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By Hallan N. Marsh

The subject of this paper is apt to bring to mind wells ranging from 6000 to over 8000 ft. in depth. However, it is uncommon to pump wells at depths greater than about 5000 ft. Fig. 1 shows the number of wells being pumped at various depths by one company in Southern California. A few companies have a very few wells pumping at depths greater than this. This paper will deal with wells between 3000 and 5500 ft. in depth. Most California oils at these depths are between 25" and 35" gravity. The subject is so broad that it will be necessary to omit many interesting phases, and to treat others very briefly. Power, power transmission equipment, power efficiency, counterbalancing, sucker rods, pumps and volumetric efficiency will be discussed. Power As a source of power, the 50/20-hp. electric motor is generally preferred. Input is generally between 10 and 25 hp. Due to the uneven-ness of the load, an input of 20 hp. on the low range is generally about all that these motors will carry without overheating, in spite of their overload capacity. In some cases the capacity of the motor limits the speed

Jan 1, 1929

By W. V. Vietti

Actual field data from several wells are used to illustrate the application of the method of determining the average density of the fluid column in a flowing oil well in the Yates field, Pecos County, Texas. The depths of the wells in the Yates field vary from 900 to 1700 ft., depending on surface elevation and the location of the wells on structure. Production rates over 8000 bbl. per hour have been determined and many wells are capable of producing 2000 bbl. hourly. Gas-oil ratios are usually below 400 cu. ft. per barrel, but a few wells high on structure have produced over 3000 cu. ft. per barrel. Incidentally, tubing wells has cut these high ratios to as low as 400 cu. ft.' By common agreement of the operators all wells making ratios over 400 cu. ft. will be tubed. Daily production of the field is prorated to 110,000 bbl. from an open-flow potential of 5,000,000 bbl. based on hourly open-flow gages.

Jan 1, 1931

By Lynn G. Howell, Alex Frosch

In a previous article1 we have described a technique for measuring the relative intensities of gamma rays from the radioactive elements occurring naturally in geological formations along the walls of a borehole. The apparatus consisted of two Geiger-Müller tubes mounted inside a pressure-tight chamber. Each counter tube was coupled separately to an amplifier and a frequency meter at the surface by means of a multiconductor cable upon which the chamber was suspended. The output currents of the two frequency meters were recorded on a photographic paper as the chamber was moved in the hole. These traces showed remarkable correlation with the geologic formations, as evidenced by comparison with commercial electrical logs.2 Owing to the penetrating power of the gamma rays, logs may be taken in both open and cased boreholes. The apparatus has recently been changed somewhat. One of the counter tubes has been removed and a stage of amplification has been added inside the chamber. This arrangement seems to give a more favorable signal-to-noise ratio and satisfactory logs can be now made in cased holes and also in open holes as previously. Briefly described, the chamber moving in the hole is made of 3½-in. drill pipe and is about 10 ft. long. There is an additional extension about 2 ft. long at the top, inside which cable connections are made. The Geiger-Müller tube is mounted inside the bottom end of the chamber. Above this is the vacuum-tube amplifier with its batteries and transformer. In the top part of the chamber, small 45-volt batteries are mounted, which in part supply the high voltage for the counter tube. Additional voltage is supplied from the surface through the multiconductor cable upon which the chamber is suspended. Also, the output of the transformer in the single-stage amplifier is coupled to another single-stage amplifier at the surface through this cable. The surface amplifier is coupled to the Thyratron-controlled frequency meter, the tank circuit of which consists of a one megohm resistor across which is a bank of condensers varying in

Jan 1, 1940

By Alex Frosch, Lynn G. Howell

In a previous article1 we have described a technique for measuring the relative intensities of gamma rays from the radioactive elements occurring naturally in geological formations along the walls of a borehole. The apparatus consisted of two Geiger-Müller tubes mounted inside a pressure-tight chamber. Each counter tube was coupled separately to an amplifier and a frequency meter at the surface by means of a multiconductor cable upon which the chamber was suspended. The output currents of the two frequency meters were recorded on a photographic paper as the chamber was moved in the hole. These traces showed remarkable correlation with the geologic formations, as evidenced by comparison with commercial electrical logs.2 Owing to the penetrating power of the gamma rays, logs may be taken in both open and cased boreholes. The apparatus has recently been changed somewhat. One of the counter tubes has been removed and a stage of amplification has been added inside the chamber. This arrangement seems to give a more favorable signal-to-noise ratio and satisfactory logs can be now made in cased holes and also in open holes as previously. Briefly described, the chamber moving in the hole is made of 3½-in. drill pipe and is about 10 ft. long. There is an additional extension about 2 ft. long at the top, inside which cable connections are made. The Geiger-Müller tube is mounted inside the bottom end of the chamber. Above this is the vacuum-tube amplifier with its batteries and transformer. In the top part of the chamber, small 45-volt batteries are mounted, which in part supply the high voltage for the counter tube. Additional voltage is supplied from the surface through the multiconductor cable upon which the chamber is suspended. Also, the output of the transformer in the single-stage amplifier is coupled to another single-stage amplifier at the surface through this cable. The surface amplifier is coupled to the Thyratron-controlled frequency meter, the tank circuit of which consists of a one megohm resistor across which is a bank of condensers varying in

Jan 1, 1940

By Dale Nix

DuRing the past year approximately 400 depth pressures have been recorded in the Yates field. Of these, 315 were "shut-in depth pressures," observed for the purpose of adjusting well potentials without making open-flow tests. The "shut-in depth pressures" were distributed one to each well and determined under as nearly uniform conditions as possible. Therefore, there is a scarcity of data applicable to production problems, other than the adjusting of well potentials. A few of the data obtained have been used in an attempt to solve some of the producing problems. These applications, however, merely indicate partial solutions and their review herein is to emphasize the variety of problems to which depth-pressure data can be applied, rather than to present conclusive solutions. Very little had been accomplished in the development of instruments to determine pressures within the well bore, when it was decided to obtain such information in the Yates field. Through the combined efforts of the Yates Engineering Committee and several producing companies, three methods of determining pressures in the well bore were soon developed: (1) the "compressor" method, (2) the "volume chamber" method, (3) the "depth-pressure recorder" method. "Compressor" Method.—A small volume compressor is used to inject gas into the tubing. The rate of injection is low so that the frictional losses will be reduced to a minimum. During the test, the pressures at the top of the tubing and casing are observed on recording pressure gages. .As the compressed gas depresses the fluid in the tubing, the pressure on the casing decreases while the tubing pressure increases. The tubing pressure becomes a maximum when the fluid level reaches the bottom of the tubing; and the casing pressure usually rises quickly as the gas breaks around the bottom of the tubing. The sum of the maximum pressure recorded at the top of the tubing and the pressure exerted by the weight of the compressed gas column is equal to the depth pressure at the bottom of the tubing. The procedure can be reversed;

Jan 1, 1932

By C. P. Walker

Determining the distance to remote objects by observing the time required for sound to traverse the intervening space is an old practice. Attempts have been made to use this method for determining the fluid level in oil wells but as far as the writer is aware it was not found to be practicable, because vibrations in gas in the audible frequency range do not travel as well and as far as low-frequency pressure waves, which are capable of transmitting a greater amount of energy than can be transmitted by audible waves. Wood, in his book "Sound," states that in a given medium the range of sound transmission will vary inversely as the square of the frequency. The fact that the sound from a whistle having a low tone has a much lower attenuation rate than that from a whistle of high pitch is well known. Also, the pressure waves caused by cannon fire often rattle windows at points so distant that no sound of the cannon is heard. In 1932 P. E. Lehr and H. T. Wyatt, of the Shell Oil Co., experimented with the principle of the concussion, or pressure-wave echo, method of determining fluid levels in oil wells. They released compressed gas into the top of the casing, thereby creating a pressure wave, which traveled down the well and back again. Their experiments proved conclusively that, with the proper apparatus for recording the echoes and determining the velocities at which the waves travel, the method could be used successfully for determining fluid levels in oil wells. Wells are often equipped with from one to three tubing catchers and these together with the top of the liner are frequently above the fluid. Each of these obstructions reflects a part of the pressure wave. In such wells there may be, therefore, as many as five pressure-wave reflections. Thus it is obvious that in order to identify the various reflections and to determine therefrom the fluid level in a well it is necessary to obtain a graphic record of these reflections.

Jan 1, 1937

By Charles C. Rodd

Prior to 1938, proration procedure in Kansas required the physical testing of wells in order to set up a basis for allocating production. Subsequently the use of liquid-level data and bottom-hole pressure data was authorized on certain types of wells as a basis for calculating well capacities, thereby permitting wells to be tested at low rates and with small volumes of production. This paper gives some attention to the equipment used for obtaining liquid-level data but in general it is devoted to the theoretical and physical factors involved in well testing by drawdown methods. These tests are divided into two classifications: (I) liquid-level data used directly to calculate capacities, and (2) liquid-level data and liquid-level measuring equipment used in connection with other data to determine bottom-hole pressure. Equations and calculations for both types are shown. Well capacities calculated from fill-up data have not been used generally but offer a simple means of testing some wells. Theoretical factors and calculations for such tests are shown. In the state of Kansas, proration laws required that the "ability of a well to produce" be given consideration in state allocation orders and for many years this was the only factor used in prorating the allowed oil. The "ability of a well to produce", was the quantity of oil that could be obtained from a well in a prescribed period, usually 24 hr. Early in the history of State-regulated proration, Kansas operators realized that, unless some restriction were placed upon equip- ment, the competition between producers to obtain large well "potentials" might result in a race to install the largest pumping equipment. Consequently, restrictions were placed upon the size of tubing and length of pump stroke that could be used in pumping wells during potential tests. Later, restrictions were placed also upon the size of tubing and chokes that could be used in flowing walls. Despite the restriction setup, better pumping equipment was designed and installed, pumps were improved, and various devices were invoked to obtain high rates of production for short periods of time. By 1937 pumping cycles of forty to forty-five 54-in. strokes per minute were not uncommon, and numerous wells had produced at the rate of 3500 bbl. per day for short periods. Such production was far beyond any rate that could be long sustained. Equipment necessary to take "potentials" was several times larger than that needed for normal producing purposes, and repairs and replacements required by the high pumping speeds were excessive. Also, many operators suspected that the high rates of production main tained during '"potential" tests were conducivc to early water encroachment. By 1938 large-scale physical testing of wells in Kansas ended, the use of the bottom-hole pressure gauge had become common, engineers and operators were becoming familiar with the term ''productivity index," and bottom-hole pressure was being used as a factor in allocation in many areas. There were many drawbacks, however, to large-scale use of

Jan 1, 1943

By Charles C. Rodd

Prior to 1938, proration procedure in Kansas required the physical testing of wells in order to set up a basis for allocating production. Subsequently the use of liquid-level data and bottom-hole pressure data was authorized on certain types of wells as a basis for calculating well capacities, thereby permitting wells to be tested at low rates and with small volumes of production. This paper gives some attention to the equipment used for obtaining liquid-level data but in general it is devoted to the theoretical and physical factors involved in well testing by drawdown methods. These tests are divided into two classifications: (I) liquid-level data used directly to calculate capacities, and (2) liquid-level data and liquid-level measuring equipment used in connection with other data to determine bottom-hole pressure. Equations and calculations for both types are shown. Well capacities calculated from fill-up data have not been used generally but offer a simple means of testing some wells. Theoretical factors and calculations for such tests are shown. In the state of Kansas, proration laws required that the "ability of a well to produce" be given consideration in state allocation orders and for many years this was the only factor used in prorating the allowed oil. The "ability of a well to produce", was the quantity of oil that could be obtained from a well in a prescribed period, usually 24 hr. Early in the history of State-regulated proration, Kansas operators realized that, unless some restriction were placed upon equip- ment, the competition between producers to obtain large well "potentials" might result in a race to install the largest pumping equipment. Consequently, restrictions were placed upon the size of tubing and length of pump stroke that could be used in pumping wells during potential tests. Later, restrictions were placed also upon the size of tubing and chokes that could be used in flowing walls. Despite the restriction setup, better pumping equipment was designed and installed, pumps were improved, and various devices were invoked to obtain high rates of production for short periods of time. By 1937 pumping cycles of forty to forty-five 54-in. strokes per minute were not uncommon, and numerous wells had produced at the rate of 3500 bbl. per day for short periods. Such production was far beyond any rate that could be long sustained. Equipment necessary to take "potentials" was several times larger than that needed for normal producing purposes, and repairs and replacements required by the high pumping speeds were excessive. Also, many operators suspected that the high rates of production main tained during '"potential" tests were conducivc to early water encroachment. By 1938 large-scale physical testing of wells in Kansas ended, the use of the bottom-hole pressure gauge had become common, engineers and operators were becoming familiar with the term ''productivity index," and bottom-hole pressure was being used as a factor in allocation in many areas. There were many drawbacks, however, to large-scale use of

Jan 1, 1943

By E. V. Foran

Among the many newer disclosures that have accompanied the petroleum industry's progressively deeper exploratory drilling is the increased frequency with which the operators are encountering reservoirs of which the products at the time of discovery exist wholly or predominantly in the gas phase. The popular term "distillate pool" is most often used within the industry when referring to this type of reservoir, and in this paper the term is used in that sense. These pools have been observed in many different surroundings. In some places the entire reservoir is filled with the wet gas containing its water-white condensible products in the gas phase but apparently with no dark oil or other hydrocarbon liquids in the reservoir. The 8200-ft. horizon in the Big Lake field in West Texas is a good example of this type. At other places the wet, or distillate-bearing, gas may form a large gas cap directly overlying and in contact with an extensive reserve of dark oil. Oklahoma City, Kettleman Hills, the 8500-ft. horizon in the Big Lake field, and many others are examples of this type. There are also many places in which the wet distillate-bearing gas fills nearly the entire reservoir space, while the dark oil occupies only a narrow, bandlike zone, which marks the boundary of the reservoir along its lowest productive contour. The heavier components of these deep pool gases are generally water white in color, a large portion of which are condensible in a conventional oil and gas separator, when operated under pressures of the order of 400 to 800 Ib. per sq. in. Although the water-white products recovered in the separator sometimes have end points of 650" F. and higher on standard Engler distillation, they occur only in the gas phase in the reservoir. It is entirely possible that even some small amounts of dark colored reservoir components may occur in the gas phase when the temperature is 300" F. and pressures exceed 6000 Ib. per sq. in. Close approaches to these conditions have been encountered in the deepest producing wells. The condensible content of the deep reservoir gases of the many pools that have been tested or produced to date shows a wide variation in both condensible content, per 1000 cu. ft. of gas, and physical character.

Jan 1, 1939

By E. V. Foran

Among the many newer disclosures that have accompanied the petroleum industry's progressively deeper exploratory drilling is the increased frequency with which the operators are encountering reservoirs of which the products at the time of discovery exist wholly or predominantly in the gas phase. The popular term "distillate pool" is most often used within the industry when referring to this type of reservoir, and in this paper the term is used in that sense. These pools have been observed in many different surroundings. In some places the entire reservoir is filled with the wet gas containing its water-white condensible products in the gas phase but apparently with no dark oil or other hydrocarbon liquids in the reservoir. The 8200-ft. horizon in the Big Lake field in West Texas is a good example of this type. At other places the wet, or distillate-bearing, gas may form a large gas cap directly overlying and in contact with an extensive reserve of dark oil. Oklahoma City, Kettleman Hills, the 8500-ft. horizon in the Big Lake field, and many others are examples of this type. There are also many places in which the wet distillate-bearing gas fills nearly the entire reservoir space, while the dark oil occupies only a narrow, bandlike zone, which marks the boundary of the reservoir along its lowest productive contour. The heavier components of these deep pool gases are generally water white in color, a large portion of which are condensible in a conventional oil and gas separator, when operated under pressures of the order of 400 to 800 Ib. per sq. in. Although the water-white products recovered in the separator sometimes have end points of 650" F. and higher on standard Engler distillation, they occur only in the gas phase in the reservoir. It is entirely possible that even some small amounts of dark colored reservoir components may occur in the gas phase when the temperature is 300" F. and pressures exceed 6000 Ib. per sq. in. Close approaches to these conditions have been encountered in the deepest producing wells. The condensible content of the deep reservoir gases of the many pools that have been tested or produced to date shows a wide variation in both condensible content, per 1000 cu. ft. of gas, and physical character.

Jan 1, 1939

By Joseph Jensen, F. W. Hertel

Many fields have been zoned by nature with shales and intermediate waters between oil zones. Limitations thus imposed have been the basis on which a field was developed. In contrast thereto, in the Ventura Avenue field, nature proved more generous. Always expecting to find such similar limitations, operators drilled deeper and deeper into the oil zone without finding any distinctive shale bodies other than the Gosnell shale and only one intermediate water, which became the point below which the final water shut-off of each well was made. Thus, on top of the structure, about 3300 it. of oil-bearing zone has been penetrated below this intermediate water—a distance of 4000 ft. below the Gosnell shale. At first it seemed that the greater penetration in the zone, the better the well. The error of this assumption became evident as time passed. Other pressing attendant problems requiring consideration also developed. In the spring of 1929, the Associated Oil Co., still having a large undrilled area, adopted a method for developing this land by dividing the oil formation into zones, so as to drill two classes of wells and to prepare for others, if conditions in the future justified or required such action. Wells now completed are considered as permanent completions in the zone or class for which they are drilled, and are not looked on as a ready means for deepening or accepted as a temptation for deepening to get some flush production quickly. Provision has also been made to avoid future water problems. The most striking demonstration resulting from such work is the fact that the top of the structure is far from being the point at which the largest oil recovery is made. Wells on the flank of the structure invariably produce with lower gas-oil ratios and secure much larger oil production. Zoning of Oil Sands The Gosnell shale separates the upper light 50 gravity oil from the lower 30 gravity oil below. As the light oil zone is of practically no importance at present, it is not being exploited. The development pro-

Jan 1, 1931

By Carl J. Christensen

This paper presents the development of diamond coring of the Weber sand section in the Rangely Field, Colorado. The description and operation of the diamond-coring equipment is included as well as the economics and results obtained by its use. Diamond coring is compared with the other methods used for drilling the Weber sand. Two types of diamond coring are discussed. The first and the one used most extensively is the regular 6 ?x 3¾-in. diamond bit and bottom hole 50-ft barrel. The second type, which has also been used successfully by Stanolind, consists of a 4 13/16 x 2 11/32-in. cutting bit and reverse circulation coring equipment. The first type will be referred to as regular or conventional diamond coring while the latter type will be referred to as reverse circulation diamond coring. Introduction Diamond coring has been used for many years in mines, quarries, surface coring at dam sites, laboratory work, and so on, but, until recently, had never been used very extensively in coring oil sands and other oil-bearing strata. It was demonstrated early in its development that hard forma-tions could be cut rapidly and that core recoveries far exceeded those obtained with conventional hard rock bits and quite often 100 pet recovery was obtained. However, the poorly constructed diamond-coring equipment and resulting high costs of early diamond coring slowed down its progress. Early in the development Of the Rangely Weber field, Rio Blanco County, Colorado, the Rangely Engineering Committee selected key wells that were to core the Weber section in its entirety. These cores were to be analyzed and various sections tested to gather sufficient information so that accurate reservoir studies could be made. The number of wells selected were kept at a minimum inasmuch as the productive Weber section, which is found at an approximate depth of 6000 ft, is thick, being as much as 600 to 700 ft on top of the structure. The Weber section is also comparatively hard to drill. For instance, one well took 60 days to core 490 ft of Weber sand with conventional coring equipment. It was noticed, however, that Core Labora-verse diamond plug cutter could quickly cut a plug from. one of these hard cores. This fact led to the serious consideration of diamond coring the Weber sand. The first diamond coring at Randy was performed by Stanolind in August 1946 andl although we experienced some difficulties, the results definitely indicated that diamond coring would be successful at Rangely for .coring the Weber sand. As more wells were cored and the equipment improved somewhat, diamond coring became less expensive than drilling the Weber sand with the conventional rock bit. In less than one Year diamond coring has definitely Proved its usefulness in oil-field drilling operations in the Rocky Mountain area where formations quite often drill very hard. The practice of spot coring in hard oil-bearing formations with conventional coring equipment is giving way diaimond coring of the entire sections, thus givng an operator the complete picture.

Jan 1, 1948

By Carl J. Christensen

This paper presents the development of diamond coring of the Weber sand section in the Rangely Field, Colorado. The description and operation of the diamond-coring equipment is included as well as the economics and results obtained by its use. Diamond coring is compared with the other methods used for drilling the Weber sand. Two types of diamond coring are discussed. The first and the one used most extensively is the regular 6 ?x 3¾-in. diamond bit and bottom hole 50-ft barrel. The second type, which has also been used successfully by Stanolind, consists of a 4 13/16 x 2 11/32-in. cutting bit and reverse circulation coring equipment. The first type will be referred to as regular or conventional diamond coring while the latter type will be referred to as reverse circulation diamond coring. Introduction Diamond coring has been used for many years in mines, quarries, surface coring at dam sites, laboratory work, and so on, but, until recently, had never been used very extensively in coring oil sands and other oil-bearing strata. It was demonstrated early in its development that hard forma-tions could be cut rapidly and that core recoveries far exceeded those obtained with conventional hard rock bits and quite often 100 pet recovery was obtained. However, the poorly constructed diamond-coring equipment and resulting high costs of early diamond coring slowed down its progress. Early in the development Of the Rangely Weber field, Rio Blanco County, Colorado, the Rangely Engineering Committee selected key wells that were to core the Weber section in its entirety. These cores were to be analyzed and various sections tested to gather sufficient information so that accurate reservoir studies could be made. The number of wells selected were kept at a minimum inasmuch as the productive Weber section, which is found at an approximate depth of 6000 ft, is thick, being as much as 600 to 700 ft on top of the structure. The Weber section is also comparatively hard to drill. For instance, one well took 60 days to core 490 ft of Weber sand with conventional coring equipment. It was noticed, however, that Core Labora-verse diamond plug cutter could quickly cut a plug from. one of these hard cores. This fact led to the serious consideration of diamond coring the Weber sand. The first diamond coring at Randy was performed by Stanolind in August 1946 andl although we experienced some difficulties, the results definitely indicated that diamond coring would be successful at Rangely for .coring the Weber sand. As more wells were cored and the equipment improved somewhat, diamond coring became less expensive than drilling the Weber sand with the conventional rock bit. In less than one Year diamond coring has definitely Proved its usefulness in oil-field drilling operations in the Rocky Mountain area where formations quite often drill very hard. The practice of spot coring in hard oil-bearing formations with conventional coring equipment is giving way diaimond coring of the entire sections, thus givng an operator the complete picture.

Jan 1, 1948

By R. E. Heithecker

Almost every oil well drilled into limestone formations in Kansas is treated with hydrochloric (muriatic) acid upon completion: to increase potential capacity of well and thereby increase its "daily allowable" production; to shorten time required to produce recoverable oil; and to increase quantity of oil recovered ultimately from reservoir. Acid treating marked a forward step in the producing fields of Kansas; in fact, many old limestone fields that almost had reached their economic producing limit were "rejuvenated" with acid and their capacities to produce increased several times. It also caused a marked increase in the ultimate oil recovery of some old and nearly depleted fields of Kansas. The effect of the acid was due to the cleaning-out action by the acid at the face of the limestone, the enlargement of the small drainage channels, and the apparent penetration of the acid to previously undrained porous and saturated strata. Studies of the effects of acid were made in the Fairport field, three groups of wells in the El Dorado field and the Shutts field. Estimation of increased recoveries resulting from acid in these fields and groups of wells ranged from 1000 to 2400 bbI. per acre. Limestone structures that had been tested by drilling and found noncommercial were later completed as commerical oil-producing formations through the use of acid. The Kansas City formation, Valley Center field of Kansas, is an example. Increased oil production and revenue from the old fields justified the reconditioning of equipment, which in most cases had become in poor mechanical condition. The first treatment with hydrochloric acid of an oil well in Kansas was in October 1932, and by the end of 1937 almost 6000 wells had been treated. Many wells were treated more than once and the total number of treatments exceeded 8000 by the end of 1937. Approximately 12 3/4 million gallons of acid was required for these treatments. The report includes 15 illustrations and 16 tables.

Jan 1, 1939

By R. E. Heithecker

Almost every oil well drilled into limestone formations in Kansas is treated with hydrochloric (muriatic) acid upon completion: to increase potential capacity of well and thereby increase its "daily allowable" production; to shorten time required to produce recoverable oil; and to increase quantity of oil recovered ultimately from reservoir. Acid treating marked a forward step in the producing fields of Kansas; in fact, many old limestone fields that almost had reached their economic producing limit were "rejuvenated" with acid and their capacities to produce increased several times. It also caused a marked increase in the ultimate oil recovery of some old and nearly depleted fields of Kansas. The effect of the acid was due to the cleaning-out action by the acid at the face of the limestone, the enlargement of the small drainage channels, and the apparent penetration of the acid to previously undrained porous and saturated strata. Studies of the effects of acid were made in the Fairport field, three groups of wells in the El Dorado field and the Shutts field. Estimation of increased recoveries resulting from acid in these fields and groups of wells ranged from 1000 to 2400 bbI. per acre. Limestone structures that had been tested by drilling and found noncommercial were later completed as commerical oil-producing formations through the use of acid. The Kansas City formation, Valley Center field of Kansas, is an example. Increased oil production and revenue from the old fields justified the reconditioning of equipment, which in most cases had become in poor mechanical condition. The first treatment with hydrochloric acid of an oil well in Kansas was in October 1932, and by the end of 1937 almost 6000 wells had been treated. Many wells were treated more than once and the total number of treatments exceeded 8000 by the end of 1937. Approximately 12 3/4 million gallons of acid was required for these treatments. The report includes 15 illustrations and 16 tables.

Jan 1, 1939

By H. H. Wright

In many fields edge water is one of the most important factors governing the production of oil. Possibly this fact is not appreciated by many producers except in so far as it may bring about a loss in production from wells drilled on the flanks of structures. In the light of artificial flooding as practiced in New York and Pennsylvania, and of the beneficial effect of natural water-flooding on many wells and leases in the Mid-Continent and elsewhere, it seems reasonable to suppose that very few phases of the petroleum industry hold greater promise for future benefit than the study and control of the natural water drive. Rate of Water Encroachment The rate of movement of water in artificially flooded areas has been referred to as so many feet per unit of time, usually from an injection well toward surrounding producing wells. This definition is vague when used in reference to the movement of natural edge water, inasmuch as such factors as sand thickness, steepness of dip and horizontal extent arc not considered. In the ultimate analysis, only the vertical component of movement affects the production of oil in the natural drive, and in order to define the rate of water encroachment more exactly, such a term as acre-fect per unit time might be used. Thus, where one well is located to each 10 acres a vertical movement of 5 ft. in the water level in a year would be defined as an encroachment of 50 acre-feet per year, and where one well is located to each 20 acres, as 100 acre-feet per year. Such a definition as this is entirely arbitrary, but it takes into consideration to a certain extent the influence of well spacing, and consequent sand drainage, on the rate of water movement. The rate of movement is considered to be an important function of water encroachment, for it is believed that the efficiency of recovery by natural water flood depends a good deal upon the rate of movement. In general, rapid encroachment is thought to effect a poor recovery because of the differential in favor of the movement of water through a sand body and the consequent tendency to trap oil in the sand. Slow movement, on the contrary, is thought to bring about a partial displace-

Jan 1, 1931

By C. M. Nickerson

In times of overproduction such as the operators have been struggling against for the past several years it is the practice of the oil industry to shut in certain wells in order to reduce the flood of oil. The purpose of this paper is to present certain variations in production of oil wells when the offset wells are shut in. The scope of the study has been confined to California fields, and more especially to those of the San Joaquin Valley. The accepted definition of a shut-in well is a well where production has been suspended by closing in the casinghead arid tubing or by cessation of pumping. The immediate effect of such a procedure, of course, is to reduce the oil production from the lease, which is the result desired. However, it appears that certain types of wells vary widely in production of oil, gas and gasoline after adjacent wells have been shut in, which variation has a very material effect on the ultimate recovery of oil from the property. The increase or decrease in the oil production itself may not be of sufficient volume to occasion comment, but wide fluctuations in the gas and gasoline recovery under the changed conditions arc of the utmost importance in the future recovery of oil. The scope of this paper includes: (I) the effect on producing oil wells of shutting in offset wells, the wells being studied in three groups arranged according to their relative stages of depletion; (2) probable source of excess gas and the effect on the ultimate recovery of oil; (3) suggested procedure when wells are shut in; (4) methods that could be employed to prevent undue migration of gas from the shut-in area; and (5) the need for future studies of the situation. Three Classes of Producing Oil Wells For the purposes of this paper producing wells in California have been arranged in three groups according to the age of the well, or to the relative stage of depletion of the producing zones. The first group consists of those wells with a high fluid level, or in other words those wells whose fluid levels are a considerable distance above the top of the perforations. This type of well is in the flush period of its life and ordinarily produces

Jan 1, 1929

By J. T. Hayward

Studies of the forces and conditions governing the recovery of petroleum from natural reservoirs indicate that a low gas-oil ratio increases ultimate recovery, retards the encroachment of water and tends to reduce lifting costs. Methods for controlling and reducing gas-oil ratios in producing wells consequently have been given considerable attention during the past few years. However, during this same period, the production from wells in nearly all fields has been fixed by proration agreements and it is the opinion of the writer that where a well is required to produce steadily at a predetermined rate, less than its "potential" or maximum capacity, the gas-oil ratio will depend only upon the rate of production, and will be independent of the method of production and of the design of equipment in the well. If no change in the rate of production is contemplated, efforts directed to improving the gas-oil ratio by altering the diameter of the flow string, changing the position of the choke, assisting the flow with gas-lift or pump, etc., will be unsuccessful. This viewpoint is not new. It was presented by H. N. Marsh and B. H. Robinson in 1929,' but it has not been generally accepted. Although engineers believe that the rate of withdrawal and not the equip ment used governs the water-oil ratio, a similar opinion regarding the gas-oil ratio is not so commonly admitted. The rates of flow of oil and gas into the base of an oil well depend upon the following conditions: 1. The characterist-ics of the oil and gas. 2. The characteristics of the underground reservoir. 3. Temperature and pressure conditions in the reservoir. 4. The back-pressure held against the face of the sand. In operating a well, the only one of these conditions over which control may be exercised through operating procedure and the use of equipment above the sand is the back-pressure at the face of the sand. Strictly speaking, the back-pressure varies over the face of the sand, owing

Jan 1, 1932

By G. E. Archie

The usefulness of the electrical resistivity log in determining reservoir characteristics is governed largely by: (I) the accuracy with which the true resistivity of the formation can be determined; (2) the scope of detailed data concerning the relation of resistivity measurements to formation characteristics; (3) the available information concerning the conductivity of connate or formation waters; (4) the extent of geologic knowledge regarding probable changes in facies within given horizons, both vertically and laterally, particularly in relation to the resultant effect on the electrical properties of the reservoir. Simple examples are given in the following pages to illustrate the use of resistivity logs in the solution of some problems dealing with oil and gas reservoirs. From the available information, it is apparent that much care must be exercised in applying to more complicated cases the methods suggested. It should be remembered that the equations given are not precise and represent only approximate relationships. It is believed, however, that under favorable conditions their application falls within useful limits of accuracy. Introduction The electrical log has been used extensively in a qualitative way to correlate formations penetrated by the drill in the exploitation of oil and gas reservoirs and to provide some indication of reservoir content. However, its use in a quantitative way has been limited because of various factors that tend to obscure the significance of the electrical readings obtained. Some of these factors are the borehole size, . the resistivity of the mud in the borehole, the effect of invasion of the mud filtrate into the formation, the relation of the recorded thickness of beds to electrode spacing, the heterogeneity of geologic formations, the salinity or conductivity of connate water, and, perhaps of greatest importance, the lack of data indicating the relationship of the resistivity of a formation in situ to its character and fluid content. On the Gulf Coast it is found that the effects of the size of the borehole and the mud resistivity are generally of little importance, except when dealing with high formational resistivities or extremely low mud resistivities. Fortunately, little practical significance need be attached to the exact values of the higher resistivities recorded. Low mud resistivities are not common, but when this condition is encountered it may be corrected by replacing the mud column. With the present advanced knowledge of mud control, invasion of mud filtrate into sands can be minimized, thereby increasing the dependability of the electrical log. The effect of electrode spacing on the recorded thickness of a bed is often subject to compensation or can be sufficiently accounted for to provide an acceptable approximation of the true resistivity of the formation. As development of a field or area progressively enhances the knowledge of the lithologic section, the resistivity values of the electrical log take on greater significance, ultimately affording acceptable interpretations. The salinity, and

Jan 1, 1942

By G. E. Archie

The usefulness of the electrical resistivity log in determining reservoir characteristics is governed largely by: (I) the accuracy with which the true resistivity of the formation can be determined; (2) the scope of detailed data concerning the relation of resistivity measurements to formation characteristics; (3) the available information concerning the conductivity of connate or formation waters; (4) the extent of geologic knowledge regarding probable changes in facies within given horizons, both vertically and laterally, particularly in relation to the resultant effect on the electrical properties of the reservoir. Simple examples are given in the following pages to illustrate the use of resistivity logs in the solution of some problems dealing with oil and gas reservoirs. From the available information, it is apparent that much care must be exercised in applying to more complicated cases the methods suggested. It should be remembered that the equations given are not precise and represent only approximate relationships. It is believed, however, that under favorable conditions their application falls within useful limits of accuracy. Introduction The electrical log has been used extensively in a qualitative way to correlate formations penetrated by the drill in the exploitation of oil and gas reservoirs and to provide some indication of reservoir content. However, its use in a quantitative way has been limited because of various factors that tend to obscure the significance of the electrical readings obtained. Some of these factors are the borehole size, . the resistivity of the mud in the borehole, the effect of invasion of the mud filtrate into the formation, the relation of the recorded thickness of beds to electrode spacing, the heterogeneity of geologic formations, the salinity or conductivity of connate water, and, perhaps of greatest importance, the lack of data indicating the relationship of the resistivity of a formation in situ to its character and fluid content. On the Gulf Coast it is found that the effects of the size of the borehole and the mud resistivity are generally of little importance, except when dealing with high formational resistivities or extremely low mud resistivities. Fortunately, little practical significance need be attached to the exact values of the higher resistivities recorded. Low mud resistivities are not common, but when this condition is encountered it may be corrected by replacing the mud column. With the present advanced knowledge of mud control, invasion of mud filtrate into sands can be minimized, thereby increasing the dependability of the electrical log. The effect of electrode spacing on the recorded thickness of a bed is often subject to compensation or can be sufficiently accounted for to provide an acceptable approximation of the true resistivity of the formation. As development of a field or area progressively enhances the knowledge of the lithologic section, the resistivity values of the electrical log take on greater significance, ultimately affording acceptable interpretations. The salinity, and

Jan 1, 1942