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By P. R. PaeIay, A. Slibar

Using three-dimensional, stress-deformation rate equations for a Bingham plastic, an approximate solution for the laminar flow of drilling mud between the drill pipe and casing is given for the case when the velocity gradients due to axial flow are large compared to velocity gradients due to rotation. INTRODUCTION The fact that drilling mud can be treated, to a first approximation, as a Bingham plastic has been established by several investigators12,3,4,5. A Bingham plastic is a material that is rigid until a certain combination of stresses exceeds a critical value. When the stresses are sufficiently high to initiate flow, the reduced stresses have a constant ratio to the corresponding deformation rates at each point. Prediction of pressure and torque requirements to produce the desired flow of the material have been made by analytical solutions due to Bingham6, Reiner7, and Buckingham8. One part of the present means of calculation that requires clarification is the flow between the drill pipe and casing. Present methods treat the flow resulting from the rotation of the drill pipe separate from the flow produced by the axial pressure gradient. Since the non-linear behavior of a Bingham plastic implies that solutions cannot be superposed, the present analytical investigation was undertaken to obtain a solution to the problem of combined axial and tangential flow. Equations have been proposed for the three-dimensional flow of a Bingham plastic9,10,11 and it has been shown that the proposed equations lead to the usual solutions from the one-dimensional theory". Applying these equations to the flow between two concentric cylinders the problem of axial flow only13 and tangential flow only12 have been solved. In addition to the separate problems of axial and tangential flow between concentric cylinders, the authors have determined the relationship between external torque on the inside cylinder and axial pressure gradient necessary to initiate flow". The solution given in Ref. 14 points out the complexity of the present problem. The problem considered here is the case of simultaneous axial and tangential flow. The axial flow, necessary to keep the drill bit free of removed material, results from the axial pressure gradient. Tangential flow is present since the drill pipe rotates in the hole. The solution given here is valid when the shear stresses in the drilling mud due to rotation are small compared to the shear stresses resulting from the axial flow. This case for laminar flow can be encountered in oilfield drilling. STRESS-DEFORMATION RATE EQUATIONS A detailed derivation of the equations governing the behavior of a Bingham plastic is given in Ref. 10. This section briefly outlines the physical reasoning leading to this three-dimensional formulation of the stress-deforma-tion rate law. Experiments on a certain class of materials have demonstrated the following properties: (1) when a certain combination of the stresses is below a critical value no deformation of the material occurs, (2) to a first approximation this combination of stresses is independent of the hydrostatic pressure (negative average normal stress), (3) if flow occurs the ratio of the reduced stress to the corresponding deformation rate is constant at each point of the flowing material, and (4) incom-pressibility. For the one dimensional case of shear deformation, Bingham6 formulated the governing equation as dxx, = 0 for sxx < to and µdxx = s xx = to for sxx to , . where dxx is the shear deformation rate, sxx the shear stress, to the critical shear stress, and p the slope of the sxx vs dxx curve for dxx > 0. Fig. 1 shows the behavior for pure shear between two parallel plates. Taking into account the physical properties given above and assuming the critical combination of stresses to be measured by the octahedral shear stress, the fol-lowing three-dimensional equations have been proposed.

Jan 1, 1958

By J. E. Chappelear

We are concerned with the problem of calculating the forces produced by passing waves on a submerged object (in particular a drilling barge) located on the ocean floor. We employ the linearized theory of waves (the Airy1 theory), since solutions are generally more easily obtained in such a theory. It will be indicated how an approximate solution to the problem can be obtained for waves of finite height by use of a linear combination of Airy waves. We shall assume the submerged object has an infinite length, thus neglecting diffraction and making the problem two-dimensional. We find that there is not a considerable difference between our solution and the usual engineering solution. The force, as a function of time, is plotted in Figs. 4 and 5, together with the usual solution for easy comparison. So far, no experiments have been found to compare with the results. As will be shown, the calculations can be extended to waves of finite height (Stokes2-Struik3 waves) in an approximate fashion. This can be done by calculating the force produced by each Fourier component of the wave, separately, and omitting the coupling between the various harmonics produced by Bernoulli&apos;s theorem. The problem and its boundary conditions will be briefly stated. We seek a function, +, the velocity potential, which is harmonic, ?2?=0...........(1) and which satisfies the boundary conditions ??/?n =0 .......(2) (the normal derivative of + is zero) on the ocean floor and the sides of the barge, and s??/?y = ?..........(3) on the ocean surface, where s = g/w2........(4) The physical reasons for these choices and an interpretation of ? are given by Lamb.&apos; As previously stated, we assume also that the problem is two-dimensional. We set up our coordinates such that x = 0 is the center of the barge and y = 0 is the ocean floor. The coordinates are shown in Fig. 1, together with the location of the barge on the bottom. Our solution may be decomposed into a function which is symmetric about x = 0,?e, and one which is antisymmetric, +,, ? = ? + ?o...........(5) Thus directly above the barge we have as boundary conditions that for x = 0, ?o = 0, ...........(6) and ??e/?x = 0........(7) Now, far from the barge, we have that (for x positive and assuming the waves are incident from the left) ?e ? Ae cosh ky cos k (x + a) , . . . (8) and ?e ? Ao cosh ky cos k (x + ß) . . . . (9) where + means ". .. approaches ... for x large." Let us put Ae, Ao, and k equal to one, and remember that, in accordance with the derivation of Eq. 3, a sinusoidal time factor is to be supplied. Then we may rewrite Eq. 8 for ?e, and we find that

Jan 1, 1958

By Blake M. Caldwell, Thomas C. Poulter

A new approach to an old problem has made it possible to do in a a tively short period what has not been accomplished in the past three quarters of a century using strictly experimental methods. A theoretical study was made of the underlying principles whereby a jet is formed by a shaped charge and of the mechanism of the penetration of the target by that jet. It was found that there are more than 10, and perhaps as many as 15 variables affectin!? the performance of the shaped charge. Only a few calculations are necessary to show that it is physically impossible to investigate all of these variables experimentally. The shaped charge theory has been extended to include a previously little-understood mechanism in high explosive phenomena; namely, low order detonation. By superimposing a high order detonation on a zone already undergoing low order detonation, all appreciable improvement in performance is accomplished. The development of a design wherehy these phenomena are coordinated in such a way as to develop a jet which is tailored to meet the specific target requirement will be described in detail. The shortcomings or even impossibility of strictly experimental techniques will be illustrated by a discussion of the development of a special-purpose explosive charge. INTRODUCTION In an article appearing in the May, 1888 issue of Scribner&apos;s Magazine, Charles E. Monroe described his early experiments with gun cotton (Fig. 1) which led to his name being most fre-quently connected with our present-day shaped charge. Although the sunken letters or "cavities" in Mon- roe&apos;s gun cotton were not lined, they produced some penetration of an iron plate. The credit for the lined shaped charge, however, should rightfully go to Dr. R. W. Wood of the Physics Dept. of Johns Hopkins University, who was responsible for first discovering the fact that a metal liner in a cavity of explosive gave high velocity fragments and/or jets of metal. This discovery was made by Dr. Wood inadvertently while investigating an accidental death resulting from an electric blasting cap. He discovered that a jet of high velocity copper particles was ejected from the dimple

Jan 1, 1958

By Leendert de Witte, Fred J. Radd

In many areas caring failures can be directly related to electrical currents observed in the casings. It is the thesis of this paper that the observed casing currents are mainly due to electrochemical potentials of the type in evidence on spontaneous potential curves of electrical logs. The general nature of these potentials are discussed and an equivalent circuit is given for current and potential distributions around open holes. The casing forms a short circuit to these potentials and tends to average the effects of local cells. The case of casing corrosion opposite the Dakota water sands in the salt-mud area of Kansas is discussed anil used us a qualitative, illustration of the relation between SP&apos;s and casing currents. A method of quantitative derivation of casing current distribution frorn electric log SP curves, using linear transform theory, is described and results are compared with a measured current profile. The effects of hydrogen over-potentials at the cathodic portions of the pipe are considered and some laboratory data are given in support of conclusions regarding the over-1.01tuge.s. INTRODUCTION To date an appreciable amount of work has been done on the measurement of oil well casing currents and on the correlation of the anodic portions of the current profiles with corrosive casing failures. Speculations on the origin of the casing currents have, however, remained rather vague; and although almost every plausible cause has been mentioned, there is to the writers&apos; knowledge no clear-cut expose&apos; on the details of the causes of the corrosive currents in the literature. A study of current surveys and casing failures in the N.W. Burnett field, Ellis County. Kan.. indicated the probability that concentration cell emf&apos;s between the Wellington salt section and the relatively fresh waters in the Dakota sands were a major cause of the corrosion currents. A more general concept evolved upon analysis of the severe corrosive conditions in the Pleistocene sands in the Ventura Avenue and San Miguelito fields in California. In this area no major variations in the salt content of the formation waters occur and yet large casing currents are observed. An explanation is found in the fact that the local spontaneous potentials which are set up due to concentration contrast between the drilling fluid and the connate water are short circuited when casing is set. The very conductive path through the casing increases the magnitude of the currents and has the tendency to average local sources over fairly large intervals. Current will flow between the sections that are predominently shaly and the sections that are mostly sandy. At the places where the current leaves the pipe, corrosive attack will occur. This same phenomenon will be present wherever unprotected pipe is set through sections that show large SP kicks on the electric logs over reasonably thick interval~. GENERAL- NATURE OF THE SPONTANEOUS POTENTIALS When a sequence of sedimentary rocks is penetrated by a drill hole filled with a mud which has a different salt concentration from that in the formation waters, various types of electrochemical potentials are established between the formations and different parts of the mud column. Opposite clean sand sections. a simple liquid-liquid junction potential will be observed; while opposite argillaccous formations, a membrane potential, often referred to as shale potential, will be established. The first quantitative analysis of these emf&apos;s in terms of liquid junction and membrane potentials is due to Wyllie.1

Jan 1, 1956

By T. O. Allen, J. H. Atterbury

Laboratory and field tests during the past five years indicated considerable variation in the penetrating power of commercially available gun perforators. Many of the guns which achieved inadequate penetration in these tests have since been improved. However, recent productivity tests indicated the possibility of inadequate penetration or, at least, ineffective penetration in some wells. Laboratory experiments under simulated well conditions have demonstrated considerable plugging of the perforations, apparently as a result of factors associated with the shooting process and/or the drilling mud in the well at the time of perforating. The restrictions to flow per unit of hole depth caused by this plugging appears to be greater for jet perforators than for bullet guns of comparable diameter; however, because of the greater depth of penetration obtained with the jet guns, the total flow rates appear to he approximately equal. Limited testing with an experimental shaped charge suggests that less shot hole restriction and greater flow rates may result from larger-diameter perforations or other factors related to charge design. INTRODUCTION Gun perforating has been accepted for a number of years as a routine well completion method which is often preferred since it permits more selective operation of producing zones. Nevertheless, questions have continued to arise as to the effectiveness of the communication paths established between the productive formation and the interior of the casing. The basis for these questions has generally been failure to obtain anticipated fluid production rates through gun perforated completions in specific wells. These low productivities, together with the frequent recovery of bullets from well bores, were considered strong evidence of inadequate penetration. Laboratory investigations of the penetration performance of many of the bullet guns available as late as 1948 gave support to these indications. Subsequent electrical analog studiesl,2,3 indicated that the depth of penetration required to provide productivities equivalent to open hole was beyond the capacity of most bullet perforators evaluated in the early laboratory penetration tests. These results, together with the advent of the shaped charge in the field of oil well perforating, stimulated the interest of both oil operators and service companies in gun development. Improvements in gun design resulted in jet and bullet guns which appeared to be capable of providing sufficient penetration for most perforating jobs. However, some wells failed to yield satisfactory fluid production even after being perforated with the more powerful guns, again raising the question as to the effectiveness of the perforating operation. This fact, together with preliminary shooting into targets prepared with formation cores, indicated that factors associated with the perforating process and/or the fluids in the well bore at the time of shooting may reduce effective formation penetration and thereby decrease well productivity. These laboratory and field data prompted another phase in the investigation of the effectiveness of gun perforating: a program to determine the extent and seriousness of perforation plugging under simulated well conditions.

Jan 1, 1955

By C. J. Rodgers

The present day success of gravel packs to prevent or retard the migration of unconsolidated sands into the well bore is due to: (I) the use of a saline or non-aqueous, nonsolids drill fluid, (2) proper preparation of the well bore prior to gravel packing, and (3) pressure placement of the gravel. The experience gained from the "pressure pack" method of gravel packing indicates that sand-free fluid production can be maintained for a length of time sufficient to make the operation economically attractive. Data pertaining to the first 15 wells so completed by Gulf indicate that for each dollar spent to effect the completion, there will be a return of more than $2.92. The pressure pack technique of gravel packing is essentially the placing of gravel in and adjacent to the producing formations. This is done with fluid pressure and by the use of a drill fluid that will permit partial or complete loss of returns to the formation during placement. This technique was first intentionally used by Gulf in May, 1950, and since that time has been applied in more than 90 wells. Other advantages claimed for this type of completion are that the pressure placement of the gravel has a scouring effect on the casing perforations, that additional drainage channels to the well bore are created, and that the possibility of shifting of the formations adjacent to the casing is minimized and possibly prevented. During the past few years, the use of gravel to prevent or retard the migration of unconsolidated sands into the well bore has met with a favorable degree of success. Numerous methods and techniques of "gravel packing" have been used, each having its own relative merits, and with varying results. M. L. Cashion1 in 1939 ably reviewed the history of gravel packing to that time. As stated in his paper, ". .. the idea of gravel packing wells is not new." During the period 1939 to 1949, very little if any progress or change in technique in this type of completion was made. However, it was noted in some cases that during the placement of gravel, if there was a loss of drill fluid to the formation, there was a corresponding loss of gravel to the formation. Also, it was noted that in those gravel-packed completions (opposite casing perforations) that "sanded up," there was found to be an absence of gravel in the annular space between the liner and casing, although gravel had previously been placed in this space and no gravel had been removed from the well at the surface. These findings resulted in the placement of gravel with fluid pressure and by the use of a drill fluid that would permit partial or complete loss of returns to the formation during placement. Pressure placement of gravel became an accepted practice in late 1949 and early 1950. Another fact brought to light that has contributed to the current success of gravel pack completions is that drilling fluids containing solids will to some extent cause plugging of the screening medium or blocking of the producing section. The removal of these solids by chemical action, mechanical action, or a combination of the

Jan 1, 1955

By W. E. Bergman, P. G. Carpenter, H. B. Fisher

The conditions under which barium carbonate can be used to remove sulfates from drilling muds are limited The amount of sulfate remaining in solution in the system after treatment with barium carbonate is shown to be a function of the concentration of the carbonate and barium ions and the concentration of other electrolytes. Barium hydroxide may advantageously replace barium carbonate when the contamination is not entirely due to anhydrite (calcium in the system is then stoichiometrically less than sulfate) or when the carbonate concentration is high. The effect of substances such as quebracho, phosphates, and chromates, which form complexes or precipitates with barium, is discussed. INTRODUCTION As the complexity of the operations in drilling for oil has increased, more attention has of necessity been directed to the problems pertaining to the maintenance of good drilling mud properties. As a result, chemical treatment of muds has become an important factor in recent years. Some of these treatments have been designed to eliminate the deleterious effects of contaminants in aqueous mud systems by precipitation or other means. The most common of substances encountered during drilling include sodium chloride, cement, and calcium sulfate while various other contaminants: usually in small amounts, may be introduced from the water, clays, and other materials used in preparation of the mud. In certain cases, for example where continued salt-water flow is encountered or massive anhydrite is drilled, special muds may be used so that the physical properties of the mud will remain satisfactory for drilling. In other cases, it is desirable to remove the contaminants so that soluble electrolytes in the system are maintained at low values. For sulfate contamination, the conlmon practice in the field is to add barium carbonate to precipitate the sulfate as barium sulfate Ordinarily such a procedure gives satisfactory results. There have been important instances, however, where addition of barium carbonate was not effective in removal of soluble sulfates from drilling muds. and it is to these cases that the present paper is directed. While it is generally known that barium carbonate is not always effective in removing soluble sulfates from drilling muds, certain inconsistencies appear in the literature as to the limitations of its use, and little explanation for the limitations are given. Varnell and Kimbrel state that "the treatment (with barium carbonate for removal of sulfate) is simple and consists in maintaining a pH of 9 with caustic soda and quebracho." They caution that concentrations of quebracho greater than 1 lb./bbl. may inhibit the reaction. In another publication&apos;, a pH of 10.5 is considered "the maximum desirable," and the indication is that as much as 2.5 lb. quebracho per barrel may be present in the particular mud under discussion. Lancaster and Mitchell5 state that appreciable amounts of phosphates in the mud will inhibit the reaction with barium carbonate and that the phosphate treatment should be discontinued at least 24 hours before addition of the carbonate. Experimental work was initiated to ascertain the factors involved in using barium carbonate for the removal of sulfate contamination in drilling muds. While the experimental data herein reported are limited, they focus attention on the pertinent factors which must be considered for successful treatment. These factors are discussed from a practical and a theoretical view, the latter being supported by equilibrium data found in the literature. Further, it will be appreciated that the factors involved in this specific study will be closely analogous to those in certain of the other chemical treatments which involve a precipitation of the soluble contaminant. A thorough comprehension of these factors should result in a more fruitful application of this type of chemical reaction to the treatment of drilling muds. EXPERIMENTAL A. Reagents Two muds were used during this investigation. For one series of tests, bentonite suspensions were prepared by dilution of a stock suspension containing 8 per cent by weight of bentonite (Aquagel). For another series, a 6.4 per cent ben-tonitic mud weighted to 9.7 lb./gal. with barium sulfate (Mag-cobar) was used. Distilled water was used in all preparations. The quebracho (72% tannin extract) was obtained from the Thompson-Hayward Co. of Tulsa and contained 11.4 per cent moisture (105 C.). All other materials were reagent grade, and concentrations were corrected for water of crystallization, if any. All concentrations are expressed in pounds per barrel (42 gallons). B. Technique The systems — either mud or water — were contaminated with either sodium or calcium sulfate after treatment with the desired amounts of sodium hydroxide and quebracbo. For treatments with barium carbonate an approximately 3-fold excess (5 lb./bbl.) was used over that computed to be required to precipitate all the sulfate as barium sulfate. Barium hydroxide was used in concentrations of 2 lb./bbl. — about

Jan 1, 1949

By P. G. Carpenter, H. B. Fisher, W. E. Bergman

The conditions under which barium carbonate can be used to remove sulfates from drilling muds are limited The amount of sulfate remaining in solution in the system after treatment with barium carbonate is shown to be a function of the concentration of the carbonate and barium ions and the concentration of other electrolytes. Barium hydroxide may advantageously replace barium carbonate when the contamination is not entirely due to anhydrite (calcium in the system is then stoichiometrically less than sulfate) or when the carbonate concentration is high. The effect of substances such as quebracho, phosphates, and chromates, which form complexes or precipitates with barium, is discussed. INTRODUCTION As the complexity of the operations in drilling for oil has increased, more attention has of necessity been directed to the problems pertaining to the maintenance of good drilling mud properties. As a result, chemical treatment of muds has become an important factor in recent years. Some of these treatments have been designed to eliminate the deleterious effects of contaminants in aqueous mud systems by precipitation or other means. The most common of substances encountered during drilling include sodium chloride, cement, and calcium sulfate while various other contaminants: usually in small amounts, may be introduced from the water, clays, and other materials used in preparation of the mud. In certain cases, for example where continued salt-water flow is encountered or massive anhydrite is drilled, special muds may be used so that the physical properties of the mud will remain satisfactory for drilling. In other cases, it is desirable to remove the contaminants so that soluble electrolytes in the system are maintained at low values. For sulfate contamination, the conlmon practice in the field is to add barium carbonate to precipitate the sulfate as barium sulfate Ordinarily such a procedure gives satisfactory results. There have been important instances, however, where addition of barium carbonate was not effective in removal of soluble sulfates from drilling muds. and it is to these cases that the present paper is directed. While it is generally known that barium carbonate is not always effective in removing soluble sulfates from drilling muds, certain inconsistencies appear in the literature as to the limitations of its use, and little explanation for the limitations are given. Varnell and Kimbrel state that "the treatment (with barium carbonate for removal of sulfate) is simple and consists in maintaining a pH of 9 with caustic soda and quebracho." They caution that concentrations of quebracho greater than 1 lb./bbl. may inhibit the reaction. In another publication&apos;, a pH of 10.5 is considered "the maximum desirable," and the indication is that as much as 2.5 lb. quebracho per barrel may be present in the particular mud under discussion. Lancaster and Mitchell5 state that appreciable amounts of phosphates in the mud will inhibit the reaction with barium carbonate and that the phosphate treatment should be discontinued at least 24 hours before addition of the carbonate. Experimental work was initiated to ascertain the factors involved in using barium carbonate for the removal of sulfate contamination in drilling muds. While the experimental data herein reported are limited, they focus attention on the pertinent factors which must be considered for successful treatment. These factors are discussed from a practical and a theoretical view, the latter being supported by equilibrium data found in the literature. Further, it will be appreciated that the factors involved in this specific study will be closely analogous to those in certain of the other chemical treatments which involve a precipitation of the soluble contaminant. A thorough comprehension of these factors should result in a more fruitful application of this type of chemical reaction to the treatment of drilling muds. EXPERIMENTAL A. Reagents Two muds were used during this investigation. For one series of tests, bentonite suspensions were prepared by dilution of a stock suspension containing 8 per cent by weight of bentonite (Aquagel). For another series, a 6.4 per cent ben-tonitic mud weighted to 9.7 lb./gal. with barium sulfate (Mag-cobar) was used. Distilled water was used in all preparations. The quebracho (72% tannin extract) was obtained from the Thompson-Hayward Co. of Tulsa and contained 11.4 per cent moisture (105 C.). All other materials were reagent grade, and concentrations were corrected for water of crystallization, if any. All concentrations are expressed in pounds per barrel (42 gallons). B. Technique The systems — either mud or water — were contaminated with either sodium or calcium sulfate after treatment with the desired amounts of sodium hydroxide and quebracbo. For treatments with barium carbonate an approximately 3-fold excess (5 lb./bbl.) was used over that computed to be required to precipitate all the sulfate as barium sulfate. Barium hydroxide was used in concentrations of 2 lb./bbl. — about

Jan 1, 1949

By C. W. Binckley, F. R. Burgess, E. R. Haymaker

A method of establishing stabilized back-pressure curves for gas wells producing from formations of extremely low permeability is presented. Actual well performance under many different operating conditions is shown by the stabilized back-pressure curve. By use of the method. it is possible to conduct back-pressure tests with a critical-flow prover on wells that stabilize slowly, and save approximately 88% of the gas ordinarily vented to obtain satisfactory test data, with a great reduction in time required for testing. INTRODUCTION The reasons for establishing dependable back-pressure curves on gas wells have been pointed out by previous publications. The publication most referred to. of course, is the United States Bureau of Mines Monograph 7, titled "Back-Pressure Data on Natural Gas Wells and Their Application to Production Practices". The technique generally established therein has been accepted and used by many engineers; and, when proper tests are conducted, the results can be used for the analysis and solution of several practical problems concerning field operation and development. Even where formations of low specific permeability are encountered, the determination of a well&apos;s actual performance by the back-pressure test method permits the engineer to analyze many problems in individual well operation and also to predict necessary future field development. Such problems as the determination of the ability of a well to produce into a pipe line at a predetermined line pressure, the design of gas gathering systems and meter settings, and the determination of the time and the number of wells required to be drilled to meet future market obligations, can be solved, in part., by the use of a reliable back-~ressure curve. In addition, the computed well delivery rates determined by data from backpressure tests ordered by state regtilatory bodies, when compared with the true back-Pressure curve, permit the operator to ascertain whether such data represent unstable or relatively stabilized delivery rates for given pressure conditions of the well. The technique of back-pressure testing, as described in this report, was developed by Phillips Petroleum Company engineers from data obtained during a testing program that started in 1944 and has been continued to date. Three hundred and eleven back-pressure tests were conducted on 299 wells located in the southern part of the Hugoton Field. The gas-bearing zone is composed of several dolomitic formations of the Permian Age; the important ones are the Herington, Upper Krider, Lower Krider, and Winfield. The average bottom-hole temperature is approximately 91 °F.. and the initial wellhead shut-in pressures range from 400 to 440 psig. The spacing pattern is 640 acres per well with each well located near the center of the section. The range of back-pressure potentials on wells tested was from 500 to 23,000 Mcfd. All gas wells were acidized, and the quantity of acid used, expressed in 1574 hydrocloric acid, varied from 12,000 to 22,000 gallons per well. The quantity and concentration of each treatment depended on the stage, the formation being treated, and experience gained from previously completed wells. The gas in the Hugoton Feld is a "dry" gas. It has a gasoline content of approximately 0.25 gallons per thousand cubic feet, as determined by charcoal test, and its specific gravity averages about 0.71 as compared to air (air = 1.00 at 60°F.). Of the wells tested, 71 were completed with 7" casing, 3 with 9 5/8" casing, and 1 with 6%" casing set on top of the upper producing formation with the well bore through the gas bearing formations being open hole. Two hundred and twenty-four were completed with 5 1/2&apos;&apos; O.D. casing set through the gas bearing formations and perforated. For the purpose of establishing reliable back-pressure curves in the area, Phillips Petroleum Company personnel has computed data on the basis of 24-hour flows per point. Early in the program, many tests were actually permitted to flow 24 hours to obtain data for each plotting point, at great expense in man power and time. Presently, however, such tests have been replaced by tests of short duration flows which can be made to effect results that correspond to the tests obtained by flows of much longer duration. METHOD When a gas well producing from a reservoir of low permeability is opened for production through a constant size orifice, both the rate of flow and working pressure decline. first at a high rate and later at a lower rate until after several hours the decline becomes difficult to ascertain. In this paper the rae of flow and working pressure are considered to be stabilized when it becomes difficult to observe changes in working pressure during a period of three hours by the use of a deadweight pressure gage. Stalibization of pressure in the literal sense is never obtained in a producing gas well. In formations of low permeability. such as those in the Hugo-ton Field, most wellhead working pressures approach stabilization closely enough to be used satisfactorily in the determination of a back-Pressure potential curve after flow periods of 24 hours. We shall therefore describe the backpressure curve calculated from ohserved rates of flow and working pressure at the end of 24-hour flow periods.

Jan 1, 1949

By E. R. Haymaker, C. W. Binckley, F. R. Burgess

A method of establishing stabilized back-pressure curves for gas wells producing from formations of extremely low permeability is presented. Actual well performance under many different operating conditions is shown by the stabilized back-pressure curve. By use of the method. it is possible to conduct back-pressure tests with a critical-flow prover on wells that stabilize slowly, and save approximately 88% of the gas ordinarily vented to obtain satisfactory test data, with a great reduction in time required for testing. INTRODUCTION The reasons for establishing dependable back-pressure curves on gas wells have been pointed out by previous publications. The publication most referred to. of course, is the United States Bureau of Mines Monograph 7, titled "Back-Pressure Data on Natural Gas Wells and Their Application to Production Practices". The technique generally established therein has been accepted and used by many engineers; and, when proper tests are conducted, the results can be used for the analysis and solution of several practical problems concerning field operation and development. Even where formations of low specific permeability are encountered, the determination of a well&apos;s actual performance by the back-pressure test method permits the engineer to analyze many problems in individual well operation and also to predict necessary future field development. Such problems as the determination of the ability of a well to produce into a pipe line at a predetermined line pressure, the design of gas gathering systems and meter settings, and the determination of the time and the number of wells required to be drilled to meet future market obligations, can be solved, in part., by the use of a reliable back-~ressure curve. In addition, the computed well delivery rates determined by data from backpressure tests ordered by state regtilatory bodies, when compared with the true back-Pressure curve, permit the operator to ascertain whether such data represent unstable or relatively stabilized delivery rates for given pressure conditions of the well. The technique of back-pressure testing, as described in this report, was developed by Phillips Petroleum Company engineers from data obtained during a testing program that started in 1944 and has been continued to date. Three hundred and eleven back-pressure tests were conducted on 299 wells located in the southern part of the Hugoton Field. The gas-bearing zone is composed of several dolomitic formations of the Permian Age; the important ones are the Herington, Upper Krider, Lower Krider, and Winfield. The average bottom-hole temperature is approximately 91 °F.. and the initial wellhead shut-in pressures range from 400 to 440 psig. The spacing pattern is 640 acres per well with each well located near the center of the section. The range of back-pressure potentials on wells tested was from 500 to 23,000 Mcfd. All gas wells were acidized, and the quantity of acid used, expressed in 1574 hydrocloric acid, varied from 12,000 to 22,000 gallons per well. The quantity and concentration of each treatment depended on the stage, the formation being treated, and experience gained from previously completed wells. The gas in the Hugoton Feld is a "dry" gas. It has a gasoline content of approximately 0.25 gallons per thousand cubic feet, as determined by charcoal test, and its specific gravity averages about 0.71 as compared to air (air = 1.00 at 60°F.). Of the wells tested, 71 were completed with 7" casing, 3 with 9 5/8" casing, and 1 with 6%" casing set on top of the upper producing formation with the well bore through the gas bearing formations being open hole. Two hundred and twenty-four were completed with 5 1/2&apos;&apos; O.D. casing set through the gas bearing formations and perforated. For the purpose of establishing reliable back-pressure curves in the area, Phillips Petroleum Company personnel has computed data on the basis of 24-hour flows per point. Early in the program, many tests were actually permitted to flow 24 hours to obtain data for each plotting point, at great expense in man power and time. Presently, however, such tests have been replaced by tests of short duration flows which can be made to effect results that correspond to the tests obtained by flows of much longer duration. METHOD When a gas well producing from a reservoir of low permeability is opened for production through a constant size orifice, both the rate of flow and working pressure decline. first at a high rate and later at a lower rate until after several hours the decline becomes difficult to ascertain. In this paper the rae of flow and working pressure are considered to be stabilized when it becomes difficult to observe changes in working pressure during a period of three hours by the use of a deadweight pressure gage. Stalibization of pressure in the literal sense is never obtained in a producing gas well. In formations of low permeability. such as those in the Hugo-ton Field, most wellhead working pressures approach stabilization closely enough to be used satisfactorily in the determination of a back-Pressure potential curve after flow periods of 24 hours. We shall therefore describe the backpressure curve calculated from ohserved rates of flow and working pressure at the end of 24-hour flow periods.

Jan 1, 1949

By Lincoln F. Elkins, John T. Cooke

Injection of gas to increase oil recovery has been considered for almost all important discoveries during the past ten or fifteen years. However, the number of gas injection projects having sufficient history and data is too limited to permit valid generalities of effectiveness of gas injection. Management and engineers are faced with a difficult problem of selecting those reservoirs which are susceptible to profitable application of gas injection. Injection of gas to maintain high pressure favors some factors affecting reservoir performance such as viscosity, surface tension, and formation volume factor of oil by keeping gas in solution and favors some operating features such as extending flowing life of wells and storing part of the produced gas for future use or sales. Injection of gas at low pressure involves lower compression ratio, or at least a single gas-gathering system, larger displacement volume in the reservoir per unit of gas handled, and permits effective utilization of the naturally existing energy and agent for oil displacement that is gas dissolved in oil. Each program is thus a compromise to meet optimum economic conditions while striving to attain maximum recovery of this important nautral resource. The statement has often been made that pressure maintenance would greatly increase oil recovery by permitting abandonment of formation oil inflated with gas in solution rather than abandonment of the same liquid volume of tank oil, if the same terminal oil saturation could be attained. Simple calculations indicate increases in oil recov- ery as high as one hundred per cent on this basis for high formation volume factor oil encountered in current deep drilling. Important in this statement is "if the same terminal oil saturation could be attained." Implicit in this statement are the requirement of physical

Jan 1, 1949

By John T. Cooke, Lincoln F. Elkins

Injection of gas to increase oil recovery has been considered for almost all important discoveries during the past ten or fifteen years. However, the number of gas injection projects having sufficient history and data is too limited to permit valid generalities of effectiveness of gas injection. Management and engineers are faced with a difficult problem of selecting those reservoirs which are susceptible to profitable application of gas injection. Injection of gas to maintain high pressure favors some factors affecting reservoir performance such as viscosity, surface tension, and formation volume factor of oil by keeping gas in solution and favors some operating features such as extending flowing life of wells and storing part of the produced gas for future use or sales. Injection of gas at low pressure involves lower compression ratio, or at least a single gas-gathering system, larger displacement volume in the reservoir per unit of gas handled, and permits effective utilization of the naturally existing energy and agent for oil displacement that is gas dissolved in oil. Each program is thus a compromise to meet optimum economic conditions while striving to attain maximum recovery of this important nautral resource. The statement has often been made that pressure maintenance would greatly increase oil recovery by permitting abandonment of formation oil inflated with gas in solution rather than abandonment of the same liquid volume of tank oil, if the same terminal oil saturation could be attained. Simple calculations indicate increases in oil recov- ery as high as one hundred per cent on this basis for high formation volume factor oil encountered in current deep drilling. Important in this statement is "if the same terminal oil saturation could be attained." Implicit in this statement are the requirement of physical

Jan 1, 1949

By R. V. Smith

The theoretical background for calculating friction factors for flow in gas wells by two methods is presented. The first method, requiring pressures, temperatures and specific volumes of the flowing fluids at various depths in the well bore, shows how the mechanical-energy-balance equation for vertical flow may be graphically integrated over the actual path of the expansion of the fluid in the well. Thus, assumptions regarding the effective temperature and effective compressibility of the fluid in the well are avoided. The second method presents an equation derived on a basis of the assumptions that both the temperature and the compressibility are fixed at constant effective values throughout the flowing column of gas. The second method provides a convenient and practical means of calculating friction factors for gas wells and lends itself readily to the problem of calculating subsurface pressures in a flowing gas well. The application of both methods to actual test data taken on a flowing gas well is illustrated in the paper. INTRODUCTION As friction factors for the producing strings of flowing gas wells cannot be measured directly and must be calculated from flow-test data, study of the methods of arriving at friction factors is a necessary adjunct to understanding the characteristics of flow in gas wells. There are two methods of calculating friction factors for gas wells; they differ from one another mainly in the treatment of the path of expansion of the fluid in the well. In the flowing well, the energy consumed in lifting the fluid from the bottom to the top of the well, overcoming the friction between the moving fluid and the pipe walls, and increasing the velocity of the fluid as it flows up the producing string is supplied by expansion of the flowing fluid. The available energy is determined by the expansion of the fluid that follows a path determined by conditions of temperature, compressibility and phase changes of the fluid during the expansion. A means of evaluating the available energy in a flowing gas well and determining the proportion of the available energy used in lifting the gas, overcoming friction, and increasing the velocity of flow is developed in this report. Knowing how much energy is consumed in overcoming friction makes it possible to calculate friction factors for given flow rates in given sizes of pipes in wells. Friction coefficients, as used in this report, are dimension- less proportionality multipliers used in the flow equations to satisfy the equality between the terms of the equation. The square root of the reciprocal of the friction coefficient is termed the friction factor. It has been known for many years that friction factors may be computed directly from mathematical formulas based on certain assumptions regarding the temperature and compressibility of the moving fluid in a well. A general equation is presented in this report without assumptions for vertical flow of fluids and a conventional-type equation is derived on the basis of assumptions that fix the temperature and compressibility at constant values. Accurate pressures at the sand faces in wells are required in the method of determining the productivity of gas wells, as outlined by Rawlins and Schellhardt1 in Bureau of Mines Monograph 7. Where measurements are not made with subsurface-pressure gauge; or static gas columns are unavailable, flowing pressures customarily are calculated at the sand face in the well by the use of the well-known Weymouth formula1. Natural gas engineers have realized that errors introduced by the use of friction factors as given by the Weymouth formula are relatively unimportant in testing low-capacity gas wells; they also know that such factors are important considerations in testing large-capacity gas wells. Accordingly. present research on the productivity of gas wells at the Petroleum Experiment Station of the Bureau of Mines, Bartlesville, Okla., is being directed toward measurement of the pressure loss due to friction in flowing gas wells. It is beyond the scope of this report to show how friction factors vary with rate of flow and in pipes of different diameters, as it is intended only to develop and illustrate the use of mathematical expressions for calculating friction factors from flow-test data. The equations presented apply only to turbulent flow in circular pipes. ENERGY RELATIONS FOR FLOW OF FLUIDS2 The concept of conservation of energy is usually the basis of any study of fluid flow through vertical pipes as in gas wells, horizontal pipe lines, or orifices. In deriving equations, the following symbols are used:

Jan 1, 1950

By Leon W. Dupuy

Many articles have been written describing peculiar and particular types of drilling. Little correlation has been made between the character of ground to be drilled and sampled and the type of drilling most desirable for procuring satisfactory samples. In development work, the engineer and metallurgist often desire the recovery of a sample in as physically natural a condition as possible, particularly when the sample must provide material for process tests as well as chemical and physical analyses. This paper describes the results of experimentation in drilling unconsolidated materials carrying titanium minerals in the Magnet Cove area, Ark. The drilling was most difficult in that the ground varied much in consistency, and it was vitally necessary to recover a physically natural sample. Ordinary churn drilling recovered a sample that could be analyzed chemically, but the sample was not in its natural state. The problem was successfully solved by utilizing and further developing methods used in the oil and clay industries.

Jan 1, 1949

By Elton A., Youngberg

The Holden mine operated by the Chelan Division of the Howe Sound Co. is on the east slope of the Cascade Range in north central Washington on the south slope of Railroad Creek valley at an elevation of 3500 ft. The mine may be reached by a 40 mile boat trip from the town of Chelan which is at the southern tip of Lake Chelan, to Lucerne at the mouth of Railroad Creek and an 11 mile bus ride up Railroad Creek to Holden. All freight and concentrate is moved over this route to Chelan Falls on the Columbia River which is on the railroad four miles below the town of Chelan. The mine is now producing 2000 tons of gold, copper, and zinc ore per day which is treated in the Holden mill. Gold-copper and zinc concentrates are made, the first of which is shipped to Tacoma, Wash., and the latter to Kellogg, Idaho, for smelting.

Jan 1, 1949

Market confidence is on the rise and industry leaders turning toward the vast and diverse region of Latin America are faced with abundant, yet daunting, opportunity. From the iron orebodies of Brazil to the renowned copper mines of northern Chile, drilling teams in Latin America are often faced with abrasive, broken ground. These types of ground conditions tear up coring bits rapidly, making it extremely difficult for even the most seasoned drilling teams to maintain effective productivity. The drilling challenges faced in this rich and opportune region are being met today by advanced coring technology, bringing with it the potential for increased productivity in Latin American mineral exploration.

Jan 3, 2010

By George W. Friesen

This paper presents the historical trend and de- fines the causes of drilling cost escalation in the Gulf of Mexico during the 1970&apos;s. The three major components of escalation are: 1) inflation, 2) supply-demand imbalance (demand pull) and 3) decreases in drilling efficiency. The decade was divided into three periods. During each period one component of escalation was responsible for most of the rise in costs. From 1970 through 1973 only inflation pushed costs upward. During 1974 and 1975 a supply- demand imbalance caused most of the escalation. Since 1975, decreases in drilling efficiency have produced the major component of escalation. During any one year or period of years, the sum of the three components will give the total escalation rate. The reasons why different components contribute more toward escalation during certain years than others are shown by following the timing of oil and gas price increases, the overall quality of the acreage offered each year in offshore lease sales and the resulting drilling activity.

Jan 1, 1982

By Alexandra Yuyali

The objective of this research work is to increase the drilling ratio represented in tons per drilled meter (ton/m) to reduce mining costs. One of the key characteristics of this research is the use of the ITH (in-the-hole) drilling rig with a water-powered hammer, also known as Wassara™. The patented Wassara™ in-the-hole hammer is powered by high-pressure water instead of air. To reach the objective, a new design of the blast pattern was implemented considering the following: Burden from 1.7 m (5.6 ft) to 2.8 m (9.2 ft) Spacing from 1.7 m (5.6 ft) to 2.7 m (8.9 ft) Drill diameter from 89 mm (3.5”) to 102 mm (4”) Drilling length from 15 m (49 ft) to 30 m (98 ft) Borehole deviation < 2% The result of this new design is the optimization of the drilling ratio (ton/m); having as a baseline 5.2 ton/m with traditional equipment and obtaining 13.7 ton/m with the ITH drilling, which generates annual savings of $2.43M.

Jan 21, 2025

By Lee B. Paterson

Mining Engineers throughout the world have an appreciation for the importance of the role of the Blasthole Drill in one of the primary elements of the mining process. This paper highlights areas that could influence the overall cost effectiveness of that process of breaking rock and the associated downstream mining and ore recovery activities - and how the drill is designed and configured to meet that challenge. Factors influencing drill productivity and overall cost effectiveness are addressed, particularly regarding the benefits which are not necessarily reflected in the drilling process and therefore more difficult to quantify. This paper explores some of the downstream benefits of what we do to the drilling process.

Jan 1, 2000

Considerable improvements in diamond drilling equipment have been made since the early 1950s. A recent drilling programme, however, at Williamtown, near Newcastle, carried out by the Joint Coal Board on behalf of the Electricity Commission of New South Wales, emphasized deficiencies in existing equipment when particularly diflkult coring conditions were encountered.Spurred by unacceptably low recoveries in coal seams in this area, the Joint Coal Board devised and developed, with the assistance of the Electricitv Commission, a new typc core lifter and a special 26 ft triple tube core barrel, designed to operate in conjunction with it in bad coring conditions.The core lifter, whieh is propped open clear of incoming core during drilling, is activated by fluid impulses generated inside the core barrel. It can be used with double tube barrels when drilling firm rocks whichdo not change diameter by compaction inside the barrel.Softer rocks. such as clayey types, require the use of a rriple tube barrel.Results from testing carried out to date in difficult areas in New South Wales coalfields have shown that greatly improved results can be obtained with the new equipment. Although developed essentially for coaldrilling, the new core lifter and barrel could be adapted to other fields of diamond drilling. Even in areas where no great coring difficulty is encountered the cost advantage deriving from the greatly inereased life of the core lifter and the adaptor in which it is housed could justify its use.

Jan 1, 1967