Search Documents

By F. L. Ruhlman, Max C. Eastman

The termination of the recent war marked a major changc in the oil-field operations at. Elk Hills. Production was greatly curtailed, various experimental production projects were started, and a long-range exploratory program was inaugurated. Production was reduced from the wartime peak of 65,000 bbl per day to the current rate of about 8ooo bbl per day in order to maintain an available source of crude that can be drawn upon during a national emergency. The existing production rate is deemed essential to carry on the experimental production projects. These projects are being conducted to determine the best methods and means of maintaining the Reserve, shut in, but in a state of readiness to produce the maximum quantity of oil in the most expeditious manner. Projects now being investigated include: (I) protection of surface equipmerit; (2) repair of wells that might damage the reservoir; (3) gas injection; (4) water eneroachment, (5) gravity drainage. An exploratory program is being carried on to determine the amount of recoverable oil in the unexplored portions of the Reserve. The Shallow-zone exploration is practically completed, but owing to the complexity of the Stevens structure and the magnitude of the oil discoveries in the Stevens, exploration will probably continue in that zone for another two years. Introduction Summary of Development History of Elk Hills Although a detailed history of Elk Hills oil field is presented in various publications,1,2 a summary of its unusual development and production history will be given in order that the present problems may be more readily understood. The first development that resulted in commercial production was in the central part of the Reserve. The first well, Hay No. I, in sec 36-R,* was completed in January I9I9, and was soon followed by 37 Others in the same general area. It is commonly referred to as the Hay-Carman area and was shut in in stages from 1925 to 1934 as a result of litigation regarding the title to the land. Not being highly producti,, only about 6½ million barrels of oil with a large volume of gas was produced from the area prior to the shutdown. Shortly after the start of the development of the Hay-Carman area, drilling was started 6 miles east in sec 36-S' Tupman NO. I came in for 5000 bbl per day early in I92o, It was followed by more than 200 others in the next few years, and the field became one of major importance. Produc-

Jan 1, 1949

By Joseph Chalmers, E. L. Rawlins, D. B. Taliaferro

PRoblems dealing with the movement or migration of fluids through porous beds have been the subject of much research. The subject is not peculiar to the production of oil and gas, as many investigators have studied the nature of this movement and its relationship to the problems of other industries. Darcyl conducted a series of experiments relating to the percolation of water through filter beds. King2 carried on an extensive series of laboratory experiments with the object of formulating some conception of the rate of movement of water through soils and sand strata in the drainage of surface water into underground channels and subsequent recovery of this water through wells drilled into the source beds for irrigation purposes. Slichter3 undertook a study of the same problem from a mathematical standpoint, and more recently Furnas4 has investigated the flow of gases through beds of broken solids with particular reference to blast-furnace operation. With specific reference to gas production, Muskat and Botset5 of the Gulf Research Laboratory undertook an experimental study to establish quantitatively the characteristics of and laws governing the flow of gases through consolidated and unconsolidated porous materials of fine texture with a view of predicting the performance of gas in an underground reservoir. There seems to be a general agreement that many of the relationships between the numerousfactors influencing the flow of fluids through porous materials are far too complicated to be attacked by analytical methods based upon a knowledge of hydrodynamics. For gases, the laws of

Jan 1, 1932

By H. N. Herrick

The flow characteristics of drilling muds, as described in this paper, and the method given for solving problems relating to the flow of these muds through pipe and accessory equipment, are based on a conception that drilling muds are plastic solids like paints or greases; not liquids. The data presented in this report have been obtained from studies of California muds, chiefly those used in the Kettleman Hills field, by the Producing Department of the Standard Oil Company of California. Although no claim of scientific exactness is made for the formulas and diagrams, since the data upon which they are based are not complete even for California muds, the method has proved to be a convenient means for estimating, closely enough for practical purposes, the pressures required to force muds at various rates through pipe systems in which-they are handled. Certain approximations have been made to simplify the procedures so that they can be used easily in the field. Viscosity and Shearing Strength of Mud For the purpose of this discussion a plastic solid is defined as a material in which no deformation or flow takes place when the material is subjected to shearing forces, until the shearing force reaches a value called the "yield point." With liquids, the smallest force will produce continuous deformation; that is, the yield point of liquids is zero. The difference between true liquids and muds is illustrated in Fig. 1, which shows rates of flow through a small tube under different pressures. The flow rate of the liquids is directly proportional to the pressure and that of the muds is not. The behavior of drilling mud does not conform in every detail with the definition of a plastic solid as given, because mud actually flows slightly at pressures below its yield point. However, for practical purposes the definition describes the condition adequately and has the advantage of simplicity. In order to make mud-flow calculations based on the theory that mud is a plastic solid, it is necessary to know the "yield point" of the mud, which hereinafter is defined by equation 1 under the caption "Viscosity

Jan 1, 1932

By James T. Wood

Stratigraphy, structure and closure of the Paloma field are discussed, with some details regarding the present state of development. The Paloma anticline, a large dome modified by faults, is the largest single closed dome in the southern San Joaquin valley without surface outcrop or topographic expression. It owes its discovery to geophysics. Of nine wells drilled to the Stevens sand, seven are productive. The ultimate productive area may approximate 3000 acres when the limits of the field are determined. Introduction The Paloma field derives its name from the Paloma school, ½ mile north of what is now the center of the field. The field is 17 miles southwest of Bakers-field, in the south central part of the San Joaquin Valley (Fig. I). The present developed area and its expected extensions are in townships 31 and 32S., R.26E. It is the most southerly of several fields that produce from the Stevens sand zone. The first well to produce condensate was a joint test drilled by the Western Gulf Oil Co. and The Texas Co. near the center of sec. 3, T.32S., R.26E., well No. 54-3. This well was completed on Aug. 31, 1939, at a depth of 10,178 ft. The initial production was 2280 bbl. a day of condensate and 14,750,000 cu. ft. of gas (½-hr. gauge) through a ?-in. bean. Prior to the drilling of this well, the Ohio Oil Co. discovered and developed a small gas field, which embraces a part of three townships about their common corner but lies chiefly in secs. 31 and 32, T.31S., R.26E. The first well was completed on July I, 1934, at a plugged depth of 5239 ft. after having been drilled to 7957 ft, production was found in a 59-ft. zone IIO ft. below the Fourth Mya bed, within the Sari Joaquin clays. Until recently this field was known as the Buena Vista gas field. It is now carried by the Division of Oil and Gas as the Paloma gas field. Production within the Paloma gas field is derived from six wells, producing from several different zones in the interval from 4177 to 5548 feet. Geology Stratigraphy The sediments penetrated by wells in the Paloma held range in age from Recent to Upper Miocene. The entire section, which exceeds 10,000 ft. in thickness, conforms generally to the standard section of the south central San Joaquin Valley. The producing zone, sometimes called the Paloma sand, is the approximate equivalent of the Stevens sand zone of the Ten Section, Canal, Coles Levee and other fields. The stratigraphic section is shown in Table I. Paloma Producing Zone* (Stevens Sand Zone, Upper Miocene) .-The Paloma producing zone (Fig. 2), frequently referred to as the Paloma sand, is encountered at depths ranging from 9950 to 10,300 ft. In general, it is a massive, firm to hard, not too well sorted, fine to medium fine sand. It is interbedded with thin, hard, calcareous sand shells of similar texture and cherty

Jan 1, 1942

By James T. Wood

Stratigraphy, structure and closure of the Paloma field are discussed, with some details regarding the present state of development. The Paloma anticline, a large dome modified by faults, is the largest single closed dome in the southern San Joaquin valley without surface outcrop or topographic expression. It owes its discovery to geophysics. Of nine wells drilled to the Stevens sand, seven are productive. The ultimate productive area may approximate 3000 acres when the limits of the field are determined. Introduction The Paloma field derives its name from the Paloma school, ½ mile north of what is now the center of the field. The field is 17 miles southwest of Bakers-field, in the south central part of the San Joaquin Valley (Fig. I). The present developed area and its expected extensions are in townships 31 and 32S., R.26E. It is the most southerly of several fields that produce from the Stevens sand zone. The first well to produce condensate was a joint test drilled by the Western Gulf Oil Co. and The Texas Co. near the center of sec. 3, T.32S., R.26E., well No. 54-3. This well was completed on Aug. 31, 1939, at a depth of 10,178 ft. The initial production was 2280 bbl. a day of condensate and 14,750,000 cu. ft. of gas (½-hr. gauge) through a ?-in. bean. Prior to the drilling of this well, the Ohio Oil Co. discovered and developed a small gas field, which embraces a part of three townships about their common corner but lies chiefly in secs. 31 and 32, T.31S., R.26E. The first well was completed on July I, 1934, at a plugged depth of 5239 ft. after having been drilled to 7957 ft, production was found in a 59-ft. zone IIO ft. below the Fourth Mya bed, within the Sari Joaquin clays. Until recently this field was known as the Buena Vista gas field. It is now carried by the Division of Oil and Gas as the Paloma gas field. Production within the Paloma gas field is derived from six wells, producing from several different zones in the interval from 4177 to 5548 feet. Geology Stratigraphy The sediments penetrated by wells in the Paloma held range in age from Recent to Upper Miocene. The entire section, which exceeds 10,000 ft. in thickness, conforms generally to the standard section of the south central San Joaquin Valley. The producing zone, sometimes called the Paloma sand, is the approximate equivalent of the Stevens sand zone of the Ten Section, Canal, Coles Levee and other fields. The stratigraphic section is shown in Table I. Paloma Producing Zone* (Stevens Sand Zone, Upper Miocene) .-The Paloma producing zone (Fig. 2), frequently referred to as the Paloma sand, is encountered at depths ranging from 9950 to 10,300 ft. In general, it is a massive, firm to hard, not too well sorted, fine to medium fine sand. It is interbedded with thin, hard, calcareous sand shells of similar texture and cherty

Jan 1, 1942

By S. F. Shaw

The theory that maintaining a high back-pressure on the oil sand lowers the viscosity of the oil has been generally accepted. The theory has also been advanced that lower viscosity permits the oil to be moved through the sand to the well at an expenditure of less gas per barrel of oil than would otherwise be required. It seems reasonable to assume that production of oil at the minimum gas-oil ratio will result in a greater ultimate recovery of oil. During the past five years the writer has acquired data on thousands of tests made on wells to determine the best rate at which to produce them. In the majority of cases reduction in back-pressure did not definitely increase the gas-oil ratio. The information obtained from these tests has raised doubt in the mind of the writer as to the correctness of the theory that lowered viscosity results in lower gas-oil ratios and in higher ultimate recovery of oil. The reasons that explain the results obtained in these tests cannot yet be definitely stated, but the hypothesis is being tentatively assumed that there are other factors which outweigh the influence of viscosity. Energy in Gas Moves Oil to Well The general opinion is that in most cases it is the energy in the gas that moves the oil to the well. In wells flowing naturally it is also the energy in the gas that lifts the oil to the surface. In a flowing well, there are two very distinct operations: 1. Moving the oil through the sand to the well. 2. Lifting the oil to the surface. The more important function of the gas is that of moving the oil to the well. Means for lifting the oil can always be found once it has been delivered to the well. Principles Involved in Lifting Oil A well that flows naturally is the same as a gas-lift well except that all of the gas is supplied by the oil reservoir. This natural flow is subject

Jan 1, 1931

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 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 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

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

By Hallan N. Marsh

The subject of mud sounds so simple, uninteresting and unimportant that it has failed to receive the attention that it deserves, at least as applied to the drilling of oil wells. As a matter of fact, it is one of the most complicated, technical, important and interesting subjects in connection with rotary drilling. In 1923, R. E. Colloml said "It should be possible to establish certain physical standards for mud fluid," but while considerable work has probably been done on the subject before and since that time, and numerous articles have been written, the progress of general knowledge of the subject and the application of better practices have not kept pace with other developments in rotary drilling, and physical standards cannot be considered as established. Mud is apt to be thought of as an accessible and cheap material, but its cost is likely to be an important factor in the total cost of drilling a well. Some wells "make" most of their own mud out of the formations drilled, but in most cases a great deal of mud-making material has to be supplied from more or less distant sources. Expenditures for mud materials by one California company totaled practically one-quarter million dollars during 1929 and averaged about $13 per rig per drilling day, or about $2000 per well. Under unfavorable conditions, mud cost may reach many times this figure. Parker2 says that in the Hobbs, N. M., field "as much as $75,000 has been spent on one well alone for mud and mud-weighting compounds."' Presumably this is an exceptional case. Unit cost of mud fluid will range from 10 c. per barrel, where suitable material is close at hand, to $1 where crude material is available at moderate price but must be hauled long distances, and on up to as much as $11 per barrel where high gas pressure requires the use of special processed weighting material. The cost of mud pales into insignificance, however, when the results of using improper mud are considered. Blow-outs and lost circulation are obviously the result of inadequate mud. Stuck drill pipe, whether or not twisted off, in many if not most cases probably is caused by cuttings settling out of the mud or the mud itself precipitating. Recent experi-

Jan 1, 1931

By M. J. Kirwan, K. A. Covell

This paper covers a brief discussion of pumping 38° to 41° gravity oil from Wilcox sand wells ranging in depths from 4000 to 4900 ft. in the Seminole field, Oklahoma. As recently as a year ago it was the general belief among Seminole operators that most wells in that district could not be successfully or economically pumped. Also the idea was prevalent at that time that the crookedness of the rotary holes would cause a large amount of mechanical trouble and the use of the air-gas lift would leave the wells depleted with sand conditions and fluid levels unfavorable for pumping. At that time it was predicted that wells would be abandoned when the economic flowing and swabbing period was reached. Contrary to these beliefs it has been demonstrated that wells can be profitably pumped to limits as low as 10 bbl. of oil per day where conditions are favorable. The Serllinole field, unusual in its rapid development, has served as an experimental laboratory for many oil field pumping devices with which this paper will not concern itself. Discussion will be confined to equipment and methods in general use throughout the field. The outstanding features of equipment and pumping operations covered in this paper may be summarized as follows: 1. Pumping equipment from the standpoint of prime movers, energy cost, power transmission equipment, derricks, counterbalances, beam hangers, tubing, sucker rods, pumps, etc. 2. Pumping problems peculiar to the Seminole field, including the proper time at which to change from air-gas lift flowing to pumping. Pumping Equipment There have been no basic changes in pumping equipment in the past 20 years with the exception of some refinements in design brought about by the demand for equipment suitable for pumping deep wells. Results of research in the heat treatment of metals and progress made by the American Petroleum Institute in standardization of equipment, together with the cooperation of oil field equipment manufacturers, have

Jan 1, 1929

By Milton Williams

It is generally recognized that fluid is lost from rotary drilling muds to permeable strata during normal drilling operations;1,2-3 but that this fluid is the filtrate from the mud, rather than the mud itself, has been shown by various workers.1,4,5 The presence of this filtrate in oil-bearing or gas-bearing strata is undesirable and harmful. The decreased permeability of the stratum to oil effected by the presence of water has been pointed out by several investigators,6,7 and since, in the production of the reservoir fluid, the greatest pressure drop occurs immediately adjacent to the borehole, it follows that infiltered water is particularly objectionable in this region. Again, this filtrate tends to make electrical logs less reliable, since oil in the proximity of the borehole is probably flushed out to an appreciable extent by the water.8 Observation of side wall cores may be misleading for the same reason. Drill-stem tests in low-pressure areas may be of doubtful value where no oil is recovered, unless sufficient time is allowed for production of water lost from the mud. The infiltered water may hinder drilling operations by softening shales and causing sloughing; the ['tight hole" occasioned by excessive deposition of filter cake in the hole is a common occurrence. The filter cake remaining on the face of the producing formation may itself sometimes be detrimental to production.9 In view of these implications of the importance of filtration of mud, an investigation was undertaken to determine the factors involved in the infiltration process, and to correlate these in such a manner that the values obtained in routine filter tests employing a conventional filter of the "wall-building tester" type,10 together with data on size of hole, drill pipe, and rate of mud circulation, could be used to estimate water loss and distance of penetration of the filtrate into strata. Quantitative relations of filter-cake permeability, filtrate viscosity, and rate of filtration have been developed for filtration in the simple laboratory filter.4a,11,12,13 It is obvious, however, that the conditions

Jan 1, 1940

By Milton Williams

It is generally recognized that fluid is lost from rotary drilling muds to permeable strata during normal drilling operations;1,2-3 but that this fluid is the filtrate from the mud, rather than the mud itself, has been shown by various workers.1,4,5 The presence of this filtrate in oil-bearing or gas-bearing strata is undesirable and harmful. The decreased permeability of the stratum to oil effected by the presence of water has been pointed out by several investigators,6,7 and since, in the production of the reservoir fluid, the greatest pressure drop occurs immediately adjacent to the borehole, it follows that infiltered water is particularly objectionable in this region. Again, this filtrate tends to make electrical logs less reliable, since oil in the proximity of the borehole is probably flushed out to an appreciable extent by the water.8 Observation of side wall cores may be misleading for the same reason. Drill-stem tests in low-pressure areas may be of doubtful value where no oil is recovered, unless sufficient time is allowed for production of water lost from the mud. The infiltered water may hinder drilling operations by softening shales and causing sloughing; the ['tight hole" occasioned by excessive deposition of filter cake in the hole is a common occurrence. The filter cake remaining on the face of the producing formation may itself sometimes be detrimental to production.9 In view of these implications of the importance of filtration of mud, an investigation was undertaken to determine the factors involved in the infiltration process, and to correlate these in such a manner that the values obtained in routine filter tests employing a conventional filter of the "wall-building tester" type,10 together with data on size of hole, drill pipe, and rate of mud circulation, could be used to estimate water loss and distance of penetration of the filtrate into strata. Quantitative relations of filter-cake permeability, filtrate viscosity, and rate of filtration have been developed for filtration in the simple laboratory filter.4a,11,12,13 It is obvious, however, that the conditions

Jan 1, 1940

By H. P. Schwede, H. G. Doll

This paper describes a method to provide identification of particular depths in a borehole through the use of radioactive markers. The correlation of a marker, placed in the wall of a borehole, with known points of the electrical log and with the casing collars in the cased hole permits accurate positioning of tools with respect to a formation, regardless of absolute depth. Such a process is particularly useful in gun perforation of a casing in a well. Technique and equipment are discussed and illustrated. Examples are given of practical application in the field. Introduction During the past decade the search for petroleum has increased the importance of testing zones at depths in wells which have become progressively deeper. The development of new techniques, such as electrical logging, has permitted the identification of producing formations which consist of comparatively thin strata. When thin beds are to be produced at great depths, the problem of positioning tools accurately to place the well in production becomes acute.l Continuous consideration is being given in the petroleum industry towards the improvement of depth measurements in a borehole. The accuracy in absolute depth measurements, whether made in an open or cased hole, whether determined by a cable or a drill pipe, depends upon a number of factors, such as tension, temperature, and calibration. For example, the effects of tension from the weight of 10,000 ft of drill pipe and the thermal expansion of this length . of pipe, where its average temperature has increased SO"', will Produce an elongation as much as 8 ft.2 The effects Of such factors can be minimized through the use of care in depth measurements, the application of corrections based on experience, and continuous calibration or checking. The fact that different methods and different tools are used to determine the depths of formations in wells will sometimes give rise to a difference between measurements. It is evident that an important requirement in a well is the ability to locate at will any subsurface point. While absolute depth measurements have ion in recent years, it is reassuring to have other means to verify, for example, that a casing is perforated at a particular place with reference to a zone within a formation. Such a check on measurements may be had by placing a reference marker at a point known with respect to the electrical log of the borehole. That point is usually chosen to be in proximity to the 'One to be perforated. Thus, only short in depth measurements are made and any inaccuracy becomes very small and of minor importance' The use of reference markers located at fixed points predetermined in each zone where future operations are contemplated enables the operator to position any tool

Jan 1, 1948

By H. G. Doll, H. P. Schwede

This paper describes a method to provide identification of particular depths in a borehole through the use of radioactive markers. The correlation of a marker, placed in the wall of a borehole, with known points of the electrical log and with the casing collars in the cased hole permits accurate positioning of tools with respect to a formation, regardless of absolute depth. Such a process is particularly useful in gun perforation of a casing in a well. Technique and equipment are discussed and illustrated. Examples are given of practical application in the field. Introduction During the past decade the search for petroleum has increased the importance of testing zones at depths in wells which have become progressively deeper. The development of new techniques, such as electrical logging, has permitted the identification of producing formations which consist of comparatively thin strata. When thin beds are to be produced at great depths, the problem of positioning tools accurately to place the well in production becomes acute.l Continuous consideration is being given in the petroleum industry towards the improvement of depth measurements in a borehole. The accuracy in absolute depth measurements, whether made in an open or cased hole, whether determined by a cable or a drill pipe, depends upon a number of factors, such as tension, temperature, and calibration. For example, the effects of tension from the weight of 10,000 ft of drill pipe and the thermal expansion of this length . of pipe, where its average temperature has increased SO"', will Produce an elongation as much as 8 ft.2 The effects Of such factors can be minimized through the use of care in depth measurements, the application of corrections based on experience, and continuous calibration or checking. The fact that different methods and different tools are used to determine the depths of formations in wells will sometimes give rise to a difference between measurements. It is evident that an important requirement in a well is the ability to locate at will any subsurface point. While absolute depth measurements have ion in recent years, it is reassuring to have other means to verify, for example, that a casing is perforated at a particular place with reference to a zone within a formation. Such a check on measurements may be had by placing a reference marker at a point known with respect to the electrical log of the borehole. That point is usually chosen to be in proximity to the 'One to be perforated. Thus, only short in depth measurements are made and any inaccuracy becomes very small and of minor importance' The use of reference markers located at fixed points predetermined in each zone where future operations are contemplated enables the operator to position any tool

Jan 1, 1948