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By K. E. Brown, A. R. Hagedorn

Continuous, two phase flow tests have been conducted during which four liquids of widely differing viscosities were produced by means of air-lift through 1%-in. tubing in a 1,500-ft. experimental well. The purpose of these tests was to determine the effect of liquid viscosity on two-phase flowing pressure gradients. The experimental test well was equipped with two gas-lift valves and four Maihak electronic pressure transmitters as well as instruments to accurately measure the liquid production, air injection rate, temperatures, and surface pressures. The tests were conducted for liquid flow rates ranging from 30 to 1,680 BID at gas-liquid ratios from 0 to 3,-270 scf/bbl. From these data, accurate pressure-depth traverses have been constructed for a wide range of test conditions. As a result of these tests, it is concluded that viscous effects are negligible for liquid viscosities less than 12 cp, but must be taken into account when the liquid viscosity is greater than this value. A correlation based on the method proposed by Poettmann and Carpenter and extended by Fan-cher and Brown has been developed for 1¼-in. tubing, which accounts for the effects of liquid viscosity where these effects are important. INTRODUCTION Numerous attempts have been made to determine the effect of viscosity in two-phase vertical flow. Previous attempts have all utilized laboratory experimeneal models of relatively short length. One of the initial investigators of viscous effects was Uren1 with later work being done by Moore et al.2,3 and more recently by Ros.4 However, the present investigation represents the fist attempt to study the influence of liquid viscosity on the pressure gradients occurring in two-phase vertical flow through a 1¼-in., 1,500 ft vertical tube. The approach of some authors has been to assume that all vertical two-phase flow occurs in a highly turbulent manner with the result that viscous effects are negligible. This has been a logical approach since most practical oil-well flow problems have liquid flow rates and gas-liquid ratios of such magnitudes that both phases will be in turbulent flow. It has also been noted, however, that in cases where this assumption has been made, serious discrepancies occur when the resulting correlation is applied to low production wells or wells producing very viscous crudes. Both conditions suggest that perhaps viscous effects may be the cause of these discrepancies. In the first case, the increased energy losses may be due to increased slippage between the gas and liquid phases as the liquid viscosity increases. This is contrary to what one might expect from Stokes law of friction,' but the same observations were made by ROS4 who attributed this behavior to the velocity distribution in the liquid as affected by the presence of the pipe wall. In the second case, the increased energy losses may be due to increased friction within the liquid itself as a result of the higher viscosities. The problem of determining the li- quid viscosity at which viscous effects becomes significant is a difficult one. Ros4 has indicated that liquid viscosity has no noticeable effect on the pressure gradient so long as it remains less than 6 cstk. Our tests have shown that viscous effects are practically negligible for liquid viscosities less than approximately 12 cp. Actually there is no single viscosity at which these effects become important. These effects are not only a function of the viscosities of the liquids and of the gas but are also a function of the velocities of the two phases. The velocities in turn are a function of the in situ gas-liquid ratio and liquid flow rate. Furthermore, the role of fluid viscosities in either slippage or friction losses will depend on the mechanism of flow of the gas and liquid, i.e., whether the flow is annular. as a mist, or as bubbles of gas through the liquid. These mechanisms are also a function of the in situ gas-liquid ratios and the flow rates. It would thus seem that the best one could hope for is to determine a transition region wherein the viscous effects may become significant for gas-liquid ratios and liquid production rates normally encountered in the field. The viscous effects might then be neglected for liquid viscosities less than those in the transition region but would have to be taken into account when higher viscosities are encountered. There are numerous instances where crude oils of high viscosity must be produced. The purpose of this study has been to evaluate the effects of liquid viscosities on twephase vertical flow by producing four liquids of widely differing viscosities through a 1 % -in. tube by means of air-lift. The approach used in this study was as follows:

Jan 1, 1965

By C. T. Philipp

Recycling of waste is much preferred over disposal. This paper discusses the Enviroscience, Inc. (ESI) process, now being commercialized by MetWool, Inc., to recycle hazardous wastes using an extractive metallurgical process which is followed by vitrification of non-reducible metal oxides. In this process, volatile and reducible metals are reclaimed as their respective oxides and elements.

Jan 1, 1995

By J. M. Bray, R. R. H. Cohen, P. Kiousis, S. R. Al-Abed

"INTRODUCTION Conventional tailing storage and management practices typically utilize engineered facilities, such as ring dikes and valley impoundments. To reduce the environmental costs associated with disposing of mine wastes in tailing storage facilities (TSFs), several beneficial re-use strategies have been developed over the years. For example, thickened tailings have been used for paste backfill. It is common for tails to comprise up to 60% of the material’s total weight and it has been estimated that TSF volumes can be reduced by 60% when using this strategy, (Benzaazoua, et al. 2004). Other beneficial re-use strategies have produced unpaved temporary access roads, hot and cold asphalt, chip seals, self-compacting concrete, and golf course sand traps. This project sampled mine tailings from two different TSFs in Colorado and produced structural concrete that could potentially be used for commercial foundations, sidewalks, and paved roads. The tailings were substituted for the fine aggregates typically found in conventional concrete. The two main objectives of this study were to investigate the structural integrity of the produced concrete samples and the leaching of heavy metals from the resulting concrete. The ratio of tailings to fine aggregate (T/FA) was carefully studied to find if there was a correlation between the substitution rate and the structural integrity. The potential maximum substitution rate was also investigated for the produced concrete specimens. The potential of leaching mining impacted water (MIW) was evaluated by comparing the leachability of the raw mine tailings to the encapsulated tailings by using standard shake extraction prediction tests. MATERIAL AND METHODS Materials The four components that make up the concrete mix design for this project are: cement, coarse aggregate (gravel), fine aggregate (sand and mine tailings), and water. The type I/II ordinary Portland cement (OPC), gravel, and sand came from local cement and concrete companies in Denver, Colorado. Mine tailings were collected from two different TSFs in the Rocky Mountain Region, where Pride of the West TSF in Silverton, CO will be denoted as Site A. The primary metals of interest at the mill site are gold, silver, lead, copper, and zinc. The location of Site B will not be mentioned in this report due to confidentiality agreements with the mining company"

Jan 1, 2016

By F. W. Jessen, James N. Howell

The accumulation of paraffin deposits in tubular goods has been recognized as a major production problem since the inception of the petroleum industry. This problem is not limited to any particular geographical area nor is it limited to a specific type of crude oil.' Generally speaking, "paraffin" deposition pertains to the deposition of any predominately organic material in flow lines, and possibly even at the sand face, which would hamper the production of oil. In some fields, a continuous effort is required to remove deposits of paraffin and in order to accomplish this, many unique methods have been devised. The best solution to this problem, however, is to prevent the formation of such deposits. One method which has been tried in a number of fields is the use of plastic pipe. The purpose of this investigation is to compare the relative effectiveness of several plastic materials to aid in the reduction or prevention of paraffin accumulations in surface flow lines. COMPOSITlON OF PARAFFIN DEPOSITS By definition, paraffin deposits are those materials which are insoluble in crude oil at the prevailing producing conditions of temperature and pressure. Such deposits1 s usually consist of small particles of petroleum wax intermixed with resins, asphaltic material, and crude oil. They may also contain a variety of foreign materials such as sand, silt, water, various metal oxides, sulfates and carbonates of iron. barium, and calcium. The petroleum waxes deposited in flow strings usually consist of both a "hard" and a "soft" wax fraction. These waxes are largely aliphatic hydrocarbons with smaller amounts of aromatic and naphthenic compounds. Nathan' has classified the hard and soft wax fractions. The aliphatic hydrocarbons present are those of high molecular weight with high melting points. Reistle3 pointed out that these high molecular weight compounds first separate from the oil due to a sharp decrease in solubility as the melting point increases. The identification of the resins and asphaltic materials rests, at present, on an arbitrary solubility procedure. Under certain conditions, materials which are insoluble in pentane (ASTM D-893) are defined as resins and asphalts. Subgrouping of these materials is made on decreasing solubility in benzene and carbon disul-fide. Shock' found some correlation be-tween the solvent response and the pentane insoluble content of paraftins: higher pentane insoluble fractions are less soluble in any of the commonly used commercial solvents. PARAFFIN CONTROL METHODS The methods used in oil fields to prevent and remove paraffin accumulations can be grouped into four general classes: (1) operative methods, (2) physical methods, (3) chemical methods, and (4) combination of any of these. Operative methods attempt to prevent the formation of paraffin deposits while the other methods are concerned primarily with the removal of these deposits. Plastic coated pipe has been used for a number of years to prevent cor- rosion in wells, and in manv instances paraffin deposits have -been greatly reduced. Field observations have indicated that plastic coated pipe not only reduced paraffin accumulation but in some cases eliminated deposition completely; however, data are needed to demonstrate the relative effectiveness of plastic materials. Deposition Apparatus The pipe used to determine the effect of velocity on rates of deposition was %- and 2-in. nominal diameter, and 5 ft in length. Steel, butyrate, rigid PVC, kralastic resin-type plastic pipes, epoxy coated pipe, PVC lined glass fiber pipe, and aluminum pipe were tested. Steel pipe was used as a control. Fig. 1 is a schematic diagram of the apparatus showing the relative position of the separate units making up the equipment. In order to facilitate the installation and removal of the test pipes in the apparatus, O-ring seals capable of sustaining pressures of 50 psi were provided at each end. Test pipes were submerged in a cold water bath maintained at or below room temperature by circulating water through copper cooling coils packed in ice. A hot water bath equipped with immersion-type heaters, stirrers, and a thermoregulator was used to maintain the temperature of the oil prior to introduction into the piping manifold. The capacity of the oil reservoir was 30 gal. A 33-gal/min centrifugal pump, capable of producing turbulent flow velocities in the test pipes, was used to circulate the oil through the system when using %-in. pipe; and a 70-galjmin centrifugal pump was used in later tests using 2-in. pipe. A by-pass arrangement made it pos-

By J. V. Vogel

Jan 1, 1969

By C. D. Hall, F. E. Dollarhide

Fluid Ioss agent.s for crude oil and for water have been studied in dynamic tests. A treatment using a spearhead with a fluid loss agent followed by plain fluid appears feas ible in crude oil, but not in water. An equation for spearhead depletion shows that spurt loss relative to fracture width must be low, if the portion of spearhead fluid in the treatment is to be small. The presence of colloidal matter in crude oils aids the fluid Ioss agent. Unlike in kerosene, where flow limited the agent deposition, in crude oils the filter cake continually formed and leak-off declined. The volume-time relation varied somewhat for different crudes, but was best described by a square root of time function. Spurt loss was inversely proportional to agent concentration. After the fluid loss agent initiated the filter cake, the crude oil colloids built on it effectively. A 2-minute or a 5-minute spearhead with double the normal agent concentration gave the same fluid Ioss curve as the same concentration did for a 30-minute test. The agents tested in water gave fluid Ioss plots on which, for the first few minutes, volume was proportional to the square root of time, but later became proportional to time. For fracture area calculation the customary square root of time function is a satisfactory approximation. Leak-off rates and spurt losses were higher in water systems than in oils. The spurt Ioss tended to be inversely proportional to concentration. In spearhead tests, the filter cakes were not eroded by water flow. However, the rather high spurt loss values make spearhead treatments impractical for water-based fluids. Introduction The effects of dynamic testing conditions on the performance of fluid loss agents in kerosene have been studied previously.' We have extended the work to include crude-oil- and water-based fracturing fluids. An understanding has been gained of the mechanisms of formation and functioning of the filter cakes of fluid loss agents. The practical aspects of evaluating performance of agents in relation to fracture area calculations also are considered. The feasibility of using the fluid loss agent in a spearhead stage of the treatment is examined further for both types of fluids. Experimental Procedure The dynamic fluid loss tests were performed in an apparatus similar to the high-pressure apparatus described in a previous publication.' A fracturing fluid was circulated over a rock surface located in a closed pressurized loop. The fluid flowed axially over the cylindrical surface of a core 2 in. in diameter X 3.5 in. long, mounted (with the flat ends sealed off) in a pipe, with 0.117 in. annular clearance. The filtrate was collected in a central hole in the core and led through valves to graduated cylinders. Provision was made for changing quickly the circulating fluid during the test (spearhead runs) without interrupting the filtration pressure. The only modifications were to add heating tapes and water jackets for the tests with crude oils, all conducted at ISOF, and to change all parts exposed to the test fluid to stainless steel for the tests with water-based fluids. The latter tests were made at room temperature, 80F. Three crude oils were tested. A mixed crude, obtained from a local refinery, contained a considerable amount of light ends. For safety reasons, it was stripped to 250F vapor temperature before use in the fluid loss tests. The other two oils were used as obtained from lease tanks. One was a greenish-brown, 37" API paraffinic crude, and the other was a black, 32" API asphaltic crude. The fluid loss agent for oil, here designated for brevity as Agent A, was Adomite@ Mark II*, a granular solid commercial agent, the same as previously tested in kerosene.' Three different compositions of fluid loss agents were tested in Tulsa tap water. Agent B was adomit& Aqua*, a solid commercial fluid loss agent, comprising clays and hydrophilic gums principally derived from starch. Agent C was a mixture of three parts of Agent B with two parts of silica flour. Agent D was Dowel1 J137, a mixture of guar gum and silica flour. The test cores were cut from contiguous blocks of Berea or Bandera sandstones. For the oil tests, the cores were oven dried, evacuated, saturated with kerosene, and the kerosene permeability was measured. The cores used with the water-based fluids were pretreated by saturating with 3 percent calcium &loride solution to minimize pemeability damage by the fresh water due to clay migration. The

Jan 1, 1969

By H. D. Hodges, J. K. Godbey

In order to better understand the fracturing process, bottom-hole pressures were measured during a number of typical fracturing operations. A recently developed system was used that allows simultaneous surface recording of both the bottom-hole and wellhead pressures on the same chart. The results from six fracruring treatments are summarized on the basis of the pressure data obtained. Al-though no complete analysis is attempted, the value of accurate pressure measurements is emphasized. Important characteristics of the bottom-hole pressure record do not appear at the wellhead because of the damping effect of the fluid-filled column. In four of the six treatments described, the formations apparently fractured during the initial surge of pressure with only crude oil in the well. The properties of the fluids used during the treatments are given and the fluid friction losses are obtained directly from the pressure records. This technique is also shown to be adequate for determining when various fluids, used during the process, enter the formation. INTRODUCTION Hydraulic fracturing for the purpose of increasing well productivity is now accepted in many areas as a regular completion and workover practice. Numerous articles have appeared in the literature discussing the various techniques and theories of hydraulic fracturing'. In general, three basic types of formation fractures are recognized today. These are the horizontal fracture, the vertical fracture, and fractures along natural planes of weakness in the formation'. Any one or all three of these fracture types may be present in a fracturing operation. However, with only the wellhead pressure record as a guide, it is difficult at best to determine if the formation actually fractured, and is almost impossible to determine the type of fracture induced. These difficulties arise in part because the wellhead pressure record, especially when fracturing through tubing, does not accurately reflect the pressure variations occurring at the formation. Several factors contribute to this effect and preclude the possibility of using the wellhead pressure as a basis for accurately calculating the bottom-hole pressure. These factors are: 1. The compressibilities of the fluids which damp the pressure variations. 2. The changes in the densities of the fluids or apparent densities of the sand-laden fluids. 3. The flowing friction of the various fluids and mixtures, which is dependent on the flow rates and the condition of the tubing, casing, or wellbore. 4. The non-Newtonian characteristics of a sand-oil mixture and its dependence upon the fluid properties, the concentration of sand, and the mesh size used. 5. The unknown and variable temperatures throughout the fluid column. Because of these reasons it was determined that in order to obtain a more accurate knowledge of the nature of fracturing, the bottom-hole pressure must be measured along with the pressure at the surface during a fracturing treatment. Even with accurate pressure data, a reliable estimate of the nature of fracturing is still dependent upon knowledge of the tectonic conditions. However, the hydraulic pressure on the formation is basic to any approach to a complete analysis. In order to accomplish this objective a system was developed to record the wellhead and bottom-hole pressures simultaneously at the surface. By recording both pressures on a dual pen strip-chart recorder, it was possible to greatly expand the time scale so that rapid pressure variations would be faithfully recorded. By such simultaneous recording, time discrepancies inherent in separate records are eliminated, thus overcoming one of the most difficult problems associated with bottom-hole recording systems. This paper illustrates the results obtained by using this system during six typical fracturing operations. All of these tests were taken in wells that were treated through tubing. By a direct comparison of the wellhead and bottom-hole pressures, the importance of obtaining complete pressure information during a fracturing treatment is emphasized. THE INSTRUMENTATION AND PROCEDURES The bottom-hole pressure measuring instrument consisted of a pressure-sensing element, a telemetering section, and a lead-filled weight or sinker bar. The pressure-sensing element used was an isoelastic Amerada pressure-gauge element. By using an isoelastic element, no temperature compensation was necessary in the tests described, since the temperature was believed to be well below the maximum temperature limit of 270°F. The rotary output shaft of this helical Bourdon tube element was coupled to a precision miniature potentiometer. The rotation of the pressure-gauge shaft thus changed the resistance presented by the potentiometer

By P. B. Baxendell

The appraial of producing properties and profitability ntzalysis of a proposed capital expenditure are based on the same principles. In both problems a projection of future cash income is. cornpared to one or more capital expenditures. Several different methods have been in use either to compute a price to obtain a given earning power on the investment or to compute the earning power which will result from a given capital expenditure. One of these, the "Average Annual Rate of Return" method, computes in a simple manner the ratio of the present value of the future earnings after amortization to the present value of the undepreciated balances of the investment over the life of a project. This method, not well known generally, appears to have some rather unique advantages in reducing the computation work required, eliminating trial-and-error solutions, and providing a more accurate answer when applied to oil industry investments subject to the unit-of-production basis of amortization. Its derivation is given and its versatility demonstrated in the solution of certain everyday investment problems. A number of charts, useful in applying this method to profitability analysis and appraisal work, are provided. The current trend in the market values of producing properties is shown. INTRODUCTION Making sound capital expenditure decisions requires an objective means of measuring the productivity of individual investment proposals. Since the best measure of the economic worth of such proposals is their ability to produce profits, it is common practice to grade proposed capital expenditures according to their annual earning power as a percentage of the outstanding capital. The same principles which govern the determination of the rate of return of proposed capital expenditures also apply generally to the problem of determining the appraisal value or purchase price of income-producing oil and gas properties. Both problems are of prime importance in the producing phase of the oil business, where management is faced daily with decisions to drill or not to drill certain development wells, or with the determination of the appraisal value of producing properties. The common feature in both problems is that a projection of future cash income is compared with a known or estimated capital investment to determine itsiearning power or annual rate of return. In the case of development drilling, the cost of the proposed well can usually be estimated with a fair degree of accuracy and the problem consists of finding the rate of return on the invested capital. In the case of appraising producing properties, on the other hand, the desired rate of return is usually known in advance and the problem consists of determining the purchase price which, for the given income projection, results in the fequired rate of return. Certain accounting procedures common to the oil and gas producing business make these two problems and their solutions somewhat different from corresponding problems in other industries, and, in certain ways, simpler. The main difference is in the amortization policy which, for oil and gas production, is frequently on a unit-of-production basis, compared to the amortization on a time basis used in many other industries. The purpose of this paper is to discuss briefly the various methods currently in use for the measurement of productivity of invested capital in producing properties and, in more detail, the derivation and application of what will be called the "Average Annual Rate of Return Method". This rather interesting and not too well known method has some very definite advantages in the solution of many problems common to the oil industry. For the sake of simplicity, federal income tax considerations have been disregarded in the examples used, since they do not affect the principles involved. The use of the production payment route in the sale or purchase of producing properties, which has been amply covered in many other publications, has also not been included in this analysis. METHODS FOK MEASUKING THE EARNING POWER OF INVESTED CAPITAL, Of the many different methods used to measure the earning power of invested capital, four are applicable to oil or gas production ventures. Depending on whether these four methods utilize one or two interest rates, and whether a fixed amortization pattern is used, they may be classified as follows.

By P. J. Jacquard, C. Jain

Interpreting pressure measurements is one of the fundamental problems in the operation of oil reservoirs. The principal methods and means of study zuhich are currently used are reviewed. Emphasis is placed on the necessity of improving the quality of the information to turn it to the best possible account. One of the important aspects of the problem is the development of a system of automatic interpretation of the pressure measurements. The proposed method aims at this objective: starting from the relation which exists between a local perturbation of permeability and its effect on the velocity potentials in the wells, we determine by successive approximation the modifications to be made to the permeability map by fitting the least squares between the measured pressures and the pressures indicated by the mathematical model. The method has already been successfully employed in the case of heterogeneous reservoirs of radial- circular symmetry. Its application is extended here to the two-dimensional case, and is illustrated by two examples, for which the results are presented. The conditions required for the method to become fully operational are likewise analyzed. I — INTRODUCTION One of the basic problems of production and recovery from oil fields is interpreting pressure measurements made in wells in the single-fluid-phase regime. Simplifying assumptions, for example supposing the reservoir to be homogeneous, make it possible to use more or less simple methods which permit the estimation, from these pressure measurements, of a mean value of the permeability around the wells. Considering the actual heterogeneity of the majority of reservoirs, and the phenomena of interference between wells, these methods are only indicative. Much has been published on the studies of different cases of comparatively simple heterogeneity: some have discussed the radial heterogeneity around a single wel1,l or vertical heterogeneity.2 The results of these works have shown the influence of variations of permeability on the pressure, but unfortunately they are not very useful in practice because they all are concerned with the phenomena around a single well, without interference between wells, and they correspond to relatively simple and theoretical schemes. These studies of reservoirs or parts of reservoirs on a larger scale are made by the electric analyzer or digital model. We define a permeability map and a porosity map, then reproduce the production history of the wells on the wells of the model, and note the corresponding pressures. These pressures are then compared with actuality, and the discrepancies observed are analyzed. From this analysis we deduce the modifications to be made to the maps of permeability and porosity, and repeat until the coincidence between the pressures indicated by the model and the actually observed pressures is considered adequate. We have adjusted the model. Obviously, in this method of investigation, everything depends on the formula which permits the modification of the permeability to approach the adjustment. Considering the complicated nature of the problem, some oversimplified formulas are poorly adapted to reaching a good adjustment. For example, we have shown that the elementary operation of increasing the permeability not far from a producing well to compensate for too low pressures in the well can, in certain cases, express itself by an effect exactly opposite. 3 The project described here is for a system where we begin with the pressure measurements and the several known parameters of the reservoir, and develop the most probable permeability map, taking account of the measurements available and a subdivision of the reservoir fixed a priori. Ideally, this system is conceived as one in which no manual intervention would be necessary. The model simulating the reservoir is only one part of the whole system, and it is neither the longest nor the most complex part. The need to integrate the model into an aggregate of much more extensive processes has led to the adoption of the digital solution, even though a solution combining the digital and the analog is perfectly conceivable. The simulating model is in that case no more

Jan 1, 1966

By K. E. Brown, F. W. Jessen

By utilizing an 8,000-ft experimental field well equipped with 10 gas-lift valves and 10 Maihak pressure recorders, gas-lift tests were conducted with port sizes ranging from 5/16 through I in. The well was equipped to provide accurate means of measuring surface pressures, temperatures, quantity of injection gas and fluid production. The tests were conducted in 2%-in. OD tubing, and the well was making 95 per cent water. A complete evaluation of gas-lift-valve port sizes shows the relationship of per cent recovery, gas-liquid ratios, minimum pressure created at the operating valve and horsepower requirements for each port. The length of time necessary for the fluid in the tubing to reach equilib.rium conditions after each cycle was recorded. Fallback of fluid at depths of 477, 969, 1,685, 2,493 and 4,290 ft was noted. For each port size, pressure loads of 2.50, 300, 350, 400 and 450 psi were lifted with a valve operating at approximately 550 psi at 6,000 ft. Gas-liquid ratios for each load were varied from excess gas to a gas volume per cycle whereby the load failed to reach the surface. Numerous curves are presented in evaluating the accumulated dara. The results show a 1-in. port to be the most efficient under all conditions. The production of intermittent liquid slugs against different-sized surface chokes was evaluated. These tests were conducted from a 7/16-in. ported valve at 4,072 ft. Tests indicate that, when possible, a %-in. in diameter choke or larger should be used at the surface. In the past few years most of the advancement in gas-lift operations has been made in continuous-flow operations. Yet, it is estimated that at least 70 per cent of the wells on gas lift in the United States are of the intermittent type. Since the term "slug flow" is sometimes used in both intermittent- and continuous-flow operations, it would be well to distinguish between the two types of flow. Continuous-flow gas lift is defined as a method whereby the fluids are produced at a continuous rate at the surface. This generally requires a continuous injection of gas through a surface choke; however, various other control devices sometimes are installed to eliminate freezing, to shut-off gas during natural flow periods, etc. The actual flow of fluids in the tubing may be of the slug type (one of many flow patterns known to exist in continuous flow). Intermittent flow is defined as a method of gas lift whereby the liquid is produced in separate piston-type slugs. Perhaps this type of flow could best be thought of as a ballistic-type flow where the liquid leaves bottom as a piston, propelled by a slug of expanding gas. Gas generally is injected through some type of control at the surface at predetermined intervals. However, the valve may have characteristics whereby gas can be injected through a small choke and still result in a ballistic-type flow. The purpose of the experimental work was to evaluate the most efficient port size to be used on the operating valve for the ballistic type of lift and, in addition, to establish the importance of utilizing a surface choke large enough to allow slugs to be produced without detrimental effects. This work is part of a compre- hensive study of both intermittent-and continuous-flow gas lift, representing a joint project conducted by the Ohio Oil Co., the Sun Oil Co., Otis Engineering Corp, and The U. of Texas. The problem of evaluating port sizes has been given little previous attention. Some work undoubtedly has been done which has not been published to date. Some tests were conducted when the wireline, mechanically-opened valve (Nixon) first came on the market. This valve was capable of utilizing full tubing area as its port size. It is known that this was a very efficient valve, but to the authors' knowledge the results of tests have never been published. EXPERIMENTAL EQUIPMENT These tests were conducted on an actual field well, the Ohio-Sun Unit Well No. 2-E, in the North Markham-North Bay City field, Matagorda County, Tex. The well incorporated 23/8-in. OD tubing and produced 95 per cent water. Since the running of equipment was to be quite elaborate and expensive, a well was selected in which both intermittent- and continuous-flow tests could be conducted. This particular well was capable of producing in excess of 1,000 B/D of liquid (95 per cent salt water), yet with a 3/64-in. in diameter bottom-hole choke, production was controlled to 82 B/D. Most of the intermittent tests were conducted at this low rate. Figs. 1 and 2 show all the surface and down-hole equipment. As can be seen, every attempt was made to insure that ample equipment was available for reliable testing procedures. Fig. 1 shows the surface testing equipment. The input gas was controlled first by a regulator, then

By F. C. Pittman, D. W. Harriman, J. C. St. John

This paper mentions briefly the history of hydraulic jetting as applied to perforating and fracture initiation. It points out the advantages of hydraulic perforation and undercutting as an aid for creating a fracture at the point desired rather than depending upon the weakest point in the formation for breakdown. It describes early experimental work with jet nozzles in search of better nozzle materials. The effect of splash-back damage and its subsequent influence on jet body and tool design during this work is discussed. A series of cutting-rate curves for jets cutting steel and steel-cement-formation combinations is presented to show the effect of hydrostatic head and the point of diminishing returns with respect to cutting time. There is a series of photographs showing various types of rock formation in which perforation and undercutting tests were made. These stones were drilled and the casing cemented in place as in an actual well. The casing was perforated and circularly cut as if preparing for a fracturing job. The conclusion reached in the paper is that hydraulic jetting with sand-laden fluid can be used for perforating and undercutting casing, cement and formation rock for the intended purpose of inducing the formation to fracture at a desired point. INTRODUCTION Hydraulic jetting as a means of cleaning a formation during acidizing has been used for many years. The acid-jet gun was used to clean formation and for drilling cement from casing with acid. This tool was dropped to a seating ring installed on the tubing and could be retrieved by reverse circulation or wire line. In this process, the fluids were directed against the formation to clean and penetrate beyond the mud-damaged area. After the development of the hydraulic fracturing process, interest in jetting the formation with abrasive-laden fluid was renewed. The cutting action of abrasive fluid on pumping equipment, which is a well known problem, has been utilized to perforate and undercut casing, tubing and formation. In this process, surface areas are provided in the formation on which the frac- turing pressures may work to produce a fracture at the location desired. EQUIPMENT The tools used consist of bodies containing two, three or four jets in a single horizontal plane equally spaced around the circumference. The body is threaded to the end of a string of tubing and run into the well. In addition, an expendable tool is available that may be left in the hole after perforating and produced through until necessary to remove the tubing. The bottom of each tool is equipped with a ball-type back-pressure valve. The ball can be reversed to the surface and recovered. This allows reverse circulation so that loose sand which accumulated below the tool while jetting may be removed before the fracturing job. The present jetting tools are of such length that, when screwed together, the jets fall on 12-in. spacing. ANALYSIS OF THE PROBLEM Early work with nozzles indicated that hardened steel was not a suitable material for jets and that more durable material would be required. Ceramics were tried and found to be superior to steel but still too shortlived for most applications. Tungsten carbide, which was tried and found to be the best material available, is now being used for jet nozzles. Analysis of the problems presented by this process indicated that the following information was needed. 1. The effect of submergence on a jet stream and the effect of submergence on the cutting rate of a jet stream. 2. The cutting rate and depth of a jet stream in steel. 3. The cutting rate in various formations and point of diminishing returns. 4. Size of hole or slot cut in a pipe by a given jet. 5. Fluids and sands used. 6. The flow of various weight fluids through the jet nozzle and the discharge coefficients. 7. The type cut formed in the formation by the jet stream. 8. The stretch and contraction of tubing due to temperature and pressure. The cutting effect of a jet stream on a target in the atmosphere is rapid and spectacular as most of the

By L. C. Kern

This paper presents information on the use of a new propping agent (malleable aluminum particles) which has been used successfully for producing high-conductivity fractures. The conductivity of a packed fracture depends on the width of the fracture as well as the permeability of the propping material. It is significant that the flow capacity of a propped crack is often increased many fold by propping the crack with a sparse distribution of particles. However, the flow capacity of a sparsely propped crack can be limited by two phenomena: (I) crushing of the propping particles, and (2) embedment of the propping particles in the formation walls. Malleable aluminum particles exhibit interesting properties which tend to overcome these limitations. As high loads are applied to the particles they will deform slightly, rather than shattering. The deformation results in a greater bearing area against the formation wall. This reduces the stress on the particle and reduces particle penetration into the formation. The behavior of aluminum particles under load and the bearing capacities of serveral formation rocks have been measured in the laboratory. By properly using these data, as explained in this paper, the flow capacities of aluminum-propped cracks can be calculated for a variety of conditions. Aluminum particles have been used successfully in the field to prop fractures. Where high-conductivity fractures were needed, the aluminum-propped fractures have given greater well stimulation than could have been expected for conventional fracturing processes. INTRODUCTION The purpose of a hydraulic fracture treatment is to create a conductive channel from the wellbore out into the oil or gas formation. The word conductive is emphasized because we believe that the fracture conductivity (flow capacity) is one of the most important factors influencing fracturing results. Previous papers have pointed out the additional well stimulation that can sometimes be achieved by increasing fracture conductivity. Several years ago, we investigated in some detail the effect of fracture conductivity on productivity increases to be expeced from vertical fractures. Both electrical analog and theoretical studies of unsteady-state flow behavior were made. A discussion of the electrical analog equipment and some of the results of the study were given in a previous paper' by Dyes, Kemp and Caudle. Further details were given recently by McGuire and Sikora.5 Fig. 1 shows the remarkable influence of relative fracture flow capacity and length on well stimulation. Briefly, the study indicates the following. 1. High-permeability formations require high-conductivity cracks for best results. 2. The longer the crack, the higher the fracture conductivity required for best results. 3. If the conductivity of the crack is very large compared to the formation (i.e., flow is not being limited by crack conductivity), then the longer the fracture, the better will be the results. Judging from recently published articles,1,314 there is current interest in methods for obtaining high fracture conductivities. Hence, we would like to present in this paper a discussion of a new fracture propping process (use of aluminum particle) which we have used successfully to obtain highly conductive fractures. There are several factors which influence the conductivity of a propped crack. Conventional fracturing techniques frequently result in a crack completely packed with fracturing sand. For such conditions, the crack conductivity is the product of the width of the packed fracture and the permeability of the propping material. It is significant that a large increase in conductivity sometimes can be obtained by propping with particles which are distributed sparsely (less than a

By A. Romero-Juarez

This paper is concerned with the effect of propping-agent concentration on flow capacity of a fracture in the case in which there is embedment of the propping agent. Previous published studies have shown definitely that there is a relationship between fracture flow capacity and prop ping-agent concentration, and it has been shown that the theoretical results are confirmed by laboratory experiments. The problem of directly finding sand concentration for maximum flow capacity of a sand-propped fracture is solved, and formulas and charts are given to obtain this concentration under various conditions of effective overburden pressure, medium sand-grain diameter and rock properties. It is shown that, for the same effective overburden pressure and the same rock characteristics, optimum sand concentration in pounds per gallon does not depend on medium sand diameter. For conditions met in bydraulic fracturing operations, it is found that sand concentration in grains per square inch for maximum flow capacity varies within a wide range of values; this indicates the convenience of using data of fracturing pressure and rock characteristics for calculating sand concentration in order to achieve the best results in fracture treatments. INTRODUCTION It has been pointed out in the published literature1 that one important factor controls the success of a hydraulic fracturing operation — the propping of the fracture. The main effect of the propping agent is to hold the fracture open by means of the reaction forces that oppose the pressure due to the overburden. It is assumed in this paper that the propping agent is sand, that the grains are spherical and uniform in size, and that this sand is distributed in a monolayer in the fracture. The existence of a sand concentration value for maximum fracture flow capacity has been recognized since the publication of one of the first studies on the subject.2 In the reference cited, flow capacity was assumed to be proportional to the cube of the fracture volume per square inch not filled by sand. The obtained experimental curves relating to flow capacity and sand concentration had the same appearance as the curves obtained with the afore-mentioned assumption. Recent work3 has shown that fracture permeability, in the case of a monolayer, can be calculated accurately by means of a modified Kozeny-Cacman equation; thus, it can be shown that fracture pqmeability is a function of free volume in the fracture and of the rock and sand wet surfaces. The flow capacity of a fracture is dependent on the permeability of the fracture and on the fracture width. If all excessive quantity of sand is present in the fracture, its width may be large but its permeability i:; low due to the greater flow resistance; too few grains of sand per square inch are present in the fracture, sand embedment in the rock is greater and the width becomes small enough to appreciably decrease the rate of flow. To determine optimum conditions of flow, therefore, it is necessary to know the dependence of fracture width on density or concentration of propping agent. This relation is given in a study4 in which the approach to embedment is similar to the one made in a penetration hardness test of metal. With the equacions presented by Darin and Huitt,3 the number of sand grains per square inch that results in maxirnum fracture capacity can be determined graphically by plotting fracture capacity vs sand concentration. Since the relationship between fracture capacity and sand concentration may be considered known, one is led to formulate the analytical problem of directly determining sand concentration for maximum fracture flow capacity, in order to study the effect of the various quantities that come into the process. The solution of this problem appears to be interesting both from the viewpoint of fluid mechanics and from the practical viewpoint of oil production in hydraulic fracturing treatments. EQUATION FOR FRACTURE FLOW CAPACITY It can be shown3 that the fracture flow capacity of a monolayer is given by the following expression,

By James N. Brentz

This paper deals briefly with the problem of efficiently selecting the most cost effective haulage truck. Problems and factors are identified that effect productivity and operating cost. Despite the sophistication of computerized vehicle simulation programs, there is a wide disparity in accuracy and methodology, particularly in dealing with the various elements of cost.

Jan 1, 1984

By George J. Allen, Laura A. Allen

Introduction This section of the text presents a general review of the different types of concentrate marketing contracts. Too often the marketing strategy is ignored in the design phase of the project and the producer is left to the mercy of the buyer. Many items such as concentrate grade, impurity levels and moisture content of the concentrate my enhance, or severely restrict the producers ability to make a profit it. Close attention should be paid to the design of the concentrator which can improve the quality of the concentrates, thus the ability to increase the rider of potential buyers can be enhanced. Difficult at best, is the position of the miner who only has one outlet available for its production. Obviously, the trade offs must be evaluated. For example, concentrate grade vs recovery and grind/filtering capacity vs moisture of the concentrate all must be weighted against freight cost to a potential buyer. In addition, the above considerations must be weighed against the capital cost to the miner. This chapter is intended to highlight important articles that are included in short and long term agreements and to give a new miner/producer some insight into hat my or my not add value to the product. Unless the miner sells the product directly to a consumer such as a gold, or silver producer, or to a large enough operation that has a totally intergrated system to make a finished product, most miners are forced to sell to buyers who ultimately will refine and market the product. Types of Contract Agreements There are many types of contract agreements just as there are colors in the rainbow, however, most contracts fall into three basic categories. (1) Smelter Schedules: Designed for the small producer, the odd lot of concentrate, smelter flux and precious metal ore. Albeit custom smelters are becoming fever by the day, because of pollution control requirements and financial difficulties, most remaining custom smelters have a smelter schedule. A smelter schedule is a posted list of charges and conditions that the smelter will buy material from a seller. Smelter schedules exist for copper, lead, zinc, silver and gold (Handbook for Small Mining Enterprises, Montana Bureau of Mines). (2) Short Term Custom Contracts: Large mine producers frequently use Short Term Contracts where the seller has the buyer frame a contract that is tailored to the sellers’ production. The short term contract my be as long as one year. A spot sale qualifes as a

Jan 1, 1986

By B. W. Steele

"Dofasco began operations in 1912 as a steel foundry located in Hamilton, Ontario. Today, Dofasco is a fully integrated mill that manufactures hot rolled, cold rolled, galvanized and tinplate steels. Customers include the automotive, construction, tubular, manufacturing, appliance, packaging and steel ser-vice centre industries. Raw steel production and purchased semi-finished steel processed in1994 was 3.5 million net tonnes. Dofasco employs 7300 people at its Hamilton facility.Environmental management at Dofasco is guided by its environment policy and associated commitments. This paper discusses Dofasco’s responsibility for its products as it relates to these commitments. Dofasco is com-mitted to:n the principles of sustainable development that require that activities be conducted in a manner that provides for the present without compromising the ability of future generations to meet their needs. These principles will be integrated into product design, manufacturing and business planning;n managing renewable and non-renewable resources through the responsible application of reduce, reuse, and recycle principles;n minimizing any potential impact of its operations and products on the environment, employees, customers and the community;n continuous improvement of the effectiveness and integrity of our environmental management systems;n developing understanding among all employees about their responsibilities, and assigning the necessary authority; andn meeting the standards set by relevant legislation and international agreements through participation with governments and the diligent application of economically feasible and scientifically sound methods and technologies."

Jan 1, 1996

By Frank C. Greene

The year 1941 was uneventful in oil and gas development in Missouri. No new pools were opened and several areas with promising structures, in the northwestern part of the state, were disappointing when drilled. In looking for an explanation of these failures, it is suggested that it will be necessary to find areas in which the lower beds of the Mississippian are upfolded, in order to obtain production in northwestern Missouri. To do this, geophysical exploration or test drilling far enough into the Mississippian beds to get cores or cuttings of definitely established age appear to be the best methods. Although not leading to new production, drilling in Missouri established two new state records, one for depth and another for the amount of rotary drilling. An important well† in sec. 24, T. 19 N., R. 11 E., Pemiscot County, in the southeastern corner of the state, was drilled with a rotary to 4740 ft., several hundred feet deeper than any previous hole. The total footage drilled by rotary rigs of various types was 31,135 ft. and that by cable tools, 29,166 feet. The total number of completions was 85, of which 18 were gas wells with an initial open-flow capacity of 12,528,000 cu. ft., and 67 were dry holes. Of the latter, 19 were drilled into Mississippian or older formations. Table I gives a summary of activities by counties.

Jan 1, 1942

By Frank C. Greene

The year 1941 was uneventful in oil and gas development in Missouri. No new pools were opened and several areas with promising structures, in the northwestern part of the state, were disappointing when drilled. In looking for an explanation of these failures, it is suggested that it will be necessary to find areas in which the lower beds of the Mississippian are upfolded, in order to obtain production in northwestern Missouri. To do this, geophysical exploration or test drilling far enough into the Mississippian beds to get cores or cuttings of definitely established age appear to be the best methods. Although not leading to new production, drilling in Missouri established two new state records, one for depth and another for the amount of rotary drilling. An important well† in sec. 24, T. 19 N., R. 11 E., Pemiscot County, in the southeastern corner of the state, was drilled with a rotary to 4740 ft., several hundred feet deeper than any previous hole. The total footage drilled by rotary rigs of various types was 31,135 ft. and that by cable tools, 29,166 feet. The total number of completions was 85, of which 18 were gas wells with an initial open-flow capacity of 12,528,000 cu. ft., and 67 were dry holes. Of the latter, 19 were drilled into Mississippian or older formations. Table I gives a summary of activities by counties.

Jan 1, 1942

By L. E. Porter, H. P. Hassel

The state of California produced 310,-996,696 bbl. of oil and about 415,832,000 M cu. ft. of gas in 1944. Such oil production represented 18.5 per cent of the nation's production, as compared with 19 per cent in 1943 ,The tremendous demand placed upon the California fields is indicated by the monthly production in 1944, as follows: Month Barrels per Day Jan................... 809,262 Feb.................. 820,712 Mar.................. 824,592 .4pr ................. 829,973 May.................. 832,068 June.................. 846,038 July.................. 849,231 Aug.................. 858,932 Sept.................. 885,823 Oct................... 877,667 Nov.................. 876,613 Dec.................. 883,847 In all, 2100 wells in proved areas and 269 wildcats were drilled in California during the year 1944. At the end of the year, approximately 270 wells were drilling in the state, as compared with 156 wells at the same time in the preceding year. Nine new fields or new zone discoveries were made during the year, which, according to best estimates, will contribute some 77,000,000 bbl. of new reserves; in addition, the extensions of old fields will increase the new reserves about 165,000,000 bbl., or a combined total, through dis- coveries of new fields, zones, and extensions, of 242,000,000 bbl., offsetting to the extent of about 78 per cent the total oil produced during the year. Geographically, the reserves from these new field and zone discoveries and extensions are distributed as follows: Per Cent San Joaquin Valley........ 72 Coast Area............... 24 Los Angeles Basin Fields. . . 4 100 The state's reserves of crude oil at the end of the year have been estimated to be distributed as follows: The outstanding development project for the year was that of the United States Navy in the Naval Petroleum Reserve No. I, Elk Hills field. During the year, 115 wells were completed in this field, and at the close of the year an average of 19 strings of tools were drilling. This program is being jointly conducted by the Standard Oil Co. of California with the Navy and is designed to increase the production of Naval Petroleum Reserves from approxi-

Jan 1, 1945

By Theron Wasson

The oil and gas fields of Michigan that have been under development since 1925 are in an area that extends across the middle of the lower peninsula from northeast to southwest, a distance of about 200 miles, and with a width of about 80 miles. In 19 years 70 fields have been discovered. Most of these are relatively small when compared with other oil-producing areas. This is borne out by the fact that since the first wells were drilled these fields have produced a total of only 204,000,000 bbl. However, Michigan is still maintaining its production, for during the past five years the annual production has remained fairly constant at approximately 20,000,000 bbl. Production for 1943, as reported by the Bureau of Mines, was 20,682,000 barrels. Roughly, one third oi Michigan's production in 1943 came from the Reed City field, which was discovered in 1941. During the year, 237 oil wells were completed in Michigan in 1943. The decrease of 56 from the 1942 total is probably due to the continuance of Government regulations requiring a 40-acre spacing pattern over most of the state. Fig. I shows the principal oil and gas fields of Michigan, and the columnar section, Fig. 2, shows the principal producing horizons in relation to the section drilled. The data of Table I and Table 2 have been carefully checked with previous reports to eliminate errors. Six new producing areas were discovered during 1943 and five areas discovered in 1942 were developed during the year. Both the new discoveries and the 1942 discoveries that were developed appear to be small and relatively unimportant. Goodwell Field.—The best discovery of the year is the Goodwell field, T. 14 N., R. 11 W., Goodwell township, Newaygo County. This small structure was located by core testing done by The Pure Oil Co. in 1942 and early 1943. The first producing well, C. R. Harris No. I, was completed on July 5, 1943, ill the Traverse limestone at a total depth of 2742 ft., with ail estimated potential of 1100 bbl. per day. By the end of the year, 18 wells had been completed in this field and approximately 281,000 bbl. of oil produced. The field operated under proration of 262 bbl. per day per well from Oct. I to Dec. I; 150 bbl. per day per well after that date. Woodville Field.—The small Woodville pool, T. 15 N., R. 11 W., 3 miles north of the Goodwell field, was discovered by core testing by the Ohio Oil Co. The discovery well was completed on May 5, 1943, flowing 650 bbl. of fluid, including 18 per cent salt water the first 18 hr., from the Traverse limestone at a depth of 2810 to 2815 ft. Seven wells had been completed by the end of the year and 67,000 bbl. of oil had been produced. Development is now practically at a standstill because further drilling does not aDDear economically iustified.

Jan 1, 1944