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By J. O. Lewis

The operation of gas-condensate fields is comparatively new and involves physical principles with which the industry was not prcviously familiar. It has been necessary to devise methods for testing gas-condensate wells and to correlate laboratory and field data. In this paper new methods are advanced for interpreting well G.P.M.† tests whereby dilution by dry gas can be estimated and information supplied on revaporization of condensates by dry gas. Inaccuracies in well test data are discussed. Changes in flow rates can cause changes in the G.P.M. of the effluent and it may take some time for a well to become stabilized after an important change in flow rate. Retrograde tests as usually conducted cannot be directly compared with field G.P.M. data, because the retrograde tests usually include solution gas in the condensates, which are reported On the cumulative basis whereas field data (G.P.M.) usually report pentaneS PlUS on a rate or instantaneous basis. Introduction Though long known to physicists, the phenomena Of retrograde condensation became known to the oil and gas industry Only in recent years, when deeper drilling disclosed that the behavior of vapors under changing pressures was different in high-pressure reservoirs than under the low-pressure operations with which the industry was familiar. These deep, high-pressure reservoirs in which condensation and vaporization behaved inversely to the accustomed manner became known as "gas-distillate," or preferably "gas-condensate" fields. Partly to prevent precipitation and retention of liquids in the reservoir, but still more to prevent the waste of residue gas, the operation known as "recycling," or preferably "cycling," was instituted, in which the residue gas is reinjected into the reservoir, thus maintaining pressure and driving the wet gas to the producing wells. For lack of field experience to serve as a guide, the industry had to assume that theory and laboratory experiments could accurately forecast retrograde behaviors in operating these gas-condensate fields, but it is obvious that these assumptions should be checked at the first opportunities against actual field experience. To make such checks, it is necessary to accumulate a large quantity of reliable field data, but experience has shown that it is difficult to obtain reliable field data and that the laboratory data as usually presented are not in directly comparable form. The problems of correlation involve the complex phase behavior on the one hand, and a knowledge of field data and a visualization of underground conditions on the other hand. This paper is an approach from field experience, The purposes of this article are to discuss the sources of uncertainty in the data and to present methods of analyzing, interpreting and correlating laboratory and field data. Data mostly from lower Gulf Coast fields are presented, from which some conclusions can be derived, but better data from more sources than those available to the writer will be required before satisfactory answers to many questions can be obtained. This paper is presented to stimulate the analysis and publication of data from other fields, the reexamination of field and laboratory methods, and the taking of more complete and reliable field tests. For these purposes, the writer presents some speculations that otherwise would not be appropriate.

Jan 1, 1947

By J. O. Lewis

The operation of gas-condensate fields is comparatively new and involves physical principles with which the industry was not prcviously familiar. It has been necessary to devise methods for testing gas-condensate wells and to correlate laboratory and field data. In this paper new methods are advanced for interpreting well G.P.M.† tests whereby dilution by dry gas can be estimated and information supplied on revaporization of condensates by dry gas. Inaccuracies in well test data are discussed. Changes in flow rates can cause changes in the G.P.M. of the effluent and it may take some time for a well to become stabilized after an important change in flow rate. Retrograde tests as usually conducted cannot be directly compared with field G.P.M. data, because the retrograde tests usually include solution gas in the condensates, which are reported On the cumulative basis whereas field data (G.P.M.) usually report pentaneS PlUS on a rate or instantaneous basis. Introduction Though long known to physicists, the phenomena Of retrograde condensation became known to the oil and gas industry Only in recent years, when deeper drilling disclosed that the behavior of vapors under changing pressures was different in high-pressure reservoirs than under the low-pressure operations with which the industry was familiar. These deep, high-pressure reservoirs in which condensation and vaporization behaved inversely to the accustomed manner became known as "gas-distillate," or preferably "gas-condensate" fields. Partly to prevent precipitation and retention of liquids in the reservoir, but still more to prevent the waste of residue gas, the operation known as "recycling," or preferably "cycling," was instituted, in which the residue gas is reinjected into the reservoir, thus maintaining pressure and driving the wet gas to the producing wells. For lack of field experience to serve as a guide, the industry had to assume that theory and laboratory experiments could accurately forecast retrograde behaviors in operating these gas-condensate fields, but it is obvious that these assumptions should be checked at the first opportunities against actual field experience. To make such checks, it is necessary to accumulate a large quantity of reliable field data, but experience has shown that it is difficult to obtain reliable field data and that the laboratory data as usually presented are not in directly comparable form. The problems of correlation involve the complex phase behavior on the one hand, and a knowledge of field data and a visualization of underground conditions on the other hand. This paper is an approach from field experience, The purposes of this article are to discuss the sources of uncertainty in the data and to present methods of analyzing, interpreting and correlating laboratory and field data. Data mostly from lower Gulf Coast fields are presented, from which some conclusions can be derived, but better data from more sources than those available to the writer will be required before satisfactory answers to many questions can be obtained. This paper is presented to stimulate the analysis and publication of data from other fields, the reexamination of field and laboratory methods, and the taking of more complete and reliable field tests. For these purposes, the writer presents some speculations that otherwise would not be appropriate.

Jan 1, 1947

By Erwin H. Leeman, Raymond R. Rice, Gerald L. Hassler

In the past few years a great deal of preeise information has been obtained about the relation of natural gas to oil production1. The improvement of our understanding has been of great value, both in prolonging the life of wells and in providing a much needed technical background for the legal problem of proration. But there are two principal aspects of the problem of production. It is necessary to consider not only the energy available, in the form of compressed and dissolved gas and in the pressure of driving water, but also the tenacity with which the sandstone holds the oil. The amount of oil that each sand condition will produce under given conditions of gas content should be determined. Hitherto the effect of the sand has been judged by a study of the flow of each well coupled with a procedure for extrapolating the production curve; hut, as is well known to evaluation engineers, such production curves are subject to changes that are not well understood, and often are affected by outside disturbances. On the whole, the concept of "potential production" is vague principally because the influence of the sand in production is not known beyond the simple ideas of porosity and permeability. The permeability is a quantity that has only inference value where mixtures of gas and oil or of gas, oil and water are present. Excellent studies of the production of oil from reservoirs packed with unconsolidatcd sand are available2, but these studies treat largely of small-scale analogzes to a producing field, and the conclusions to be derived from them arc necessarily of a qualitative character because it is not known in what way these miniature oil fields resemble large ones.

Jan 1, 1936

By Erwin H. Leeman, Raymond R. Rice, Gerald L. Hassler

In the past few years a great deal of preeise information has been obtained about the relation of natural gas to oil production1. The improvement of our understanding has been of great value, both in prolonging the life of wells and in providing a much needed technical background for the legal problem of proration. But there are two principal aspects of the problem of production. It is necessary to consider not only the energy available, in the form of compressed and dissolved gas and in the pressure of driving water, but also the tenacity with which the sandstone holds the oil. The amount of oil that each sand condition will produce under given conditions of gas content should be determined. Hitherto the effect of the sand has been judged by a study of the flow of each well coupled with a procedure for extrapolating the production curve; hut, as is well known to evaluation engineers, such production curves are subject to changes that are not well understood, and often are affected by outside disturbances. On the whole, the concept of "potential production" is vague principally because the influence of the sand in production is not known beyond the simple ideas of porosity and permeability. The permeability is a quantity that has only inference value where mixtures of gas and oil or of gas, oil and water are present. Excellent studies of the production of oil from reservoirs packed with unconsolidatcd sand are available2, but these studies treat largely of small-scale analogzes to a producing field, and the conclusions to be derived from them arc necessarily of a qualitative character because it is not known in what way these miniature oil fields resemble large ones.

Jan 1, 1936

By F. B. Plummer, R. B. Newcome

The practice of introducing acid into oil wells to increase production of oil and gas has been in use since 1894, when it was first used in the Pennsylvania oil fields30.‡ It is only since 1928 that it has been used to any extent in the Mid-Continent18. The process has proved successful in increasing production, at least temporarily, in depleted oil fields where the producing formation is highly calcareous and where water drive is not too pronounced. In the Zwolle field in Louisiana, where the producing horizon is a chalk, increases of 100 per cent have been recorded25. In north-central Texas, where the oil is produced from the Marble Falls limestone, equally pronounced increases have resulted3. The production also in some fields yielding oil from quartz sand cemented with calcitc has been benefited. The evidence of actual increase in total recovery of oil, however, has been questioned by some engineers18. It has been pointed out that the results of the treatment of a well in a now district, where the process has never been tried out, can never be predicted with certainty, since other factors besides percentage of calcareous content of the oil sand play a large part in determining the success of the method. Numerous articles have been published on acid treatment and on the effects of acid on limestone1-35, yet very little has been written concerning experimental work on the actual effect of acid on capillary pores and larger oil-coated voids of oil sands. This is due partly to difficulties in duplicating field conditions in a laboratory and partly to the fact that the process has been carried out largely by contracting companies that have been unwilling to publish details of their results for fear of loss of business to competitors. The authors, using equipment developed to measure the radial permeability of oil-sand cores2', have developed a method of investigating the results of acid treatment which has enabled them to test numerous cores and to study in some detail the action of acid on the different types of rocks, particularly fine-grained rocks.

Jan 1, 1936

By F. B. Plummer, R. B. Newcome

The practice of introducing acid into oil wells to increase production of oil and gas has been in use since 1894, when it was first used in the Pennsylvania oil fields30.‡ It is only since 1928 that it has been used to any extent in the Mid-Continent18. The process has proved successful in increasing production, at least temporarily, in depleted oil fields where the producing formation is highly calcareous and where water drive is not too pronounced. In the Zwolle field in Louisiana, where the producing horizon is a chalk, increases of 100 per cent have been recorded25. In north-central Texas, where the oil is produced from the Marble Falls limestone, equally pronounced increases have resulted3. The production also in some fields yielding oil from quartz sand cemented with calcitc has been benefited. The evidence of actual increase in total recovery of oil, however, has been questioned by some engineers18. It has been pointed out that the results of the treatment of a well in a now district, where the process has never been tried out, can never be predicted with certainty, since other factors besides percentage of calcareous content of the oil sand play a large part in determining the success of the method. Numerous articles have been published on acid treatment and on the effects of acid on limestone1-35, yet very little has been written concerning experimental work on the actual effect of acid on capillary pores and larger oil-coated voids of oil sands. This is due partly to difficulties in duplicating field conditions in a laboratory and partly to the fact that the process has been carried out largely by contracting companies that have been unwilling to publish details of their results for fear of loss of business to competitors. The authors, using equipment developed to measure the radial permeability of oil-sand cores2', have developed a method of investigating the results of acid treatment which has enabled them to test numerous cores and to study in some detail the action of acid on the different types of rocks, particularly fine-grained rocks.

Jan 1, 1936

By Sherman L. Pease

An inexpensive and relatively rapid method that can be used by field crews is described. Fluid movement is determined by releasing a tracer (dye) in the well at a predetermined level and, after an interval of time, sampling the well fluid at another level. The testing equipment consists of a combined crusher and sampler unit that is run into the well on a wire line. The rate of movement can be calculated from time-volume relationships. Description of Method It is often desirable to determine whether there is occurring any transfer of fluid from point to point in a shut-in well, and, if so, to measure the rate of movement. When it is desired to examine a large number of wells for possible "thief" sands, the time and expense will be considerable unless the method used is inexpensive and rapid. After experimentation with several possible solutions to the problem, the Production Department of the Shell Oil Co., Inc., developed the apparatus described herein, which has proved satisfactory. Routine operations with it can be carried out by field production crews with a minimum of technical supervision and with negligible investment in equipment. The method is based upon releasing a suitable tracer in the well fluid at a known level, and recovering a sample of well fluid at another level after a measured interval of time. Repetition of this process with different time intervals between release and sampling gives the necessary data. For purposes of illustration, the setup for measuring migration of fluid in an upward direction is described in the following paragraphs. The arrangement of equipment is shown diagrammatically on Fig. I. The elements of the combination unit are the tailpiece, the crushing device, the spacer and the sampling device. The lengths of the tailpiece and spacer are varied to place the crushing and sampling devices in the desired positions in relation to the sands being tested. The crushing device breaks the glass bottle containing the tracer when the tailpiece strikes the bottom of the well and the tension on the sand line is slackened. Because of the open construction of the crushing device, the tracer is quickly and completely disseminated in the well fluid. The sampling device is a suction bailer, which obtains a sample of the fluid surrounding the perforated nipple just before the unit is picked up off bottom. The sample is retained in the barrel by the ball valve for examination at the surface. Normally, on the first run into a well, the sample is obtained near the releasing point of the tracer, and thereafter samples are taken near the base of the upper sand if migration is indicated by the dilution or absence of the tracer in the initial sample. The length of the time interval between the releasing of the tracer and the sampling of the well fluid is varied for successive runs, attempting first to establish the rate within limits and then to define it more accurately by additional runs if necessary.

Jan 1, 1946

By Sherman L. Pease

An inexpensive and relatively rapid method that can be used by field crews is described. Fluid movement is determined by releasing a tracer (dye) in the well at a predetermined level and, after an interval of time, sampling the well fluid at another level. The testing equipment consists of a combined crusher and sampler unit that is run into the well on a wire line. The rate of movement can be calculated from time-volume relationships. Description of Method It is often desirable to determine whether there is occurring any transfer of fluid from point to point in a shut-in well, and, if so, to measure the rate of movement. When it is desired to examine a large number of wells for possible "thief" sands, the time and expense will be considerable unless the method used is inexpensive and rapid. After experimentation with several possible solutions to the problem, the Production Department of the Shell Oil Co., Inc., developed the apparatus described herein, which has proved satisfactory. Routine operations with it can be carried out by field production crews with a minimum of technical supervision and with negligible investment in equipment. The method is based upon releasing a suitable tracer in the well fluid at a known level, and recovering a sample of well fluid at another level after a measured interval of time. Repetition of this process with different time intervals between release and sampling gives the necessary data. For purposes of illustration, the setup for measuring migration of fluid in an upward direction is described in the following paragraphs. The arrangement of equipment is shown diagrammatically on Fig. I. The elements of the combination unit are the tailpiece, the crushing device, the spacer and the sampling device. The lengths of the tailpiece and spacer are varied to place the crushing and sampling devices in the desired positions in relation to the sands being tested. The crushing device breaks the glass bottle containing the tracer when the tailpiece strikes the bottom of the well and the tension on the sand line is slackened. Because of the open construction of the crushing device, the tracer is quickly and completely disseminated in the well fluid. The sampling device is a suction bailer, which obtains a sample of the fluid surrounding the perforated nipple just before the unit is picked up off bottom. The sample is retained in the barrel by the ball valve for examination at the surface. Normally, on the first run into a well, the sample is obtained near the releasing point of the tracer, and thereafter samples are taken near the base of the upper sand if migration is indicated by the dilution or absence of the tracer in the initial sample. The length of the time interval between the releasing of the tracer and the sampling of the well fluid is varied for successive runs, attempting first to establish the rate within limits and then to define it more accurately by additional runs if necessary.

Jan 1, 1946

By R. Floyd Farris

A method is presented for determining minimum waiting-on-cement time, which takes into account the differences that exist between types and brands of cements and such individual well conditions as depth, temperature, and pressure. The basis for the method was determined by laboratory tests. Being a laboratory development, several steps were required to prove its merit. The first step consisted of laboratory tests designed to determine the minimum cement strength required in wells. Basis was found for setting a minimum value of 8 Ib. per sq. in. tensile strength. Next, it was shown by laboratory tests that the time to 8 Ib. per sq. in. tensile strength may be expressed as a function of consistometer stirring time to loo "poises," the approximate relation being "the time to 8 Ib. per sq. in. tensile strength equals the time to I00 'poises' times three." Next, it was shown that the time of maximum temperature development in cement slurries, due to heat of hydration, is also related to consistometer stirring time to loo poises, but only by a factor of approximately two. It was shown also that the shut-in casing pressure will build up after cement is placed and register a maximum pressure at approximately the same time the slurry down the hole attains maximum temperature. From this and the relationships listed above, the general rule was established that minimum waiting-on-cement time (time to 8 Ib. per sq. in.) after casing cement jobs in any well is equal to the time when the shut-in casing pressure reaches a maximum, as measured from the initial mixing of cement, times a factor of 1.5. Cement plugs drilled in the field at the time prescribed by this formula were found to drill "firm to hard," thus confirming the laboratory tests. These tests prove that many of the present regulations for waiting on cement require a longer time than is absolutely necessary. Use of the method herein proposed offers the possibility of a saving of $1200 per well. Introduction The length of time allowed for cement to set after casing is determined either by state-wide rules, field rules, or self-imposed rules written into drilling contracts. In general, the time is dictated by experience and common practice. However, owing to differences in opinion and in experience of the various groups involved, waiting-on-cement time often varies from one area to the next. For example, an operator in an area where no rules exist may drill out of surface pipe at 24 to 36 hr., while another operator in another area may wait 48 hr. or more to comply with state or field rules, although the depth of the well, hole size, type of cement, and other data are identical. An even greater difference in practices will be found by making similar comparisons with respect to oil-string cement jobs. Differences in waiting-on-cement times of 36 to 48 hr. are common. Further complicating the picture is the rather common practice of allowing more waiting time for cement to set at the greater depths than is allowed at the shallow depths. This practice has existed for years in spite of the common knowl-edge1,2,3 that the temperature of the earth at the usual setting depths of surface

Jan 1, 1946

By R. Floyd Farris

A method is presented for determining minimum waiting-on-cement time, which takes into account the differences that exist between types and brands of cements and such individual well conditions as depth, temperature, and pressure. The basis for the method was determined by laboratory tests. Being a laboratory development, several steps were required to prove its merit. The first step consisted of laboratory tests designed to determine the minimum cement strength required in wells. Basis was found for setting a minimum value of 8 Ib. per sq. in. tensile strength. Next, it was shown by laboratory tests that the time to 8 Ib. per sq. in. tensile strength may be expressed as a function of consistometer stirring time to loo "poises," the approximate relation being "the time to 8 Ib. per sq. in. tensile strength equals the time to I00 'poises' times three." Next, it was shown that the time of maximum temperature development in cement slurries, due to heat of hydration, is also related to consistometer stirring time to loo poises, but only by a factor of approximately two. It was shown also that the shut-in casing pressure will build up after cement is placed and register a maximum pressure at approximately the same time the slurry down the hole attains maximum temperature. From this and the relationships listed above, the general rule was established that minimum waiting-on-cement time (time to 8 Ib. per sq. in.) after casing cement jobs in any well is equal to the time when the shut-in casing pressure reaches a maximum, as measured from the initial mixing of cement, times a factor of 1.5. Cement plugs drilled in the field at the time prescribed by this formula were found to drill "firm to hard," thus confirming the laboratory tests. These tests prove that many of the present regulations for waiting on cement require a longer time than is absolutely necessary. Use of the method herein proposed offers the possibility of a saving of $1200 per well. Introduction The length of time allowed for cement to set after casing is determined either by state-wide rules, field rules, or self-imposed rules written into drilling contracts. In general, the time is dictated by experience and common practice. However, owing to differences in opinion and in experience of the various groups involved, waiting-on-cement time often varies from one area to the next. For example, an operator in an area where no rules exist may drill out of surface pipe at 24 to 36 hr., while another operator in another area may wait 48 hr. or more to comply with state or field rules, although the depth of the well, hole size, type of cement, and other data are identical. An even greater difference in practices will be found by making similar comparisons with respect to oil-string cement jobs. Differences in waiting-on-cement times of 36 to 48 hr. are common. Further complicating the picture is the rather common practice of allowing more waiting time for cement to set at the greater depths than is allowed at the shallow depths. This practice has existed for years in spite of the common knowl-edge1,2,3 that the temperature of the earth at the usual setting depths of surface

Jan 1, 1946

By P. H. Cardwell

The effect of various plastics upon the permeability of a sand and the mechanism of their ensuring permeability within the consolidated sand body is discussed. Data are presented on various properties of the plastic materials used in sand consolidation and the effect of temperature and usable temperature ranges are considered. The recovery of petroleum from uncon-solidated sands presents serious production problems, owing to sloughing of the formation. The solution of some of these problems usually has been by mechanical methods.' The ideal way of controlling the sloughing tendencies of these un consolidated formations, however, is to prevent the movement of the individual sand grains by the use of a bonding medium. A step in the desired direction was taken by Irons and Stcesser2 when they taught the use of liquid plastics to produce a consolidating deposit that prevents sloughing. More recently, Wrightsman and Buckley3 proposed a modification of this process. In this use of the liquid plastic, the sand grains become coated and the ensuing hardening of the plastic by polymerization or condensation cements together the sand Particles. Liquid plastics that have been suggested for this Purpose are of the following types: phenolformaldehyde, alkyd resins, vinyl type resins, polystyrene and the acrylic esters. When the flow of fluids through a sand must not be materially reduced, it is essential only to cement together the sand grains with liquid plastic and leave a portion of the interstitial space for fluid flow. TO be assured of obtaining fluid flow through the sand interstices after injection of plastic, it has been necessary in the past to remove the excess plastic from the interstices between the particles before it sets. Wrightsman and Buckley suggest two methods for the removal of the excess plastic from the interstices of the sand: (I) to flush the excess plastic back into the formation, away from the well bore, by use of oil or water; (2) to produce the well before the plastic has set, thereby moving the excess plastic into the well bore. Under certain well conditions it is very difficult to remove the excess plastic from all parts of the formation by either of these methods and leave the formation consolidated with no sections completely sealed. The method* described herein of retaining permeability within a sand body is to use a liquid plastic that upon setting ensures permeability within the consolidated sand body. This cements the sand grains but obviates the need for removing plastic from the interstices of the sand. One of the ways of accomplishing this is to use a liquid plastic that occupies a considerably greater volume than the solidified resin it yields on further polymerization or condensation in situ. In order to be satisfactory, the volume of the plastic while liquid should be at least one and one half times the volume of the solid formed. Preferably,

Jan 1, 1947

By P. H. Cardwell

The effect of various plastics upon the permeability of a sand and the mechanism of their ensuring permeability within the consolidated sand body is discussed. Data are presented on various properties of the plastic materials used in sand consolidation and the effect of temperature and usable temperature ranges are considered. The recovery of petroleum from uncon-solidated sands presents serious production problems, owing to sloughing of the formation. The solution of some of these problems usually has been by mechanical methods.' The ideal way of controlling the sloughing tendencies of these un consolidated formations, however, is to prevent the movement of the individual sand grains by the use of a bonding medium. A step in the desired direction was taken by Irons and Stcesser2 when they taught the use of liquid plastics to produce a consolidating deposit that prevents sloughing. More recently, Wrightsman and Buckley3 proposed a modification of this process. In this use of the liquid plastic, the sand grains become coated and the ensuing hardening of the plastic by polymerization or condensation cements together the sand Particles. Liquid plastics that have been suggested for this Purpose are of the following types: phenolformaldehyde, alkyd resins, vinyl type resins, polystyrene and the acrylic esters. When the flow of fluids through a sand must not be materially reduced, it is essential only to cement together the sand grains with liquid plastic and leave a portion of the interstitial space for fluid flow. TO be assured of obtaining fluid flow through the sand interstices after injection of plastic, it has been necessary in the past to remove the excess plastic from the interstices between the particles before it sets. Wrightsman and Buckley suggest two methods for the removal of the excess plastic from the interstices of the sand: (I) to flush the excess plastic back into the formation, away from the well bore, by use of oil or water; (2) to produce the well before the plastic has set, thereby moving the excess plastic into the well bore. Under certain well conditions it is very difficult to remove the excess plastic from all parts of the formation by either of these methods and leave the formation consolidated with no sections completely sealed. The method* described herein of retaining permeability within a sand body is to use a liquid plastic that upon setting ensures permeability within the consolidated sand body. This cements the sand grains but obviates the need for removing plastic from the interstices of the sand. One of the ways of accomplishing this is to use a liquid plastic that occupies a considerably greater volume than the solidified resin it yields on further polymerization or condensation in situ. In order to be satisfactory, the volume of the plastic while liquid should be at least one and one half times the volume of the solid formed. Preferably,

Jan 1, 1947

By C. P. Parsons

During the past year considerable interest has been shown in cementing operations for shutting off bottom water, whipstocking, etc. A number of plug-back methods have been used, with various adaptations for special conditions, but those described in this paper are representative of the methods now in use. Conditioning the Well Various preliminary operations for improving the results from plug-back operations have been evolved. In one method, a nitroglycerin shot is discharged at the upper portion of the formation to be plugged off, the purpose being to make a wide place in the hole in order to give the cement a more secure anchor against thrust pressure of the water against the bottom of the cement plug after the well is again put on production. Another is intended to attain a similar result by under-reaming a wide place in the hole by means of a rotary wall scraper. In one well in which this device was used there was a water sand at the bottom of the well immediately below the cap rock above which the oil sand occurred. Before the plugging back operation, the water sand was underreamed in an attempt to get a square shoulder on the underside of the cap rock, in order to prevent the water from breaking in over the top of the cement plug after the well should be put on production, and also to get a more secure anchor for the cement plug against the thrust pressure of the water against it. As an aid in calculating the amount of cement required to fill a given amount of hole to be plugged back, a device has been developed for measuring and recording the irregularities and cavities in open holes, called an "open-hole recording caliper." If consists of a steel shell, 5 in. in diameter, which encloses a recording mechanism that receives impressions from four movable arms that make sliding contact with the wall of the hole. The arms operate a ratchet, which raises and lowers a recording stylus against a chart. Each arm registers its own radius. The device is run into a well on a steel measuring line. While the device is being lowered, the arms are folded inside the shell; they are

Jan 1, 1936

By C. P. Parsons

During the past year considerable interest has been shown in cementing operations for shutting off bottom water, whipstocking, etc. A number of plug-back methods have been used, with various adaptations for special conditions, but those described in this paper are representative of the methods now in use. Conditioning the Well Various preliminary operations for improving the results from plug-back operations have been evolved. In one method, a nitroglycerin shot is discharged at the upper portion of the formation to be plugged off, the purpose being to make a wide place in the hole in order to give the cement a more secure anchor against thrust pressure of the water against the bottom of the cement plug after the well is again put on production. Another is intended to attain a similar result by under-reaming a wide place in the hole by means of a rotary wall scraper. In one well in which this device was used there was a water sand at the bottom of the well immediately below the cap rock above which the oil sand occurred. Before the plugging back operation, the water sand was underreamed in an attempt to get a square shoulder on the underside of the cap rock, in order to prevent the water from breaking in over the top of the cement plug after the well should be put on production, and also to get a more secure anchor for the cement plug against the thrust pressure of the water against it. As an aid in calculating the amount of cement required to fill a given amount of hole to be plugged back, a device has been developed for measuring and recording the irregularities and cavities in open holes, called an "open-hole recording caliper." If consists of a steel shell, 5 in. in diameter, which encloses a recording mechanism that receives impressions from four movable arms that make sliding contact with the wall of the hole. The arms operate a ratchet, which raises and lowers a recording stylus against a chart. Each arm registers its own radius. The device is run into a well on a steel measuring line. While the device is being lowered, the arms are folded inside the shell; they are

Jan 1, 1936

By H. E. Gross

A plausrsle method of drilling beyond the continental shelves is set forth with limitations of the method. The continental shelves comprise the water-covered portions of land masses out to 600 ft. of water, or roo fathoms. The problems and possibilities of drilling beyond this depth are discussed in this paper. Introduction Much attention is being given the problem of developing petroleum beneath the open sea. Geophysical surveys have been made 26 miles offshore1 from the continental United States, and onco offshore ownership is established it is likely that there will be drilling for oil on the continental shelves. More than two years ago the author presented the means for drilling in deep water.2 at the fall meeting of the Petroleum Division of the AIME at Los Angeles. His concepts then were based on the use of rigid foundations suitable for drilling in water up to 600 ft. deep. The present paper suggests a method for drilling in deeper water. Possibilities and Problems of Drilling beyond the continental shelves It being conceded that because restricted deep-water portions of the hydrosphere might contain oil in commercial quantities, and that at any rate it is pertinent to know more of the nature of the lithosphere beneath the hydrosphere, the possibilities and problems of drilling beyond the continental shelves should be set forth. Drilling in open water would offer few if any advantages over drilling on land. These are: 1. The ocean transportation is available to deep-water drilling sites, and extensive pipe lines and roads are unnecessary. 2. Refinery facilities and markets perhaps are established on the near-by shore where adjacent fields on land are nearing depletion. 3. There is freedom from jungle pests and tropical diseases. 4. Competitive drilling is less likely. 5. Extensive areas attractive for development arc not yet under lease or concession. Disadvantages are great and numerous: 1. Storm hazards from wind and wave. 2. Expensive foundations, either rigid or floating. 3. Shutdown times because of weather. 4. Marine Regulations of Federal Bureaus in addition to customary regulations on land. 5. Frequent difficulty in moving men and materials to and from drilling platforms. 6. Extra precautions required in open sea. For drilling in water more than 500 or 600 ft. deep, rigid foundations2 become too costly, and floating foundations must be used, and they must meet the following requirements:

Jan 1, 1947

By H. E. Gross

A plausrsle method of drilling beyond the continental shelves is set forth with limitations of the method. The continental shelves comprise the water-covered portions of land masses out to 600 ft. of water, or roo fathoms. The problems and possibilities of drilling beyond this depth are discussed in this paper. Introduction Much attention is being given the problem of developing petroleum beneath the open sea. Geophysical surveys have been made 26 miles offshore1 from the continental United States, and onco offshore ownership is established it is likely that there will be drilling for oil on the continental shelves. More than two years ago the author presented the means for drilling in deep water.2 at the fall meeting of the Petroleum Division of the AIME at Los Angeles. His concepts then were based on the use of rigid foundations suitable for drilling in water up to 600 ft. deep. The present paper suggests a method for drilling in deeper water. Possibilities and Problems of Drilling beyond the continental shelves It being conceded that because restricted deep-water portions of the hydrosphere might contain oil in commercial quantities, and that at any rate it is pertinent to know more of the nature of the lithosphere beneath the hydrosphere, the possibilities and problems of drilling beyond the continental shelves should be set forth. Drilling in open water would offer few if any advantages over drilling on land. These are: 1. The ocean transportation is available to deep-water drilling sites, and extensive pipe lines and roads are unnecessary. 2. Refinery facilities and markets perhaps are established on the near-by shore where adjacent fields on land are nearing depletion. 3. There is freedom from jungle pests and tropical diseases. 4. Competitive drilling is less likely. 5. Extensive areas attractive for development arc not yet under lease or concession. Disadvantages are great and numerous: 1. Storm hazards from wind and wave. 2. Expensive foundations, either rigid or floating. 3. Shutdown times because of weather. 4. Marine Regulations of Federal Bureaus in addition to customary regulations on land. 5. Frequent difficulty in moving men and materials to and from drilling platforms. 6. Extra precautions required in open sea. For drilling in water more than 500 or 600 ft. deep, rigid foundations2 become too costly, and floating foundations must be used, and they must meet the following requirements:

Jan 1, 1947

By D. R. Conlon, E. R. Brownscombe

Errors in measurement of reservoir pressure include: (I) gauge errors, and (a) interpretation errors. Gauge errors may be reduced by: (a) reading charts with a comparator microscope, (b) use of hard metal stylus points to give clear lines, (6) insuring temperature equilibrium, and (d) making multiple tests. Check calibrations are equally as important as check well tests. A statistical analysis of such check runs shows quantitatively the advantages of a standardized "zero pressure line'' and of the use of field calibrations made at bottom-hole temperature on the same chart run in the well. Interpretation errors include: (a) fluid heads, which should be corrected to the top of the perforations on the basis of well-fluid gravity and from the top of the perforation to the datum level on the basis of reservoir-fluid gravity, and (b) gradients around the well. Conventional shut-in periods may be entirely inadequate to overcome these, necessitating a reservoir study based on build-up curve data, reservoir history, core analysis and any other available information. Interest in engineering studies of the pressure changes in oil and gas reservoirs is increasing. This type of work yields important information and doubtless will be greatly extended in the future. One of the factors limiting the work, however, is the accuracy with which the reservoir pressures can be determined; for if the inaccuracies in the pressure measurements represent an appreciable percentage of the pressure changes, the engineer is seriously handicapped, and must delay the reservoir study until the reservoir pressure has changed a relatively large amount. This delay can greatly reduce the benefits of such studies, at least from the point of view of aiding the leasing, drilling and completion programs. Thus, from the point of view of reservoir analysis, it is frequently important to obtain the most accurate pressure data possible early in the history of any field—particularly for the gas-distillate fields now being developed. This paper deals with improvements in the measurement of bottom-hole pressures that permit pressures even as high as 4000 or 5000 lb. per sq. in. to be determined with gauge errors of only+ ±I to 2 lb. per sq. in. Since pressures out in the reservoir rather than in the bottom of the hole concern the reservoir analyst, differences between bottom-hole pressures and actual reservoir pressures are also considered. In general, errors in pressure measurement may be divided into: 1. Gauge errors: a. Errors due to inaccuracies in reading the pressure charts. b. Errors due to irreproducibility of the pressure element and recording system. c. Errors caused by failure to allow the gauge to reach temperature equilibrium. 2. Internretation errors: a. Errors caused by a fluid head between the gauge position in tubing and the pressure at the datum level in the reservoir. b. Pressure gradients in the reservoir.

Jan 1, 1946

By D. R. Conlon, E. R. Brownscombe

Errors in measurement of reservoir pressure include: (I) gauge errors, and (a) interpretation errors. Gauge errors may be reduced by: (a) reading charts with a comparator microscope, (b) use of hard metal stylus points to give clear lines, (6) insuring temperature equilibrium, and (d) making multiple tests. Check calibrations are equally as important as check well tests. A statistical analysis of such check runs shows quantitatively the advantages of a standardized "zero pressure line'' and of the use of field calibrations made at bottom-hole temperature on the same chart run in the well. Interpretation errors include: (a) fluid heads, which should be corrected to the top of the perforations on the basis of well-fluid gravity and from the top of the perforation to the datum level on the basis of reservoir-fluid gravity, and (b) gradients around the well. Conventional shut-in periods may be entirely inadequate to overcome these, necessitating a reservoir study based on build-up curve data, reservoir history, core analysis and any other available information. Interest in engineering studies of the pressure changes in oil and gas reservoirs is increasing. This type of work yields important information and doubtless will be greatly extended in the future. One of the factors limiting the work, however, is the accuracy with which the reservoir pressures can be determined; for if the inaccuracies in the pressure measurements represent an appreciable percentage of the pressure changes, the engineer is seriously handicapped, and must delay the reservoir study until the reservoir pressure has changed a relatively large amount. This delay can greatly reduce the benefits of such studies, at least from the point of view of aiding the leasing, drilling and completion programs. Thus, from the point of view of reservoir analysis, it is frequently important to obtain the most accurate pressure data possible early in the history of any field—particularly for the gas-distillate fields now being developed. This paper deals with improvements in the measurement of bottom-hole pressures that permit pressures even as high as 4000 or 5000 lb. per sq. in. to be determined with gauge errors of only+ ±I to 2 lb. per sq. in. Since pressures out in the reservoir rather than in the bottom of the hole concern the reservoir analyst, differences between bottom-hole pressures and actual reservoir pressures are also considered. In general, errors in pressure measurement may be divided into: 1. Gauge errors: a. Errors due to inaccuracies in reading the pressure charts. b. Errors due to irreproducibility of the pressure element and recording system. c. Errors caused by failure to allow the gauge to reach temperature equilibrium. 2. Internretation errors: a. Errors caused by a fluid head between the gauge position in tubing and the pressure at the datum level in the reservoir. b. Pressure gradients in the reservoir.

Jan 1, 1946

By Warren J. Jackson, John L. P. Campbell

Automatic recording of the radioactivity of the earth's formations provides a log of relative intensities that, if properly interpreted, can be applied to oil-field engineering. Production, engineering, and geological departments regard the radioactivity log as a forward step in the securing of more conclusive information for successful well completions. Explanations of the technique, together with some of the problems to which radioactivity logging have been applied, are presented in this paper. Introduction Those responsible for the completion of new oil and gas wells, or with planning workover operations on old wells, have followed closely the development of radioactivity well logging because they are interested in reducing the number of unknowns that usually are present in such work. Many operators have made use of the log, or are acquainted with at least one of the applications, but it is unlikely that any one operator is familiar with all of the many applications that are possible. The purpose of this paper is to present a representative example of each of the many applications, wherever the information has been released by an operator, and to illustrate by hypothetical examples other applications, releases for which have not been given. In this way, it is hoped that a better understanding of the scope of this new engineering tool may be obtained. Although the literature contains many references that describe in detail the theory, development, and application of radioactivity well logging, a brief discussion of the technique may be helpful to those who are investigating the subject for the first time. All rocks contain radioactive material in varying concentrations. In general, shales contain relatively more radioactive material than sandstones or limestones. These radioactive materials disintegrate with time into other materials of lower atomic weight, and in that process of disintegration the rocks are emitting many rays, the most penetrating of which is the gamma ray. The intensity of emission of the gamma ray is proportional to the quantities of radioactive materials present. A higher rate of emission would be observed, therefore, opposite a shale than opposite a sandstone or limestone. Since measurable intensities of gamma rays are capable of penetrating as many as five concentric strings of casing, and as the gamma-ray intensity is relative to the formations, the measurements of variations in gamma-ray intensities offer a means of identifying cased-off formations in their proper stratigraphic sequence. The Gamma-ray Curve The measurement of gamma-ray intensities is accomplished by means of an ioniza-tion chamber that consists of a heavy cylinder, about 3 ft. long, that contains two insulated electrodes and is filled with an inert gas under high pressure. Under normal conditions no current will flow through the gas when an electrical potential is set up between the electrodes, but when

Jan 1, 1946

By John L. P. Campbell, Warren J. Jackson

Automatic recording of the radioactivity of the earth's formations provides a log of relative intensities that, if properly interpreted, can be applied to oil-field engineering. Production, engineering, and geological departments regard the radioactivity log as a forward step in the securing of more conclusive information for successful well completions. Explanations of the technique, together with some of the problems to which radioactivity logging have been applied, are presented in this paper. Introduction Those responsible for the completion of new oil and gas wells, or with planning workover operations on old wells, have followed closely the development of radioactivity well logging because they are interested in reducing the number of unknowns that usually are present in such work. Many operators have made use of the log, or are acquainted with at least one of the applications, but it is unlikely that any one operator is familiar with all of the many applications that are possible. The purpose of this paper is to present a representative example of each of the many applications, wherever the information has been released by an operator, and to illustrate by hypothetical examples other applications, releases for which have not been given. In this way, it is hoped that a better understanding of the scope of this new engineering tool may be obtained. Although the literature contains many references that describe in detail the theory, development, and application of radioactivity well logging, a brief discussion of the technique may be helpful to those who are investigating the subject for the first time. All rocks contain radioactive material in varying concentrations. In general, shales contain relatively more radioactive material than sandstones or limestones. These radioactive materials disintegrate with time into other materials of lower atomic weight, and in that process of disintegration the rocks are emitting many rays, the most penetrating of which is the gamma ray. The intensity of emission of the gamma ray is proportional to the quantities of radioactive materials present. A higher rate of emission would be observed, therefore, opposite a shale than opposite a sandstone or limestone. Since measurable intensities of gamma rays are capable of penetrating as many as five concentric strings of casing, and as the gamma-ray intensity is relative to the formations, the measurements of variations in gamma-ray intensities offer a means of identifying cased-off formations in their proper stratigraphic sequence. The Gamma-ray Curve The measurement of gamma-ray intensities is accomplished by means of an ioniza-tion chamber that consists of a heavy cylinder, about 3 ft. long, that contains two insulated electrodes and is filled with an inert gas under high pressure. Under normal conditions no current will flow through the gas when an electrical potential is set up between the electrodes, but when

Jan 1, 1946