which it is employed in Iran. It has been in use there for nearly nine years, during which time some 200 million barrels of crude have been handled by the process. This process of gasoline retention consists in preventing the greater part of the casinghead gasoline hydrocarbons (the butanes and pentanes) from ever leaving the crude, instead of allowing them to be vaporized and then recovered from the lighter gases by the usual compression or absorption processes. Its efficiency is fully equal to that obtained by the absorption process; its disadvantage is that it increases the quantities of ethane and propane in the crude sent to the refinery, but with the growing demand for propane this drawback is vanishing. When casinghead gasoline is recovered as a separate liquid in the Iranian fields, it is blended with the crude, as the only outlet is through the refinery, and the crude-oil pipe line offers the cheapest means of transportation. It is under these conditions that the retention of the butanes and pentanes in the crude by multistage stabilization is a most attractive process, possessing as it does the following advantages: (1) extreme simplicity, (2) low first cost, (3) easy installation! (4) practically 100 per cent operating-time efficiency, (5) no operators required, (6) no water or other services required, (7) negligible maintenance, (8) once established, very little routine testing is necessary. The one essential for reasonably efficient multistage stabilization is that the flowing pressures of the wells should be relatively high; i.e., they should not be less than about one-third the saturation pressure of the crude in the reservoir. This is a very general statement, of course, and much depends on the type of crude and its temperature.

Jan 1, 1940

By D. L. Katz

The Oklahoma City Wilcox sand, discovered on March 26, 1930, has produced 394 million barrels of crude oil and 819 billion cubic feet of natural gas as of July I, 1941. The 100,000-bbl. wells, pressures of 2600 lb. per sq. in., and flows of "Wilcox" sand caused exciting moments in the early life of the field. Today the reservoir is substantially at atmospheric pressure and produccs 75,000 bbl. of crude oil daily through 466 pumping wells. Early estimates of the initial crude-oil content of the "Wilcox" sand1 indicated that about 600 million barrels of crude oil would remain after the pumping wells ceased to produce economically. The Oklahoma City Wilcox Secondary Recovery Association was organized in March 1939, to study the possibilities of recovering a portion of this oil. Only a very brief summary of the information available can be presented in a paper of this nature. Some simplifications and generalizations are necessary to give the over-all picture in SO short a space and statements made may not apply to a specific well or small area. Since the area under consideration by the Association is that north of the south line of section 22-11-3, some information will be presented for areas A, B, C, 1, 2, 3 and part of 4 of Fig. 2, and some will be for the entire Wilcox zone west of the fault. This paper is essentially an abstract of an engineering report made by A. D. Small, B. T. Murphree, M. C. Sons and the author for the Oklahoma City Wilcox Secondary Recovery Association on Sept. 5, 1940. Some information is taken from a report to the Association by C. V. Sidwell on March I, 1940, and some data are from a recent report by A. D. Small. It gives a brief history of the Wilcox zone, estimates of the initial oil contents of the reservoir, present conditions in the reservoir, and probable results from several programs of "secondary recovery." History of Wilcox Zone The Wilcox sand lies on the flank of the general structure, as shown by cross section of Fig. I2,3,4 and areal map of Fig. 2. The sand is of Ordovician age and is composed of well assorted, rounded sand grains with no apparent cementing material. The loose texture of the sand is shown by the enormous quantities of sand production from the wells and from the soft cores. The productive sand varies from zero thickness on the east to 220 ft. maximum and to zero thickness on the west because of water. The development of the pool4 as dependent upon drilling restrictions within the city limits, which accounts for the spacing of drilling operations listed in Table I by years. In 1931, areas I through 7 of Fig. 2 were open for drilling with the exception of some west-edge properties, and all wells drilled before Feb. I, 1935, were in this portion of the field. Nearly all wells drilled from 1933 to 1037 were in areas A, B and C. Since 1939, the newly drilled wells have gradually enlarged the producing area toward the west in the northern portion.

Jan 1, 1942

By D. L. Katz

The Oklahoma City Wilcox sand, discovered on March 26, 1930, has produced 394 million barrels of crude oil and 819 billion cubic feet of natural gas as of July I, 1941. The 100,000-bbl. wells, pressures of 2600 lb. per sq. in., and flows of "Wilcox" sand caused exciting moments in the early life of the field. Today the reservoir is substantially at atmospheric pressure and produccs 75,000 bbl. of crude oil daily through 466 pumping wells. Early estimates of the initial crude-oil content of the "Wilcox" sand1 indicated that about 600 million barrels of crude oil would remain after the pumping wells ceased to produce economically. The Oklahoma City Wilcox Secondary Recovery Association was organized in March 1939, to study the possibilities of recovering a portion of this oil. Only a very brief summary of the information available can be presented in a paper of this nature. Some simplifications and generalizations are necessary to give the over-all picture in SO short a space and statements made may not apply to a specific well or small area. Since the area under consideration by the Association is that north of the south line of section 22-11-3, some information will be presented for areas A, B, C, 1, 2, 3 and part of 4 of Fig. 2, and some will be for the entire Wilcox zone west of the fault. This paper is essentially an abstract of an engineering report made by A. D. Small, B. T. Murphree, M. C. Sons and the author for the Oklahoma City Wilcox Secondary Recovery Association on Sept. 5, 1940. Some information is taken from a report to the Association by C. V. Sidwell on March I, 1940, and some data are from a recent report by A. D. Small. It gives a brief history of the Wilcox zone, estimates of the initial oil contents of the reservoir, present conditions in the reservoir, and probable results from several programs of "secondary recovery." History of Wilcox Zone The Wilcox sand lies on the flank of the general structure, as shown by cross section of Fig. I2,3,4 and areal map of Fig. 2. The sand is of Ordovician age and is composed of well assorted, rounded sand grains with no apparent cementing material. The loose texture of the sand is shown by the enormous quantities of sand production from the wells and from the soft cores. The productive sand varies from zero thickness on the east to 220 ft. maximum and to zero thickness on the west because of water. The development of the pool4 as dependent upon drilling restrictions within the city limits, which accounts for the spacing of drilling operations listed in Table I by years. In 1931, areas I through 7 of Fig. 2 were open for drilling with the exception of some west-edge properties, and all wells drilled before Feb. I, 1935, were in this portion of the field. Nearly all wells drilled from 1933 to 1037 were in areas A, B and C. Since 1939, the newly drilled wells have gradually enlarged the producing area toward the west in the northern portion.

Jan 1, 1942

By E. H. Griswold, W. J. Wilkins

Pressure control of oil wells may be defined as the adjustment of pressures within a well to obtain the most efficient and economic utilization of the natural gas energy with a minimum of sand troubles or irregular water encroachment. The purpose of this paper is to present the methods used by the writers in applying pressure control and a discussion of the various effects occurring within the wells affected. The benefits to be derived from the conservation of natural gas energy have been so adequately discussed and demonstrated in prior papers by various engineers that the effects on ultimate production will not be discussed other than to mention a few representative cases. The detrimental effects of irregular edge-water encroachment and of sanding up arc of general knowledge to the industry. Effect on Ultimate Production One of the strongest objections voiced against pressure control is that of the danger or inadvisability of deferring oil production by cutting the rate of production. It has been our experience that such deferred product'ion is returned within a few weeks or months rather than years and that an increased cumulative oil production is obtained in the early life of the well by conserving the natural energy. In many cases the rate of production is increased rather than decreased by the adjustment of pressures to obtain the minimum gas factor. Fig. 1 shows the history of a Wilcox sand well in northern Oklahoma, which was pressure-controlled from completion. It is noted that during the early months while flowing naturally through the casing the gas factor was decreased rather than allowed to follow its natural tendency to increase. A string of 21/2-in. tubing was run to restrict the flow and resulted in a decreased gas factor with a more sustained rate of production. When first placed on gas-lift the gas factor again tended to increase, but after the proper pressure adjustments were made, remained approximately steady. It was necessary to defer 100 bbl. per day of oil production in order to maintain this low gas factor. In March serious

Jan 1, 1929

By P. L. Menaul, P. P. Spafford

This paper discusses the most dangerous form of corrosion encountered in condensate-well oil production, the discovery of the agent causing this corrosion and the remedial chemical treatment proved effective by field use. The injection of ammonium hydroxide, even as little as one quart per day, has proved effective in preventing gas-condensate well corrosion. The injection of "Bone oil" is applied to wells producing brines containing calcium and magnesium salts. Introduction The severe corrosion of equipment in high pressure gas condensate wells has been a problem for several years and numerous papers have been presented on the subject. The term "gas condensate" or "distillate well" is applied to a distinct variety of hydrocarbon producing well, the characteristics of these wells being high bottom-hole (formation) pressures and temperatures and high gas production. These wells usually produce about 40 gal of water per million cubic feet of gas and the gas contains from 0.1 pct to 2 pct carbon dioxide. In the operation of this type of well, the operators soon noted severe internal corrosion of the pipe carrying the production. In some instances the dl tubing has been found to be corroded to perforation in eight months. The high well head pressures of 2500 to 8000 psi makes any weakening of the well equipment by corrosion extremely hazardous. Bursting of the well equipment results in very expensive repair operations and may result in the loss of valuable production, loss of the costly well, or even loss of life. In November 1944, a gas-condensate well in a Gulf Coast field producing from 9500 ft showed a tubing leak. The well was "killed" by filling it with mud through the tubing, and then the tubing was pulled. Corrosion was found to have caused several perforations in the tubing, Fig I. While the mud was being circulated to kill the well, a high pressure jet from the corroded hole in the tubing perforated the casing and damaged the well to the extent that the cost of repairs amounted to $75,000. In November 1944, another gas-con-densate well in a Gulf Coast field producing from 11,400 ft showed tubing failure. This well had been producing an average of 2,500,000 cu ft of gas daily for two years. In the workover of this well, it was found that a hole one inch in diameter had corroded through the tubing and that corrosion had reduced the wall of the tubing to less than half the standard thickness over large areas of the interior of the tubing. It was found that corrosion had also caused two leaks in the casing. After four months spent in an attempted workover failed to make the well safe for further production, the well was plugged and abandoned at a total loss of $300,000,00.

Jan 1, 1948

By P. L. Menaul, P. P. Spafford

This paper discusses the most dangerous form of corrosion encountered in condensate-well oil production, the discovery of the agent causing this corrosion and the remedial chemical treatment proved effective by field use. The injection of ammonium hydroxide, even as little as one quart per day, has proved effective in preventing gas-condensate well corrosion. The injection of "Bone oil" is applied to wells producing brines containing calcium and magnesium salts. Introduction The severe corrosion of equipment in high pressure gas condensate wells has been a problem for several years and numerous papers have been presented on the subject. The term "gas condensate" or "distillate well" is applied to a distinct variety of hydrocarbon producing well, the characteristics of these wells being high bottom-hole (formation) pressures and temperatures and high gas production. These wells usually produce about 40 gal of water per million cubic feet of gas and the gas contains from 0.1 pct to 2 pct carbon dioxide. In the operation of this type of well, the operators soon noted severe internal corrosion of the pipe carrying the production. In some instances the dl tubing has been found to be corroded to perforation in eight months. The high well head pressures of 2500 to 8000 psi makes any weakening of the well equipment by corrosion extremely hazardous. Bursting of the well equipment results in very expensive repair operations and may result in the loss of valuable production, loss of the costly well, or even loss of life. In November 1944, a gas-condensate well in a Gulf Coast field producing from 9500 ft showed a tubing leak. The well was "killed" by filling it with mud through the tubing, and then the tubing was pulled. Corrosion was found to have caused several perforations in the tubing, Fig I. While the mud was being circulated to kill the well, a high pressure jet from the corroded hole in the tubing perforated the casing and damaged the well to the extent that the cost of repairs amounted to $75,000. In November 1944, another gas-con-densate well in a Gulf Coast field producing from 11,400 ft showed tubing failure. This well had been producing an average of 2,500,000 cu ft of gas daily for two years. In the workover of this well, it was found that a hole one inch in diameter had corroded through the tubing and that corrosion had reduced the wall of the tubing to less than half the standard thickness over large areas of the interior of the tubing. It was found that corrosion had also caused two leaks in the casing. After four months spent in an attempted workover failed to make the well safe for further production, the well was plugged and abandoned at a total loss of $300,000,00.

Jan 1, 1948

By Morris Muskat

Although the problem of well spacing is one of the most important involved in the production of oil, it must be considered at the present time as still subject to further development. The published literature on this question is so voluminous that we cannot enter here into a review of it, except to refer to the recent papers by L. L. Foleyl and E. A. Stephen-son,2 where other references are cited. However, a decisive and conclusive answer to the problem of well spacing in any general form does not seem to have been developed. And while we shall be unable to present the desired solution in the present paper, it is nevertheless felt that the material to be given here not only provides the physical ground work for the ultimate solution, but shows qualitatively the essential factors that enter the well-spacing problem. Field studies of the well-spacing problem, in which the ultimate recoveries from different fields with different well spacings have been compared, have generally suffered from the lack of knowledge as to the similarity of the inherent characteristics of the producing reservoirs being compared, such as the sand volumes, the sand porosities, the sand permeabilities, the original reservoir pressures, the presence or absence of gas caps, the presence or absence of effective water drives, and the economic limits of production rates at which the various fields were considered to have yielded their ultimate recoveries. Certainly no one who is evaluating originally the economic significance of any oil reservoir would deliberately ignore these phases of the problem. And it is equally certain that no one would reasonably expect the ultimate recoveries from two reservoirs, even with the same well spacing, to be identical regardless of these other factors. More reliable results might be expected from comparisons of the recoveries obtained from different leases with different well spacings, but producing from the same reservoir sand. Unfortunately, however, even conclusions for such studies may be subject to serious errors. The reason simply is that however much one may insist that an operator is entitled only to the oil immediately underneath his surface acreage he will nevertheless drain the surrounding properties as long as his reservoir

Jan 1, 1940